ML20149F319
| ML20149F319 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 07/16/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20149F300 | List: |
| References | |
| 50-282-97-08, 50-282-97-8, 50-306-97-08, 50-306-97-8, NUDOCS 9707220149 | |
| Download: ML20149F319 (38) | |
See also: IR 05000282/1997008
Text
..
t
U.S. NUCLEAR REGULATORY COMMISSION
REGION lli
Docket Nos:
50-282: 50-306
License Nos:
Report No:
50-282/97008(DRS); 50-306/97008(DRS)
Licensee:
Northern States Power Company
Facility:
Prairie Island Nuclear Generating Plant
Location:
1717 Wakonade Drive East
j
Welch, MN 55089
i
Dates:
April 14 - June 13,1997
Inspectors:
J. Guzman, Team Leader
V. Patricia Lougheed, inspector
J. Neisler, inspector
T. Tella, Inspector
)
G. O'Dwyer, inspector -
F. Burrows, inspector (NRR)
P. Cataldo, Operations Examiner
1
Approved by:
M. A. Ring, Chief, Lead Engineers Branch
Division of Reactor Safety
l
.)
i
,
lll
9707220149 970716
>
ADOCK 05000282
!
'
G
pm
.
s
l
%
EXECUTIVE SUMMARY
1
Prairie Island Nuclear Generating Plant, Units 1 & 2
NRC Inspection Report 50-282/97008, 50-306/97008
i
This report includes the results of an announced System Operational Performance
]
Inspection by regional inspectors and NRR of plant operations, maintenance, and
engineering for the auxiliary feedwater (AFW) system and parts of the control room
ventilation and safeguards chilled water systems.
Operations
Operations' performance during an observed startup of Unit 1 was good
'
(Section 01.1).
The emergency operating, operating, and alarm response procedures provided
acceptable instructions for operating the AFW system during all aspects of plant
operation (Section 03.1). While overall, the checklists and drawings reviewed were
acceptable, the inspectors identified that AFW pre-start checklists did not reflect
the current plant configuration (Section O3.2).
While the operators' performance of the AFW surveillance was considered good,
the operating shift did not identify, prior to commencing the surveillance, that
current plant conditions would have resulted in the inability to perform specific
sections within the special procedure (Section 04.1).
The inspectors concluded that the control room operators were very knowledgeable
concerning the recent AFW system modifications (Section 04.2) and observed
'
operations training concerning the recent AFW pump modifications was considered
good (Section 05.1).
Maintenance
With a few exceptions, maintenance was being performed according to approved
procedures. Work packages were well planned and contained adequato instructions
(Section M1.1).
Overall, the observed material condition of the plant was good (Section M2).
Maintenance procedures were technically adequate and sufficiently detailed to
perform the required maintenance and inspection tasks and had the necessary
provisions to identify and evaluate deficiencies. The procedures reviewed also
satisfied or exceeded vendor recommendations (Section M3.1).
Based on examination of available maintenance history, performance indicators, and
trending data, plant components were being appropriately maintained to provide
assurance of operating when called upon (Section M8.1).
2
o
O
6
Enaineerina
The AFW pump surveillance test procedure acceptance criteria could have allowed
the AFW pumps to degrade below design requirements. This was an appamnt
violation of test control requirements. The latest test results were close to tue
design requirement values (Section E1.1).
The failure to accomplish corrective action from 1991 of reviewing safety related
pump test acceptance criteria was an apparent violation of corrective action
requirements (Section E1.1).
The failure to correct the inaccurate 400 gpm AFW flow rate in the USAR, despite
two opportunities to do so in December 1993 and 1995, was considered an
apparent violation of Accuracy of Information requirements and also an apparent
violation of Maintenance of Records requirements (Section E1.2).
i
The failure to report that the plant was outside its design basis when it was
determined that the main feedwater line rupture analysis used a 400 gpm AFW
l
flowrate was considered an apparent violation of Reportability requirements. The
failure to perform a safety evaluation for this defacto change to the facility as
described in the USAR and to verify that no unreviewed safety question existed
was considered an apparent violation of 10 CFR 50.59 requirements (Section E1.2).
Design changes and modifications reviewed, including documentatic.. revisions and
post-modification testing, for the AFW system were acceptable (Section E1.3).
The basis for the unfiltered inleakage rate assumption in the control room
habitability dose analysis was considered weak because it had not been validated
through testing of the control room envelope or testing of the isolation dampers
(Section E1.4).
While many of the calculations reviewed were considered acceptable, the
inspectors noted weaknesses in the calculation verification program based upon the
errors found in the mechanical calculations, some of which were introduced during
the verification process. These errors were considered a violation of design control
requirements (Section E3.1).
Identification of discrepancies in system drawings indicated a weakness in the
drawing control program to assure plant drawings accurately reflect plant status
(Section E3.4).
The Safety Audit Committee and Operations Committee meetings fulfilled their
Technical Specification requirements and provided the necessary oversight function
for which they were intended (Section E7.1).
The licensee's corrective actions for cable trays not meeting separation criteria
were inadequate in that it took over 4 years to determine reportability and
additional cable trays were not identified until NRC inspectors noted them. This
was considered a violation of corrective action requirements (Section E8.4).
3
-.
( -
. - -
..
-
. _ = -
- .
-
.--
-
I
'
Report Details
1. ODerations
01
Conduct of Operations
01.1 Observation of Unit 1 Startuo
a.
Inspection Scope
On April 27,1997, inspectors observed operator actions during the startup of
Unit 1. The plant startup was conducted using procedure 1C1.2 " UNIT 1
STARTUP PROCEDURE," Revision 16.
b.
Observations and Findinas
,
While overall the operator actions observed by the inspectors during the startup
.
were good, an issue with control of steam generator (SG) level was noted.
1
Temporary Memo TMA-1997-0059 added Limitation 4.6 " Steam Generator Level"
l
to the Unit 1 startup procedure,1C1.2, which stated: "WHEN RCS temperature is
greater than 350 F AND reactor power is less than 5%, THEN do NOT exceed
38% steam generator narrow range level." However, during the transition from
auxiliary feedwater tc main feedwater, steam generator water level exceeded the
38% narrow range level on the 11 SG for approximately four minutes. Operators
2
responded appropriately to maintain steam generator level below 40%. In response
k
.
to this issue, the licensee formed a multi-disciplined task force to review the
<
'
restrictions and determine potential actions required or available to increase the
limited margin.
c.
Conclusions
Operations' performance during the observed startup of Unit 1 was good.
However, the inspectors noted a weakness in operators not being able to maintain
steam generator level below an administratively imposed limit.
,
03
Operations Procedures and Documentation
i
j
03.1 Review of Operatina Procedures
a.
Inspection Scope
The inspectors reviewed the adequacy of emergency operating procedures (EOPs),
'
operating procedures (ops), and alarm response procedures (ARPs) for the AFW
system, as listed at the end of this report, for event sequences requiring AFW
initiation.
.
4
a
,
4
b.
Observations and Findinas
.
The inspectors observed that recent AFW modifications were incorporated into the
ops and ARPs, both through the use of procedure changes or the facility's
temporary memo process.
The inspectors reviewed the ARPs located in the simulator at the Prairie Island
Nuclear Generating Plant (PINGP) Training Center, and noted that the ARPs did not
reflect the current condition of the simulator. Specifically, ARP C47010-0205, "11
TD AFWP LO OR DISCH PRESS TRIP," Revision 30, indicated a setpoint of < 200
PSIG for initiating the " Discharge Pressure Low" annunciator and alarm. The
inspectors determined through Simulator Change 971-002, dated March 17,1997,
that the setpoint for the AFW low discharge trip had been changed to 800 PSIG
prior to testing during the weeks of February 9 and 16,1997. The simulator ARP
was subsequently updated on April 29,1997.
c.
Conclusions
,
The inspectors concluded that while some delay occurred in updating ARPs in the
simulator, the EOP, OP, and ARP procedures provided acceptable instructions for
operating the AFW system during all aspects of plant operation.
03.2 Review of AFW System Prestart Checklists
a.
Inspection Scone
The inspectors reviewed previously completed checklists on both Unit 1 and Unit 2
auxiliary feedwater systems, and performed a walkdown with checklists and
system flow drawings,
b.
Observations and Findinas
During a walkdown on the AFW system using the prestart checklist, C28-2 (Unit 1,
Revision 34) and C28-7 (Unit 2, Revision 37), four valves were discovered in mid-
position, that is, 45 open, contrary to the required "OPEN" position detailed on the
checklists. in addition, operations personnel (including shift managers) indicated
the valves had been in the " throttled" position since the modified piping system
was installed in 1994.
The four valves in question, AF-39-1(3) and 2AF-39-1(3), are suction vent loop see
drain valves. The valves maintain a continuous flow of condensate water through
the suction piping of the AFW pumps to flush possible cooling water leakage past
the cooling water system suction supply motor-operated isolation valves. The four
valves are throttled to limit the condensate inventory loss, but are also adjusted to
maintain weekly sodium samples less than 1 part per billion (ppb).
Also, a review of previous checklists performed on both units indicated that the
previous checklists either incorrectly documented the valves as OPEN and not
THROTTLED or the checklists were crossed out and initialed to indicate " throttled."
5
7
-
.
-__
-_
_
__
.
_
o
While the safety consequences of the valves' position was negligible, the checklist
did not reflect the current plant configuration, and operators had not identified this
condition on a number of previous checklists. The inspectors considered it a
weakness that plant procedure reviews and operator performance did not identify
the need for a procedure deviation in excess of two years, the approximate time the
piping had been installed in the system, in response, the licensee initiated a
procedure submittal form to formally change the required " STATUS" position of the
drain ve.tves located on the checklists,
c.
- Conclusions
While overall, the checklists and drawings reviewed were acceptable, the inspectors
identified that AFW pre-start checklists did not reflect the current plant
'
configuration, and noted that operators had not identified this condition on a
number of previous checklists. This was considered a weakness.
04
Operations Staff Knowledge and Performance
'
04.1 AFW Operability Surveillance Test
a.
Inspection Scope
The inspectors witnessed the operating shift crew perform a post-modification
operability test on the Unit 1 turbine-driven auxiliary feedwater pump (TDAFW)
following a recent modification to the AFW system, and prior to the Unit 1 startup.
3
b.
Observations and Findinas
During performance of surveillance procedure (SP) 1102,"11 Turbine-Driven
Auxiliary Feedwater Pump Test," Revision 58, the inspectors observed the
operators stationed locally at the 11 TDAFW pump read through the procedure
steps prior to the performance of each step required by the surveillance. The
inspectors observed good communication between operators in the control room
and locally in the AFW pump room. However, the inspectors observed a number of
procedure errors and procedure steps not applicable for the plant condition
identified by the operating crew while the test was being performed.
Specifically: (1) Step 7.2.3 was identified as a procedure error for referencing
" steps 5.3.2.A and 5.3.2.B" of C28.1; the correct reference was 1C28.1,
Section 5.6; (2) Step 7.2.5 was identified as a procedure error for referericing
C28.1, which does not exist; (3) Step 7.32.2 was not performed because the test
was normally performed at 100% power with the 12 motor-driven AFW pump
(MDAFW) idle. Plant conditions at the time of the test had the 12 MDAFW pump
running for control of steam generator water level, and the step could not be
completed, in addition, the " CAUTION" statement immediately prior to Step 7.32.2
identified the 12 MDAFW pump as "lDLE" for the four steps within Section 7.32.2;
(4) Steps 7.19 and 7.20 could not be completed due to the plant conditions present
at the time of the test, namely, the other train of AFW was inservice and the steam
generator blowdown would remain inservice throughout the performance of
6
,
.
.
. .
__.
_ __
__
_
- . _ . __
Q
SP 1102. The operations crew was able to address these discrepancies and
<
successfully complete the test.
These procedure issues were considered a weakness as the operators should have
,
j
identified, prior to commencing the surveillance, that current plant conditions would ~
have resulted in the inability to perform specific sections within the special
j
procedure, in response, the licensee stated that the procedure discrepancies were
noted by the previous operating shift but the shift turnover was inadequate.
.
l
c.
Conclusions
'
While the operators' performance of the AFW surveillance was considered good,
the operating shif t did not identify, prior to commencing the surveillance, that
current plant conditions would have resulted in the inability to perform specific
sections within the procedure.
,
04.2 Review of Operations Staff Knowledae via Questionina of Operations Personnel
Reaardina The Auxiliary Feedwater System (AFW)
a.
Insoection Scope
The inspectors randomly questioned on-shift personnel to determine their level of
knowledge regarding the AFW system, including the recent AFW system
modification, 96AF01, "AFW PUMP RUNOUT PROTECTION."
b.
Observations and Findinas
The inspectors questioned on-shift personnel from different operating crews,
focusing on specific details of the modification relating to control room switch
positions and the associated TDAFW pump trips. Each operator responded with
answers consistent with the AFW modification.
In addition, various on-shift personnel were questioned on procedures developed to
monitor the AFW pump discharge piping during each shift. The procedures were
developed to assist in the detection of backleakage of steam generator water
through system check valves, which could lead to steam binding of the AFW
pumps. Each operator was knowledgeable of the steam binding issue and the
requirement for AFW pump discharge piping monitoring during each shift.
c.
Conciusions
Based on sample interviews, the inspectors concluded that the control room
operators were very knowledgeable concerning the recent AFW system
modifications.
7
_
.
_
_ _
-
.
.
_ _ _ . .
05
Operations Staff Training and Qualification
05.1 Operator Trainina on the Auxiliary Feedwater System (AFW)
.
a.
Ir.spection Scooe
The inspectors observed on-shift training and licensed operator requalification
training to determine the adequacy of training on the AFW system.
b.
, Observations and Findinas
,
The inspectors observed on-shift training conducted in tFc main control room by the
applicable shift managers regarding the recent AFW modification to protect against
AFW pump runout. The training was administered to all crews over a two-week
period, and detailed the major changes to the AFW pump operational logic. The
observed training was considered good.
Additionally, the inspectors observed a licensed operator requalification training
session. Included in the training was a discussion of the recent AFW pump runout
protection modification and other AFW operationalissues. The instructor detailed
the major changes to the AFW pump operational logic incorporated by the
modification. Good feedback was observed from the operators concerning recent
changes to the unit startup operating procedure, C1.2, which limits steam
generator water level during certain plant conditions.
$
<
c.
Conclusions
The inspectors concluded that operations training concerning the recent AFW pump
modifications was good. This conclusion was supported by the results of random
questioning of control room operators detailed in Section 04.2.
11. Maintenance
M1
Conduct of Maintenance
_ aintenance Work Observed
M
M 1.1
a.
Inspection Scqge
The team observed maintenance and surveillance work activities involving selected
. plant equipment. Maintenance and surveillance activities observed and reviewed
are listed at the conclusion to this report.
b.
Observations and Findinas
.
The observed instrumentation and controls (l&C) and electrical maintenance and
surveillance work activities were adequately performed. The procedures contained
necessary acceptance criteria. The surveillance results were acceptable. The
measuring and test equipment used were noted to be in calibration. The l&C
8
i
_ _ _ _ _ _ _ _ . _
.-
,
.
f
.
.
.
.
I
technicians and the maintenance craft were experienced and knowledgeable in the
- '
areas observed.
>
Work order packages for electrical, instrumentation, and mechanical related work
appeared to be well planned and included sufficient instructions to assure work was
accomplished according to procedure. Tagging instructions were clearly noted in
[
the work packages, in addition, quality verification hold points were identified.
'
Post-maintenance testing requirements and responsibility for conducting the test
!
were included in the procedure, when applicable.
Work Schedulina Weaknesses
During the performance of the diesel generator (DS) 18 month preventive
i
maintenance activities, the team noted that the I&C, electrical, and mechanical test
_ procedures were being performed simultaneously. With 3 procedures causing
alarms in the D5 control room, there was confusion as to which procedure was
causing the alarm. This was most evident while the l&C team and the electrical
relay team were both causing numerous lockout relay actuation alarms that resulted
"
in workers from each team unsure of which team had caused the alarm. The
licensee recognized the potential for coordination errors and revised the testing,
c.
Conclusions
!
The team concluded that, with a few exceptions, maintenance was being
performed according to approved procedures and that work pack'.ges were well
_
. planned and contained adequate instructions.
+
M2
Material Condition of Plant
i
a,
' Inspection Scope
The team walked down selected areas of the plant to review the material condition.
b,
Observations and Findinas
Tha team walked down accessible areas of the AFW system, control room (CR)
l
ventilation system, and the diesel generator rooms to review the material condition
of the equipment. Equipmont material condition, and housekeeping were good in
]
almost all cases. Several minor discrepancies were brought to the licensee's
i
~
attention and were corrected.
-
The inspectors noted during walkdowns that the licensee had installed yellow-
colored plastic chains on the front of many of the plant's switchgear and motor
control center cabinets as bump hazard warning barriers. These barriers served to
remind breaker maintenance crews and other plant personnel that the electrical
equipment was energized and that a bump to the cabinet could cause a device or
relay to trip. The inspectors considered this to be a simple yet innovative design
feature to enhance safety and prevent undesired breaker trips.
9
._
.
.
.
- .
.
-
.
..
---
.
. - - :
_ _ .
.
c.
Conclusions
The team concluded that, overall, the material condition of the plant observed was
good.
M3
Maintenance Procedures and Documentation
M 3.1 Review of Maintenance Procedures
a.
inspection Scope
The team reviewed selected maintenance procedures for the systems selected for
inspection. The reviews were to determine technical adequacy and that they
satisfied vendor requirements and recommendations.
b.
Observations and Findinos
The licensee's maintenance procedures reviewed during this inspection appeared to
be technically adequate to perform the specific maintenance task and provided for
the identification and evaluation of equipment and work deficiencies. The
inspectors' review of sample modifications to equipment or systems determined
that the maintenance proc 3dures had been revised to incorporate the modifications.
Maintenance procedure content was compared against manufacturer's maintenance
(
and inspection recommendations for the auxiliary feed pumps, auxiliary feed pump
(
turbines, MDAFW motors, circuit breakers, motor-operated valves, control room
chillers and control room air handlers. The procedures appeared to satisfy, and in
some cases exceed, the manufacturer's maintenance and inspection requirements.
Vendor manuals appeared to be complete and up-to-date.
The team also reviewed the calibration records of severalinstruments on these
systems and noted that the instrumentation was generally well maintained. With
few exceptions, the reviewed measuring and test equipment used for surveillance
tests were in calibration.
Discrepancy Report Not Comoleted for Out-of-Tolerance Data
The inspectors' review of surveillance procedure, SP-2224, dated March 1996,
indicated that the control room recorders,2TR-450 and 2TR-451 (wide range RCS
temperatures), were out of tolerance yet a sun sillance procedure discrepancy
report (SPDR) had not been written. This was in conflict with work procedure,
SWl-STE-10, " Evaluation of Out-of-Tolerance Calibration Data in !&C Procedures,"
which specified that a SPDR be completed when as-found data did not meet the
specified tolerance of the acceptable value. The issue was of minimal safety
consequence as the recorders were brought back into calibration (when initially
identified) and were considered operable, in response, the licensee issued
nonconformance reports (NCRs) Nos. 2010746 and 2010747 to address the issue.
The licensee's failure to generate the SPDRs was considered a weakness.
10
,
.
_
-
. ._
_
_
_
,_. .
.
!
l-
l
C.
Conclusions
!l'
The team concluded that, overall, the licensee's procedures were technically
'
adequate and sufficient to perform the required maintenance and inspection tasks
and had the necessary provisions to identify and evaluate deficiencies. The
L
procedures also satisfied or exceeded vendor recommendations for maintenance
and inspection of vendor supplied equipment.
i'
!
M8
Miscellaneous Maintenance issues
l
M8.1 Maintenance-Related Unavailability
a.
Insoection Scope
)
i
The team reviewed maintenance history on selected components, performance
indicators, and trending to determine whether equipment was being adequately
maintained to assure its operability under all conditions,
,
b.
Observation and Findinas
Review of performance indicators from April 1996 through March 1997, provided
the following information:
Average monthly corrective action backlog: less than 50 work orders
(
Licensee event reports directly attributed to maintenance during the past
year: 1
Reactor trips initiated by maintenance: none
Repeat work requests generated: 16
Power block Priority 1 average backlog: 4
Overdue preventive maintenance January 1994 - February 1997: none
The data reviewed indicated that the maintenance and preventive maintenance
programs appeared effective in assuring equipment operability. Based on
examination of the available data as well as field walkdowns, the inspectors noted
that plant components were adequately maintained such that equipment had a high
degree of assurance of operating when called upon.
c.
Conclusion
Based on examination of available maintenance history, performance indicators, and
l
trending data, plant components were being appropriately maintained to provide
'
assurance of operating when called upon.
!
11
7 ---
..
- - _ . -
..-
_,
- . - .
. . - - -
--.
-..
.
f4
4
l
i-
.
,
s-
111. Enaineerine
E1
- Conduct of Engineering
[
E1.1
Inadeauste AFW Pump Surveillance Testina Acceptance Criteria
a.
Inspection Scope
1
.
i
The inspectors reviewed the Updated Safety Analysis Report (USAR), the Technical
.
[
Specifications and Bases, and other licensing and design basis documents to
[
. identify and quantify the functions and performance requirements for the AFW
system. The inspectors reviewed the completed procedures for the four previous
performances of the refueling outage (RFO) functional tests for each of the four
F
AFW pumps and the monthly AFW pump surveillance procedures. The inspectors
i.
also reviewed applicable engineering calculations.
j
1
b.
Observations and Findinas
1
1.
The licensee had designated the minimum acceptance criteria for the AFW pump
tests as .10% degradation from the reference pump curve which satisfied ASME
code,Section XI. However, based on review of the design basis accident (DBA)
requirements, the inspectors raised a concern that the licensee had not evaluated
whether the pumps, at 10% degradation, would meet the DBA requirements. The
licensee had not calculated the minimum pump performance requirements
necessary for the pumps to meet minimum design requirements but instead based
the test acceptance criteria only on Code requirements of allowing up to 10%
degradation. From USAR Section 11.9, the AFW pumps' minimum DBA
requirement was to provide a flowrate of at least 200 gpm to one steam generator
(SG) at 1100 psig.
Of particular concern was the inspectors' observation that the 3% actual
degradation of the most limiting AFW pump (21) appeared to be near the minimum
design flow requirement. The licensee promptly documented in calculation ENG-
ME-315 that assuming worst case conditions, worst case instrument inaccuracy
combinations and other conservatisms even the most limiting AFW pump (21)
would deliver at least 200.8 gpm to one SG at 1142.6 psig. The calculation used
empirical test data and a computer model of the AFW system. Some parts of the
model still needed to be validated and the licensee intended to accomplish that
validation testing during the next refueling outages (RFOs) (October 1997 for Unit 1
and February 1998 for Unit 2). A preliminary team review found that the
calculation provided reasonable assurance that the pumps would perform the AFW
safety functions during any DBA.. The licensee believed that improved test
equipment and calculations would demonstrate that the pumps actually have more
margin. Detailed NRC review of the calculation and verification of the model will be
tracked as inspection followup item (IFl 50-282/306-97008-01(DRS)).
j
Further, the licensee promptly initiated non-conformance report NCR 2010728
which documented that the ASME acceptance criteria (10% from the reference
,
curve) for all the AFW pump tests could have allowed the pumps to degrade below
minimum design requirements. The team confirmed that the acceptance criteria
12
t
..
.
. - _ . , _ _ . _ - ,
. , _ . . .
_
_
__.
_
c
1.
were inadequate.10 CFR Part 50, Appendix B, Criterion XI, Test Control, requires,
in part, that testing shall be performed in accordance with written test procedures
which incorporate the requirements and acceptance limits contained in applicable
design documents. The failure of AFW test procedures to have incorporated the
design requirements contained in applicable des!'jn documents is an apparent
violation of 10 CFR 50, Appendix B, Criterion XI, Test Control (eel 50-282/306-
97008-02).
The non-conformance report also documented that all AFW pump test procedures
would be corrected by May 31,1997, or before the test was reperformed,
,
whichever was sooner. While onsite, the team confirmed that the tests that were
performed had corrected acceptance criteria.
The licensee informed the team that there was reasonable assurance that even the
most limiting AFW pump (21) would not degrade below safety function capacity
before the next RFO test because there were numerous conservatisms in calculation
ENG-ME-315. A team review confirmed the existence of substantial conservatisms
in the calculation. The team also reviewed the last four tests for each AFW pump
and found that the degradation between tests was small enough to assure that the
AFW pumps would not degrade below the safety function capacity.
The licensee assured the team that their preliminary review found that all safety
related pumps were performing above minimum design requirements.
Failure to Complete Corrective Action on Similar Issue
(
(
.
In response to team questions on the acceptability of the acceptance criteria of
other safety related pumps, the licensee stated that the cooling water pumps'
performance was reviewed prior to an NRC service water operational performance
inspection (SWOPI) performed in the early 1990s. The pumps' performance was
found adequate and the lowest test acceptance criteria were also found to be
adequate. The licensee also stated that the safety injection (SI) pumps were
reviewed during a 1991 modification and found to be performing above design
requirements but the acceptance criteria had to be corrected. The licensee stated
in NCR 2010728 that the acceptance criteria for the remaining safety related
pumps would be reviewed by July 1,1997.
However, an operational experience assessment (OEA) action item was generated
in 1991 to review the acceptance criteria of all of the ASME Section XI pumps
other than the cooling water and safety injection pumps. This review was not
given proper priority and was never accomplished. This review would likely have
identified that the AFW and other pump tests had inadequate acceptance criteria.
The failure to complete this corrective action was not identified until prompted by
NRC questions. The licensee's corrective action process for industry operating
experience issues was separate from the corrective action tracking process for
other nonconformances and as a result did not have adequate controls to ensure
,
l
proper action was taken on an item open for several years. In response, the
l
licensee stated that all OEA open items, priorities, and schedules would be
reviewed by June 30,1997.
13
,
,.
10 CFR 50, Appendix B, Criterion XVI, Corrective Action, required that " Measures
shall be established to assure that conditions adverse to quality. . .are promptly
identified and corrected." Contrary to this requirement, since the original
identification in 1991 of the above described condition adverse to quality, the
licensee did not promptly act to correct this condition. The failure to accomplish
the review of other ASME Section XI pumps is an apparent violation of 10 CFR 50,
Appendix B, Criterion XVI, Corrective Action (eel 50-282/306-97008-03).
c.
Conclusion
The inspectors concluded that the AFW pumps' test procedure acceptance criteria
did not include the design requirements from the USAR. The acceptance criteria
could have allowed the AFW pumps to degrade below required design flows. This
i
was an apparent violation of test control requirements.
The licensee failed to accomplish corrective action from 1991 of reviewing safety
related pump test acceptance criteria and this was an apparent violation of
corrective action requirements.
'
E1.2 Reauired AFW Flow Rates Followina a Desian Basis Accident
3.
Scope
The inspectors reviewed the AFW design basis document (DBD), the follow-on
items (FOI) resulting from validation of the DBDs, and the USAR to determine the
most limiting required flow rates.
b.
Observations and Findinas
USAR Section 11.9.3 " Performance Analysis [ Condensate, Feedwater, and
Auxiliary Feedwater Systems]" specified that 400 gallons per minute (gpm) of AFW
flow were available to the intact steam generator within 10 minutes of a main
feedwater line rupture (MFLR). Based upon the nameplate rating of the AFW
pumps, both AFW pumps would have to supply water to one steam generator to
achieve this value. If there was a single failure of one AFW pump, then the
required flow rate could not be achieved. In the DBD, the inspectors noted that the
issue of the required flow rate following a MFLR had been designated a FOI.
The FOI had been issued in December 1992 to resolve a discrepancy between the
USAR required value and the capability of a single pump. The FOI,781, also stated
that the MFLR was not discussed in the accident analysis section of the USAR,
Section 14, although it was the accident which placed the most limiting conditions
upon the AFW system.
The licensee's initial evaluation in early 1993 confirmed that the MFLR scenario
was based upon a guillotine rupture of the feedwater piping after the AFW system
l
joined the line. A simultaneous loss of offsite power would require AFW flow to
l
mitigate the accident. The assumed single failure was the loss of the AFW pump to
'
the unbroken loop. The remaining pump would feed the break until manually
realigned. The operator was required to take action to realign the remaining AFW
14
,
.
pump to the unbroken loop within 10 minutes. However, this evaluation confirmed
that only one AFW pump would be available to provide AFW flow to the steam
generator. Since each pump provides approximately 200 gpm, the 400 gpm flow
rate listed in the USAR would not be achievable.
In July 1993, the licensee concluded that the nuclear analysis department (NAD)
should confirm that the appropriate AFW flow rate (200 gpm) was used in the main
feedwater line break analysis, if so, NAD was to take steps to appropriately revise
the USAR. If not, NAD was to perform the necessary analysis to show that 200
gpm was acceptable. At the same time, the licensee performed an operability
evaluation and concluded there was a reasonable basis for considering 200 gpm
l
acceptable. This conclusion was based partially upon a 1969 letter from the
nuclear steam supply vendor and relied upon a less conservative initiating reactor
trip scenario than was stated in the USAR. Because the 400 gpm value was
considered a " paperwork" issue, the licensee did not establish a high priority for
confirming that 200 gpm was an acceptable value.
Although the licensee considered the issue to be one where the USAR was
incorrect, the schedule for updating the USAR was not taken into account in setting
a resolution date. The USAR was updated in late December 1993 and was
supposed to reflect changes to the USAR as of six months previous (i.e., up
through June 1993). Although the incorrect USAR value was identified in
November 1992, and the operability analysis performed in June 1993 declared 200
gpm to be the correct number, the USAR was not changed in the 1993 update.
Two years later, in June 1995, the licensee questioned the status of the FO! and
whether the USAR should be updated. At that time, NAD had determined that the
main feedwatcr line break analysis did assume a 400 gpm AFW flow rate, but had
not yet redone the analysis to confirm that 200 gpm would be sufficient.
Therefore, the licensee decided to not update the USAR, because acceptability of a
200 gpm AFW flow rate to mitigate the MFLR was not proven. It appeared the
licensee did not fully consider the dichotomy of this decision: if 200 gpm was not
an acceptable number for the USAR, then the plant was no longer within its design
basis and the operability evaluation should have been revisited to ensure that AFW
was still capable of performing its safety related function following a MFLR. The
licensee also did not recognize or report that the plant was in an unanalyzed
condition, since the 400 gpm flow rate assumed by the MFLR analysis was not
achievable by the pumps, and the available 200 gpm flow rate was not analyzed.
Nor did the licensee perform a safety evaluation to justify a "de facto" modification
to the facility as described in the USAR.
The inspectors questioned the licensee about the status of the FOI. A member of
the licensing staff responded that the licensee intended to update the USAR during
the December 1997 update, but acknowledged that, as of the time of the
inspection, the information necessary to support the update was not available. The
,
inspectors then discussed :he issue with the responsible technical engineer. The
(
inspectors were informed that NAD had performed the analysis and concluded that
200 gpm was acceptable. However, the calculation was still undergoing the review
i
'
and approva! process. The licensee engineer stated that a June 30,1997, date had
been established for NAD to complete the review and approval process. The
15
_-
_
..
.
_ _.
_
_
,
f
a
"
inspectors questioned whether the engineer had considered th USAR update
e
schedule in establishing this date; the licensee responded that they had not, but
'
would ensure that it would be taken into account.
10 CFR 50.9(a), " Completeness and Accuracy of Information," requires, in part,
that information provided to the NRC by a licensee or information required by _
regulation to be maintained by a licensee shall be complete and accurate in all
material respects.
'
10 CFR 50.71(e), " Maintenance of Records, Making of Reports," requires, in part,
that each licensee periodically update the final safety analysis report (FSAR) to
assure that the information included in the FSAR contains the latest material
develoned. Subsection 4 requires, in part, that revisions be filed such that the
intervais between successive updates to the FSAR do not exceed 24 months. It
further states that the revisions must reflect all changes up to a maximum of 6
!
months prior to the date of filing.
l
4
10 CFR 50.73(2)(ii)(B) requires, in part, that the licensee report any event or
1
condition that resulted in the nuclear power plant being in a condition that was
j
,
outside the design basis of the plant.
1
10 CFR 50.59, " Changes, Tests and Experiments," permits the licensee, in part, to
make changes to the facility as described in the safety analysis report without prior
Commission approval provided the change does not involve an unreviewed safety
'
question. It requires, in part, that the licensee maintain records of changes in the
facility and that these records include a written safety evaluation which provides
i
the bases for the determination that the change does not involve an unreviewed
)
safety question.
4
i
10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action," requires, in part,
l
that measures be established to assure that conditions adverse to quality, such as
failures, malfunctions, deficiencies, deviations, defective material and equipment,
and nonconformances are promptly identified and corrected.
The failure to correct the inaccurate 400 gpm AFW flow rate in the USAR, despite
4
two opportunities to do so in December 1993 and 1995, is considered an apparent
violation of 10 CFR 50.9 and of 10 CFR 50.71(e) (eel 50-282/306-97008-04a and
-04b).
The failure to report that the plant was outside its design basis when it was
determined that the MFLR analysis used a 400 gpm AFW flowrate was considered
an apparent violation of 10 CFR 50.73 (eel 50-282/306-97008-05a). The failure to
,
i
perform a safety evaluation to make permanent this change to the facility as
described in the USAR and to verify that no unreviewed safety question existed
was considered an apparent violation of 10 CFR 50.59 (eel 50-282/306-97008-
05b).
i
The failure to take prompt corrective actions to resolve the above described
significant condition adverse to quality is considered an apparent violation of
.
16
>
y
. . .-
.. .---
.
. -
-.
.
..
.
.
.
..
10 CFR, Part 50, Appendix B, Criterion XVI, " Corrective Action" (eel 50-282/306-
4
97008-06).
c.
Conclusions
,
i
Based upon knowledge of the required AFW flows for similar nuclear power plants,
the inspectors considered the preliminary (unverified) results of the licensee's MFLR
4
analysis to provide reasonable assurance that the AFW pumps were operable and
could handle the main feedwater line rupture accident. However, the licensee did
,
not take prompt and appropriate actions to confirm that the 200 gpm flow rate was
acceptable and to correct the USAR.
E1.3 Modifications and Desian Chances
a.
Inspection Scope
.
The team reviewed several mechanical, electrical, and instrumentation and control
design changes. The inspectors reviewed the design changes for an adequate
description of the design change, necessary interdepartmental reviews for technical
I
adequacy, 50.59 evaluations, adequate supporting calculations, adequate
'
implementation of the design change, quality control (OC) reviews, post-
modification testing, adequate documentation, and training on the design change,
as needed. Design Changes reviewed are listed in back of this report.
1
b.
Observations and Findinas
k
,
The inspectors reviewed a sample of modifications from 1982 through 1996 and
observed that the modifications generally made only minor changes and did not
affect the design basis. The inspectors reviewed the associated safety evaluations
in accordance with 10 CFR 50.59. The licensee showed a definite improvement in
'
the quality of safety evaluations over the years, with the latter evaluations being
much more comprehensive and in-depth. Based on reviews of safety evaluations
and screenings, the inspectors did not identify any examples where an unreviewed
safety question existed, although Section E3.2 discusses a concern of failure to
,
generate a safety evaluation. The inspectors concluded that the modifications,
including documentation, revisions, and post-modification testing, on the AFW
system were acceptable.
I
c.
Conclusions
Design changes and modifications reviewed, including documentation revisions and
-
post-modification testing, on the AFW system were acceptable.
1
E1.4 Lack of Validation of Controi loom (CR) Habitability Analysis Assumptions
a.
Inspection Scope
,
The inspectors reviewed the control room ventilation system including original and
recent calculations related to control room (CR) habitability. The team also
2
-
17
4
.
-.
.
..
_
._
.
.
reviewed design and licensing basis documents related to the system, equipment
testing procedures, and the CR ventilation's compliance with regulations.
b.
Observations and Findinas
Backaround
The calculated radiation exposure to the CR operators is dependent on several
factors ir.cluding the flow rate of unfiltered air inleakage to the CR envelope
assumed in the safety analysis. These assumed values are based on system design
and are typically fixed but bounding values in the safety analysis. However,
industry experience, as documented in NUREG/CR-4960, "CR Habitability Survey of
Licensed Commercial Nuclear Power Generating Stations," indicates that air
i
inleakage rates are commonly found to be significantly greater than the assumed
values. This may be due to wear on dampers and door seals and degradation of
duct and penetration seals.
As discussed in NUREG-4960, in evaluating CR habitability for inleakage of
potentially contaminated unfiltered air, attention should be focused on penetration
of the CR envelope, (ducts, piping, cabling, and doors), particularly system
dampers. Air inleakage at these locations can occur for all types of CR habitability
system designs, including those such as Prairie Island's that do not rely on
maintenance of positive pressure relative to adjacent areas, in systems where
positive pressure is not maintained, penetrations of the CR envelope may be the
source of significant inleakage and a periodic test would demonstrate that the
radiological analysis has not been negated due to increased inteakage. This testing
had not been done at Prairie Island Nuclear Generating Plant (PINGP).
Mr to the inspection, the NRC resident inspection staff had raised several
questions related to inconsistencies in assumptions between different control room
dose calculations. Partly as a result of these questions, the licensee generated
nonconformance report (NCR) 2010713 to address the inconsistencies.
Subsequently, the licensee revised the CR personnel post-LOCA dose analysis
(GEN-PI-023, Addendum 1) in an attempt to bound the identified non-conservative
inputs in the original calculation. The revised inputs inc;uded use of control room
volume values that added the Safeguards Chilled Water Rooms and the Relay Room
as part of the control room envelope. The CR volume in the analysis changed from
approximately 44,000 ft to a volume of 164,000 ft'.
Assumption for CR Unfiltered Inteakaae Rate not Validated
The revised calculation concluded that the thyroid, whole body, and beta skin doses
to the control room operators continued to satisfy the General Design Criteria (GDC) 19 criteria, namely 5 rem whole body or equivalent. However, the inspectors noted
that the analytically determined total thyroid dose of approximately 27.6 rem
provided little margin to the GDC 19 limit of 30 rem. The inspectors were
concerned that a pivotal assumption made in the revised calculation, the unfiltered
control room inleakage, assumed to be 165 cfm, had not been verified or validated
by testing. Higher inleakage values could readily place the plant outside of the
regulatory limit.
18
^
.
4
..
Based on reviews of the documentation and interviews with the licensee, the
1
inspectors considered that the licensee had relied on generic guidance, without fully
i
demonstrating that the inteakage value was appropriate. While no regulatory
'
,
requirement was identified requiring validation of the assumption, the weak
tecimical basis was a concern.
In response to the inspectors' concerns, the licensee discussed their regulatory and
'
technical basis for concluding that the use of 165 CFM inteakage valve was
!
appropriate.
The regulatory basis relied on use of NRC Standard Review Plan 6.4,
I
Section li.3.d.2. In order to obviate testing of the inleakage value, the licensee
assumed a leakage value just above the value that the SRP would require validation
via testing. Further, the licensee noted other license basis documents where the
NRC had referenced the subject SRP section. It appeared that the licensee was
using .the SRP guidance in a " piecemeal" fashion. For example, contrary to the
discussion in the SRP, the gross leakage (calculated or measured) was not based on
1
test data. Also, discussion with NRR indicated that correlating the CR volume to
i
unfiltered CR leakage as the licensee was doing, was used as a starting point
assumption during the licensing process. The actualinleakage may differ
significantly and continued use of the SRP values should have a technical basis.
The licensee's technical bases for the adequacy of the assumed unfiltered inleakage
.
rate were also discussed. The licensee staff stated they had confidence in the
!
conservativeness of the assumed inleakage value based on arguments such as
f
(1)
physical CR location which has minimal unsealed openings,
(2)
a relative negative pressure in the auxiliary building during a LOCA (from the
auxiliary building special ventilation system),
(3)
sealing quality design of the isolation dampers, and
(4)
use of an additional inleakage value (unverified) for post accident CR egress
and ingress.
The inspectors noted the technical arguments continued to rely on the assumption
that all penetrations are adequately sealed, that the assumed inleakage is in fact
bounding and that degradation over the years has been minimal. A periodic test,
which would demonstrate that the radiological analysis has not been negated due
to increased inleakage, was not required and had never been conducted.
Although the Prairie Island Nuclear Generating Plant CR isolation dampers are
inspected annually, the inspection consists only of a visual examination of damper
mating surfaces and visual checks of closure. There are no minimum leaktightness
j
performance requirements. The licensee staff stated that the louver style dampers
were designed for maximum leakage of approximately 15 cfm at 4-inch pressure
differential, and per the vendor, would maintain outstanding sealing characteristics
through a broad range of pressure differentials. However, as noted by NRC
inspections documented in NUREG/CR-4960, of the various damper styles in use
for isolation purposes, based on industry empirical testing, louver-style dampers
l
appear to have the highest potential for significant leakage. Louver-style dampers
l
19
I
i
l
_ _ . .
. _
_
_
_.
._
.
. _
_ _ _ _ _
_
,
,
were found to be very poor at maintaining air tightness especially when exposed to
a differential pressure of severalinches of water.
The licensee stated that it would be prudent to confirm the amount of isolation
damper degradation that may have occurred since installation and would further
evaluate the need to confirm this assumed value. However, the licensee did not
give a time frame for this evaluation. The licensee also planned to re-perform the
control room dose analysis using the Dose Conversion Factors (DCF) from
International Commission on Radiological Protection (ICRP) 30 instead of from
ICRP 2 which were used in the latest calculation. It was expected that the ICRP 30
values would increase the margin between the analytical values and the GDC 19
limits.
c.
Conclusions
For the CR habitability dose analysis, the inspectors considered that the licensee
had a weak basis for concluding that the unfiltered inleakage rate assumption was
conservative. PINGP relied on industry guidance and non-validated technical
arguments without demonstrating that the actualinleakage value had not changed
or that the CR envelope had not degraded. While no regulation or license condition
appeared to require testing of the CR envelope or of the CR isolation damper, the
low margin to the GDC 19 thyroid dose limit and the effects of the unfiltered
inleakage on the analytical doses were of concern.
E1.5 Safeauards Chilled Water Pipina
a.
Inspection Scope
The team reviewed the design of the control room chilled water system piping to
ascertain whether the piping would perform its intended function under plant design
basis conditions,
b.
Observations and Findinas
The safeguards chilled water system was originally design class lll and during the
original design a detailed seismic analysis was not performed on the piping system.
The Prairie Island USAR did not classify the piping system as design class 1, which
at Prairie Island required a seismic evaluation. However, the piping provides cooling
to several safety-related rooms through unit coolers or air conditioners. These
rooms are:
4kV Safeguards Switchgear rooms
480V Safeguards Switchgear rooms
Relay room
Control room
Event Monitoring Equipment rooms
20
O
e
i
.
In May 1996, the licensee questioned the architect / engineer regarding the
seismicity of the safeguards chilled water system. The architect / engineer was able
to locate seismic documentation for system components but not for the piping,
in response to the team's concerns that the piping was not design class I, the
licensee produced documentation describing the safeguards chilled water piping
walkdown, calculation ENG ME-309, " Seismic Adequacy Review of Safeguards
Chilled Water Piping," Revision 0, March 4,1997, and safety evaluation, SE
No. 21, Revision 2, May 2,1997. This documentation qualitatively demonstrated
that the safeguards chilled water system piping should maintain the pressure
boundary during a seismic event. Heat load analysis qualifying equipment in the
above rooms had been generated. The Safe Shutdown Earthquake (SSE) at Prairie
Island was relatively small.
.
Horizontal acceleration
0.12g
Vertical acceleration
O.08g
The team's review of licensing requirements and the USAR found no requirement
for the safeguards chilled water piping to be design class I piping.
c.
Conclusions
The safeguards chilled water system was not seismically designed; however, the
team did not identify any requirement in the USAR or licensing documents that
[
required the piping to be seismic design class 1.
g
E3
Engineering Procedures and Documentation
E 3.1
Review of Calculations
a.
insoection Scope
The inspectors reviewed calculations in electrical, instrumentation and mechanical
disciplines (see list at end of inspection report) for technical adequacy, verification
of assumptions and overall correctness of conclusions.
b.
Findinos and Observations
The calculations ranged from those performed during initial construction of the plant
in the early 1970's to some as late as 1995. The inspectors had minimal
comments with the electrical, instrumentation, HVAC and pipe stress analyses
reviewed. These calculations were considered acceptable with respect to
assumptions, methodology, and conclusions. However, the inspectors noted minor
discrepancies in many of the pump and hydraulic related mechanical calculations
reviewed.
For example, during initial construction, a calculation was performed to determine
the AFW pump discharge pressure. The controlled copy of the calculation did not
show the calculation as being independently verified, showed numbers crossed out
with new numbers written in, contained mathematical errors, and did not reflect
21
O
'
.
.
changes made to the plant during installation. Similarly, a calculation for
determining the total dynamic head did not use conservative assumptions (in regard
to water temperature) and was not independently verified. Additionally, the
inspectors determined that the assumed friction head losses were less than half of
those in the installed system; however, the calculation was not revisited when
actual piping information became available. In both cases, although the numerical
results were incorrect, the overall conclusions of the calculations were not affected,
in 1990, during the station blackout proj3ct modifications, the Unit 2 condensate
storage tanks (CSTs) were moved further away from the plant. A calculation,
M-376-CD-001, was performed to determine the effects of this move on the net
positive suction head (NPSH) available for the AFW pumps. The independent
l
reviewer identified some errors in the original calculation, and performed an
alternate calculation to correct those errors. However, the alternate calculation by
the independent reviewer actually introduced more significant errors. For example,
the independent reviewer did not calculate the worst case NPSH (from the #22 CST
to the #11 AFW pump); instead, the reviewer calculated the line losses from the
- 22 CST to the #12 pump (which removed approximately 30 feet of line losses
from the calculation). Additionally, the independent reviewer ignored the head loss
from the pipe nozzle and through contractions in the pipe diameter, left out
approximately 16 feet of pipe between the CSTs and the header, and made
incorrect assumptions about head losses through elbows. The inspectors
performed an independent calculation and determined that the NPSH available was
about 27 feet, well above the required NPSH of 13 feet. Therefore, the
calculational errors did not affect the AFW pump operability. The licensee
acknowledged the errors in the calculation and was considering a revision to the
calculation.
In 1992, the licensee performed calculation SYS-AF-002 to determine how quickly
condensate would build up in the steam supply line to the TDAFW ISump. The
purpose of the calculation was to determine if the TDAFW pump could be
considered operable if the steam line drains were isolated. The inspectors noted
that the calculation was performed in January 1992, but the calculation was not
validated until December 1992. Additionally the inspectors noticed that both the
preparer and the independent reviewer used an incorrect formula for calculating the
Nusselt number for the horizontal runs, both overlooked 11 feet of piping, and,in
correcting a pipe length error in the original calculation, the independent reviewer
introduced a new error by performing the calculations on the wrong diameter
piping. Finally, the independent reviewer's alternate calculation contained
mathematical errors: in calculating the Raleigh number, the reviewer forgot to
convert one of the terms from feet per second squared to feet per hour squared.
This introduced a conversion error equal to 12,960,000 seconds squared per hours
squared. These errors had no impact on the calculation's conclusions, since the
licensee had determined that the TDAFW pump must be considered inoperable if
the drains were closed. However, the licensee acknowledged that the calculation
needed revising to correct the errors.
in October 1992, the licensee performed calculation ENG-ME-292 to determine if
sufficient cooling water flow could be passed through a half-open gate valve to the
AFW pumps. Similar to the other calculations, errors were discovered by the
22
7
. - ~
.
.-. - - - - - . - -
- . . - . - - - - - - - .- - - . . - .
-
...
- t
ie
i
- -
, inspector, including an incorrect number.of elbows in the pipe and a
-
non-conservative cooling water header pressure. ' Additionally, during review of the.
l
,
isometric drawings while performing an NPSH calculation, the inspectors noted that
I
the isometric showed the cooling water connection to the AFW pumps to be
.
1
1 %-inches in diameter versus the 4-inches claimed in the calculation. The errors
i
resulted in the numerical value being significantly decreased; however, it still
,
appeared to be above the required flow rate. The licensee prepared a
j
nonconformance report and planned to revise the calculation.
!
In 1995, the licensee revised calculation ENG-ME-148 which evaluated the effects
of flooding in the AFW pump room. During review of ENG-ME-148, Revision 1, the
l'
inspectors noted that it claimed (on page 4) that " supporting calculations performed
by NSP's Nuclear Analysis Department [ Reference 7] show that this flow rate can
'
be readily handled by the floor drains, trench, and the gap under the doors leading
the AFW rooms with less than 3 inch rise in water level." However, when the
'
inspectors reviewed " Reference 7," which was the corporate Nuclear Analysis
Department calculation V.SMN.94-006, the following errors were discovered: 'First,
the NAD calculation made no attempt to estimate flow through the drains. During -
i
an inspection during the first week onsite, the inspectors observed that several of
'
the small floor drains were clogged with dust and debris. The inspectors asked if
l
the drains received periodic cleaning. The licensee's response was "no;" however,
the drains were clear by the last week of inspection. The inspectors also noted that
- there was one large rectangular grated sump which led to a drain'which, due to the
water flow observed, appeared to be clear.
Second, the NAD calculation assumed that the trench running through the room
(
was uncovered and then calculated various percentages of blockage, down to 10
percent open, due to the cover normally over the trench. However, during the
walkdown, the inspectors observed that the trench was completely covered, with
j
only three small (less than 2-inches in diameter) openings - one on the Unit 1 side
i
and two on the Unit 2 side. These openings provided an access to the trench of
less than 1 percent; considerably less than assumed in the calculation. Finally, the
)
calculation evaluated the flow of water under the door. - However, a mathematical
mistake was made in that the preparer calculated a 1.25-inch gap across the length
of the door rather than the actual condition of a %-inch gap for 2.3 feet and % inch
gap for the remaining 4.5 feet of the door length. Ignoring the majority of the
drains, due to the chance of their being clogged, the inspectors independently
calculated the flow into the sb...e 9, d normally open drain, along with more realistic
.
flows under the door and into the trench. The inspectors found that the water
l
buildup in the room would probably not exceed 6-inches, which was the height of
I
several electrical connections.
10 CFR Part 50, Appendix B, Criterion ill " Design Control," requires, in part, that
3
design control measures shall provide for verifying or checking the adequacy of the
l
design, such as by performance of design reviews or by use of alternate or
"
simplified calculations. In the above calculations, the design control measures
failed to verify the adequacy of the design in that the above errors were not
identified during the verification or new errors were introduced by the verification
i
review. This is considered a violation of 10 CFR Part 50, Appendix B, Criterion lli
(VIO 50-282/306-97008-08(DRS)).
l
23
1
.
.
. . . _ . ,
+
-, .-
aa
-
-
n_.
~xa,,-
-u
.*
c.
Conclusions
,
While many of the calculations reviewed were considered acceptable, the
inspectors noted weaknesses in the calculation verification program based upon the
errors found in the mechanical calculations; some of which were introduced during
2
the verification process. These errors were considered violations of design control.
However, the inspectors acknowledged that, if taken individually, the errors had
only minor safety significance, due to the conservative actions taken based upon
the calculations or the margin available.
E3.2 Effect of Loss of instrument Air on the Chilled Water System
,
a,
inspection Scope
'
The inspectors reviewed the licensee's actions regarding installation of a nitrogen
bottle and use of operator action on an air-operated valve in the cooling water
-
return line from the chilled water system. These actions were necessary to
compensate for the consequences following a loss of instrument air. The
inspectors reviewed work order 9505565, licensee event report (LER)95-013,
,
JSAR Section 10.3.3, and the abnormal operating procedures for loss of instrument
dir, and earthquakes.
L.
Observations and Findinas
j
During a walkdown of the control room chilled water system, the inspectors noted
,
that nitrogen bottles were installed in the chilled water system room and airline
tubing was staged to an air-operated valve (AOV) on the cooling water return line
from the chilled water condenser. The licensee explained that during the
L
licensee-conducted service water system operational performance inspection in
1
August 1995, engineers had discovered that the cooling water return line valve
1
failed closed on loss of instrument air. This resulted in the environmental
qualification of some control room equipment being exceeded.
At that time, the licensee installed the nitrogen bottle and changed procedures to
'
require operator action to connect the nitrogen supply to the AOVs following loss of
instrument air. Additionally, the licensee determined the issue was reportable, and
issued LER 95013.
During review of this issue, the inspectors determined that the nitrogen bottle was
added to the rooms under a work order, using a standard anchor bolt installation
procedure. The licensee justified use of a work order rather than a design change,
primarily based upon the fact that the nitrogen bottle was not actually connected to
the cooling water system. After further questioning by the inspectors, licensee
engineers stated that they did not believe a safety evaluation was performed for the
change, but they be?ieved that appropriate procedures were revised.
The inspectors acknowledged that the installation of the nitrogen bottle, in itself,
did not modify the system configuration, but they were concerned that the use of
operator action to hook up the nitrogen supply to the air operated valve constituted
a change in the way the system was designed to operate following an event.
24
_
a: .
'g
r
The inspectors noted that the USAR Section 10.3.3.1 stated that the chilled water
system was " designed to provide a reliable means of cooling and filtering air
supplied to the Control and Relay Rooms under both normal and post-accident
conditions." The inspectors ascertained that the USAR statement could not be met
under "both normal and post-accident conditions" based upon the licensee's
determination that operator action was necessary following a loss of instrument air.
, Since the function of the system, as described in the USAR, was changed, the
inspectors considered that a safety evaluation should have been performed under
During a subsequent walkdown, the inspectors noted that the pressure gauge for
the nitrogen bottle was normally closed. The inspectors questioned whether there
was any surveillance procedure to ensure that the nitrogen bottles were regularly
verified to be pressurized. : Although the licensee believed that the bottles were
checked as part of routine operator duties, this was not confirmed by the end of
the inspection.
_
The li:ensee had alternate plans to cool the control room (such as by propping open
doors; following an earthquake, and would probably have sufficient time to take
those actions before equipment environmental qualifications were exceeded.
However, the inspectors were concerned about other scenarios that might result in
a loss of instrument air. The licensee noted that there were three instrument air
compressors, each of which was fed from a different emergency diesel generator,
although the system.was non-safety related. Therefore,it would be unlikely that
q
loss of offsite power would cause a loss of instrument air.
(
In 1996, the Office of Nuclear Reactor Regulation (NRR) reviewed the acceptability.
of the licensee modifying the design basis to take credit for operator actions for an
inadequate intake line issue. The NRR staff concluded that, for the particular case,
an unreviewed safety question existed for two reasons: The change to the
licensee's design basis of requiring operator actions: (1) might increase the
probability of a malfunction of equipment important to safety previously evaluated
in the USAR because operator intervention was now being relied upon for effective
performance of systems important to safety and (2) might result in the possibility
for creating an accident or malfunction of a different type than evaluated previously
in the USAR because making the effective performance of systems important to
safety reliant upon human intervention could potentially introduce unanalyzed failure
modes caused by operator acts of omission or commission.
c.
Conclusions
The inspectors determined that the nitrogen bottle installation and resultant
dependence on operator action appeared to be a change to the system function as
described in the USAR. The issue is considered an Unresolved item (URI
50-282/306/97008-09) pending coordination with NRR to determine if this example
of use of operator actions involves an unreviewed rafety question.
I
I
25
--
o.m
. . -
. E3.3 Instrumentation Setooint Methodoloav Review
a.
Inspection Scope
The inspectors reviewed design basis document follow on item FOI 0060, " Evaluate
. Basis for Precautions, Limitations and Setpoints (PL&S)," dated May 18,1990,
which was still open and required further licensee review. This follow on item
questioned the lack of a clear basis for existing setpoints. Also reviewed were
Technical. Specification setpoint values and corresponding values used in plant
procedures.
b.
Observations and Findinas
Follow-on Item 0060, " Evaluate Basis for PL&S," dated May 18,1990, questioned
0
the existing basis for.various plant setpoints and stated that a project should be
-
started to clearly establish the status of the PINGP setpoint methodology and
handling of calculations and safety evaluations versus current regulatory
)
expectations. A review of the existing plant correspondence and discussions
1
. between the inspectors and licensee indicated that the technical bases for some of
_
' the plant's limiting safety system settings and other safety-related setpoints may
not exist or may be inadequate. The setpoints may be inadequate in that no margin
to account for instrumentation uncertainties existed between some Technical
. Specification (TS) setpoints and corresponding values used in plant accident
analyses,
g
in response to this concern, but subsequent to the inspectors leaving the site, the
licensee stated that the basis for the plant's existing setpoints and limiting safety
system settings was the plant specific PL&S document developed by Westinghouse
and backed up by channel uncertainty calculations also performed by
The credibility of the Westinghouse PL&S-based setpoints was to be verified by the
plant specific setpoint calculations to indicate that a margin exists to assure that
.i
the plant's analytical limits and safety limits would not be exceeded during normal
)
,
operation and design basis accidents. The results of this effort to date were
'
,
provided to the inspectors in the form of a table comparing actual plant setpoints,
~ TS setpoints, safety analysis setpoints, and instrument uncertainties assumed in the
PL&S or design specifications. The inspectors noted that the table was not
comprehensive because not all of the limiting safety system settings (LSSS) and
limiting setpoints from the plant's TS were encompassed by the table. Further, for
some of the setpoints listed in the table, including LSSS such as overtemperature
'
delta T and overpower delta T, no margin existed between the setpoint values from
the TS and the corresponding setpoints used in the safety analyses. However, the
actual setpoints were cor:sistently more conservative than the T.S. setpoints.
The inspectors were not able to determine the acceptability of the Prairie Island
setpoint methodology process but did note that the licensee was working with
j
other utilities and appeared to be following industry guidance such as ANSI /ISA-
l
S67.04, "Setpoints for Nuclear-Related Instrumentation." The concern regarding
lack of margin to account for instrumentation uncertainties between some TS
i
26
1
1
i
-
. .
.
-
-. .
- . - - - . - - . - . . - -
- - . - _ - . - . - . . - -
..-
l
!*
-
!
-
setpoints and corresponding values used in plant accident analyses may be contrary.
i
to 10 CFR 50.36, " Technical Specifications." 10 CFR 50.36 states, in part, that
4,
LSSS must be so chosen that automatic protective action will correct the abnormal
j
situation before a safety limit is exceeded. This issue of setpoint adequacy is
'
considered an Unresolved item pending further review by NRR and Region 111 (URI
50-282/306/97008-10(DRS)).
.
c.
Conclusions
i
!
The technical bases for some of the plant's limiting safety system settings and
other safety-related setpoints may not exist or may be inadequate. The inspectors
were not able to determine the acceptability of the Pl setpoint methodology process
,
1
but did note that PINGP was working with other utilities and was following industry
]
,
guidance. This issue remains unresolved pending further review by the NRR and
-
i
Region 111.
4
E3.4 Drawino Control
a.
Inspection Scope
!.
The team performed system walkdowns on the selected systems, reviewed the
i
system configuration for consistency with design drawings, and assessed the
material condition of the systems.
,
~<
b.
Observations and Findinas
(
q
i
The team noted errors in the control room air flow diagram on drawing
NF-39603-1, Revision AH. Damper NFD-23 was shown on the 3,000 CFM duct,
,
but was installed in the 12,000 CFM duct. The drawing shows device TE 15781
1
on the discharge of the train A clean up filter fan; however, device TE 15781 was
i
j.
installed on the suction side of the fan. A damper on the discharge duct of the
control room air handler in Unit 1, train A was not shown on the drawing.
,
On flow diagram NF-39603-3, Revision AE, on the chilled water system,
temperature transmitter TT-17402 was shown on the cooling water line between
manual valves CL-16-8 and CL-16-9. In the plant, the transmitter was between
valve CL-16-9 and the flexible connection.
J
.
On condensate makeup piping isometric drawing X-HIAW-106-188, Revision 8,
1
butterfly valve C-41-2 was shown on the condensate line between auxiliary
feedwater pumps 12 and 21. However, the internals had been removed from this
valve. Incorrect drawing information on this valve impacted both the flow modeling
i
,.
and net positive suction head calculations.
!'
in response to the inspectors' question, the licensee stated a walkdown of the
system was .r!anned for within two weeks of the team's exit date.
4
f
27
.
,
_
_
_
_
.'
.
c.
Conclusions
The team's identification of the above discrepancies in system drawings indicated a
weakness in the drawing control program to assure plant drawings accurately
reflect plant status.
E7
Quality Assurance in Engineering Activities
E7.1
Review of Safety Audit Committee Meetina Minutes and Operations Committee
Meetina Minutes
a.
Inspection Scope
The inspectors reviewed the safety audit committee (SAC) meeting minutes for
June, September, and December 1996. The inspectors also reviewed the
Operations Committee (OC) meeting minutes for October 1996 through April 1997,
and witnessed portions of an OC meeting on April 18,1997.
b.
Observations and Findinas
in general, based upon review of the meeting minutes, the SAC meetings appeared
to have an appropriate focus and to accomplish the requirements of TS 6.2. The
inspectors noted that the OC meeting minutes were extremely short, merely listing
the items discussed during the meeting. The inspectors observed that it was
difficult to determine from the meeting minutes what was accomplished during the
OC meeting. During the OC meeting witnessed by the inspectors, the inspectors
determined that the required OC members were present, that the members were
prepared for the meeting, and that there was a good discussion of the issues
presented to the OC members.
c.
Conclusions
The inspectors concluded that the SAC and OC meetings fulfilled their TS
requirements and provided the necessary oversight function for which they were
intended.
E7.2 Quality Audits
a.
Inspection Scope (40500)
The team reviewed licensee quality assurance audits and assessments and the
licensee's corrective action relative to deficiencies identified during the audits.
b.
Observations and Findinas
The licensee's quality assurance program updated in 1996 included an audit plan or
schedule based on the four SALP functional areas. The licensee audit teams were
normally composed of quality personnel from both Prairie Island and Monticello plus
specialists as needed.
28
.
.
.
.
. - .
s ~..
.
j
Lf
.
..:
.-
-
The team reviewed four recent audits and numerous quality surveillances performed
at Prairie Island. Findings were documented and presented to plant line
management for initiation of appropriate corrective action. Correction of
'
3
i.
deficiencies identified by the findings appeared to be thorough and timely.
(
Corrective actions were reviewed by Quality Assurance to assure all aspects of the
finding were addressed and properly corrected.
4
.
!
c.
Conclusions
.
Based on the sample examined, the team considered the licensee's quality
verification program to be adequately designed and implemented. Corrective
)
!.
actions on recent QA findings were appropriate; however, corrective actions
i
violations for older issues were identified in Sections E1.1, E1.2, and E8.4 of this
j
report.
{
E8
Miscellaneous Engineering issues
.[
E8.1
Closed LER 282/306/96010: Auxiliary Feedwater Pumps Not Protected Against
i
Runout for All Conditions. This event was previously discussed in inspection
i
Reports 50-282/306/96007 and 50-282/306/96010 and a non-cited violation was
I
issued. During the SOPI, the inspectors witnessed portions of the licensee's
setpoint modification for Unit 1, including the post-modification test. No problems
4
F
were observed. As all corrective actions for this modification are now complete,
7
this LER is closed.
(
!
E8.2 (Closed) LER 282/306/97003: Discovery That the Auxiliary Feedwater Pumps Will
(
J
Trip on Low Steam Generator Pressure During a Complete Loss of Feedwater
ATWS Event. During review of a safety evaluation being prepared to resolve the
-
issue described in LER 96010, the licensee identified that the increased discharge
!
pressure setpoints would result in an AFW pump trip during an anticipated transient
l.
without scram (ATWS). The licensee identified that an AFW pump trip was not
considered during the generic ATWS analysis used by the plant. Following
identification of the issue, the licensee obtained a plant-specific analysis assuming
-
tripping of the AFW pumps. The inspectors discussed the results of the analysis
with the licensee and reviewed the vendor information describing the assumptions
and results of the analysis. The inspectors concluded that the licensee had
. appropriately resolved this issue. The inspectors concluded that the finding
constituted a violation of 10 CFR Part 50, Appendix B, Criterion ill, " Design
Control." Due to the licensee identifying the issue and promptly and adequately
correcting it, the violation is being treated as a Non-Cited Violation (NCV
50-282/306/97008-11), consistent with Section Vll.B.1 of the NRC Enforcement
Policy. This LER is closed.
E8.3 '(Closed) LER 282/306/97004: AMSAC Actuation Blocking Setpoint Inadvertently
Set Non-Conservatively High During a system review, a licensee engineer
discovered that the AFW pump anticipatory start signal setpoint upon an ATWS did
not agree with the USAR value. The licensee determined this was because a
previous setpoint calculation assumed that first stage turbine impulse pressure ~ was
linear, when it was not. The licensee promptly determined the correct values and
reset the setpoints. The inspectors reviewed the licensee's actions and determined
'
29
7
-
-.
= -
- .
.
.
_
.~.
-
.. .
-
-
.
.'
.
4
)
that the corrective actions taken were acceptable. The inspectors concluded that'
'
the finding constituted a violation of 10 CFR Part 50, Appendix B, Criterion lil,
" Design Control." Due to the licensee identifying the issue and promptly and
adequately correcting it, the violation is being treated as a Non-Cited Violation (NCV
50-282/306/97008-12), consistent with Section Vll.B.1 of the NRC Enforcement
'
Policy. This LER is closed.
,
E8.4 (Ocen) LER 50-282/306/96-13: Unresolved item (50-282/96008-09): Cable Trays
Not Meeting Separation Criteria. On July 31,1996, the licensee reported that
'
several cases of cable' trays did not meet the separation criteria in Section 8.7.2 the
Updated Safety Analysis Report (USAR). This issue was previously discussed in
4
inspection Reports 50-282/306/96008 and 50-282/306/96014. The inspectors
concluded that the licensee's evaluation of this issue was untimely and narrowly
focused. It took over four years to complete the safety evaluation and to determine
,
that the configurations were outside the plant's design basis and, therefore,
reportable. After making the report, pursuant to 10 CFR 50.72, the licensee's
investigation of the issue involved only those tray interactions listed in the original
findings, until prompted by additional NRC findings, despite evidence in the original
list that the interactions might not be limited to original findings. This is considered
a violation of 10 CFR Part 50, Appendix 8, Criterion XVI, " Corrective Action,"
which requires, in part, that measures be established to assure that conditions
adverse to quality, are promptly identified and corrected. (VIO 50-282/306/
97008-13).
The inspectors also reviewed portions of the licensee's modifications and actions in
response to this issue and interviewed licensee staff working on the issue's
resolution. The final review of the operability evaluation and the final modifications
will be coordinated with NRR to verify acceptability of use of recent IEEE guidance
and use of a 1971 Pioneer technical document to justify cable separation distances
greater than described in the USAR. The Unresolved item will remain open.
V. Manaaement Meetinas
X1
Exit Meeting Summary
The inspectors presented a summary of preliminary findings to members of Northern
States Power management at the exit meeting on May 16,1997. In addition, a telephone
exit was conducted on June 13,1997, to notify the licensee of additional examples of
violations. The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the inspection
should be considered proprietary. No proprietary information was identified.
30
7-
-
.
-
. -. -
.
.- ..
.
- -
.
.
.
PARTIAL LIST OF PERSONS CONTACTED
Licensee
K. Albrecht, General Superintendent Engineering
T. Amundsen, General Superintendent Engineering
J. Curtis, Superintendent, Electrical Systems Engineering
J. Goldsmith, General Superintendent, Engineering
S. Heideman, Superintendent Mechanical Systems Engineering
J. Hill, Manager Quality Services
G. Lenertz, General Superintendent Plant Maintenance
J. Leveille, Licensing & Management Issues
C. Mundt, Superintendent, l&C Systems Engineering
i
R. Pearson, Superintendent, Mechanical Systems Engineering
1
R. Peterson, Design Standards, Principal Engineer
T. Silverberg, General Superintendent Plant Operations
i
J. Sorensen, Plant Manager
M. Wadley, Vice President, Nuclear Generation
i
4
INSPECTION PROCEDURES USED
IP 37551:
Onsite Engineering
IP 40500:
Effectiveness of Licensee Controls in Identifying, Resolving, and
<
Preventing Problems
i
IP 61726:
Surveillance Observations
IP 62707:
Maintenance Observations
IP 71707:
Plant Operations
IP 71750:
Plant Support Activities
IP 90712:
In Office Review of Written Reports of Nonroutine Events at Power
Reactor Facilities
IP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power
Reactor Facilities
IP 92903:
Followup - Engineering
IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors
~ IP 93801:
Safety System Functional Inspection
Tl 2515/118:
SW System Operational Performance inspection
ITEMS OPENED, CLOSED, AND DISCUSSED
i
Opened
282/306/97008-01 IFl
Review of AFW Flow Model
282/306/97008-02 eel
Apparent Viol. of Test Control involving AFW Acceptance
Criteria
282/306/97008-03 eel
Apparent Viol, of Corrective Action involving failure to review
acceptance criteria of other ASME pumps
282/306/97008-04a eel
Apparent Viol, of 50.71(e) involving failure to update the
31
7 _-
_
__
_ . _ _ _ _
_. _ _ . .. _ ..
_- _ _-
_
-_
__ _ ._ _ _ ..
. _ _
-
, . .
-.
a
ITEMS OPENED, CLOSED, AND DISCUSSED (cont'd)
2
282/306/97008-04b eel
Apparent Viol. of 50.9 involving failure to provide accurate
1
4
282/306/97008-05a eel
Apparent Viol. of 50.73 involving failure to report the USAR
-
MFLR AFW accident flowrate was outside DB
282/306/97008-05b eel
Apparent Viol. of 50.59 involving failure to perform SE to
- -
address change to the facility as described in the USAR
'
,
resulting from incorrect AFW flow rate
l'
282/306/97008-06 eel
Apparent Viol. of Corrective Action involving failure to correct
j
.
282/306/97008-07 URI
Determination of seismicity requirements for safeguards chilled
- .
water piping
282/306/97008-08 VIO Design Control violation involving inadequate calculation
.
verification
282/306/97008-09 URI
Determination of acceptability of manual action installing N 2
bottle on Loss of lA for SCW system
,
4
282/306/97008-10 URI
Determination of acceptability of instrumentation setpoint
uncertainties and of administrative control of setpoints
282/306/97008-11 NCV Design control non-cited violation for AFW trip on Lo SG Press
{
during Loss-of-FW-ATWS
282/306/97008 12 NCV Design control non-cited violation for non-conservative setting
-
of AMSAC Actuation Blocking Setpoint
282/306/97008 13 VIO Design Control violation involving Untimely corrective action
,
on cable tray separation issue
,
Closed
282/306/96-010
LER Determination that the Auxiliary Feedwater Pumps are not
Protected Against Runout for all Accident Conditions
282/306/97008 11 NCV Design control non-cited violation for AFW trip on Lo SG Press
during Loss-of-FW-ATWS
282/306/97003
LER
Discovery that AFW Pumps will trip on Low SG Pressure
during a complete Loss-of-FW-ATWS Event
282/306/97008-12 NCV Design control non-cited violation for non-conservative setting
of AMSAC Actuation Blocking Setpoint
282/306/97004
LER Non-conservative setting of AMSAC Actuation Blocking
Setpoint
Discussed
EA 96-402
Failure to identify an Unreviewed Safety Question Existed in a
Safety Evaluation of the Emergency Cooling Water Intake Line
282/306/96013
LER Cable Trays Not Meeting Separation Criteria
282/306/96008-09 URI
Cable Trays Not Meeting Separation Criteria
32
p ,.
.
m.y.._
- _
. _ _ . _ _ . . _ _ . .
. _ . , _ . _ . _ _ _ _ . . _ _ _ . . . _ . _ . . _ _ _ . . _ .
.
1
. .
9..
i-
i
'
j.
LIST OF ACRONYMS USED
,
Auxiliary Building
,
ATWS Mitigating System Actuation Circuitry
'
i
ANSI
American National Standards Institute
.AOV
Air-Operated Valve
Alarm Response Procedure
d
.ASME
American Society of Mechanical Engineers
,
L
ATWS.
Anticipated Transient Without Scram
Cubic feet per minute
l
CFR
Code of Federal Regulations
'
t
CL.
Cooling Water
!
CR
Control Room
'
!
Condensate Storage Tank
j-
Design Basis Accident
.
1
Design Basis Document
- Dose Conversion Factor
!
DRS.
Division of Reactor Safety
i-
EA-
Enforcement Action
'
eel
Escalated Enforcement issue
Emergency Operating Procedure
Environmentally Qualified
FOI
Follow-On item
.
Final Safety Analysis Report
'
GDC
General Design Criteria
'
GPM
Gallons Per Minute
Heating, Ventilation and Air Conditioning
l&C
Instrumentation and Controls
ICRP
International Commission on Radiological Protection
IEEE
Institute of Electrical and Electronic Engineering
IFl
Inspection Followup item
IP
Inspection Procedure.
inservice inspection
lST
Inservice Testing
Improved Standardized Technical Specifications
LCO
Limiting Conditions for Operation
LER
Licensee Event Report
,
Loss of Coolant Accident
.LSSS
Limiting Safety System Settings
Motor Driven Auxiliary Feedwater Pump
MFLR
Main Feedwater Line Rupture
NAD
Nuclear Analysis Department
Nonconformance Report
Non-cited Violation
Net Positive Suction Head
NRC
Nuclear Regulatory Commission
Office of Nuclear Reactor Regulation
North::~ States Power Company
OC
Operta ~ns Committee
33
p
.
'
, ,
'b
LIST OF ACRONYMS USED (cont'd)
Out-of-Tolerance
j'
OP
Operations Procedure
Prairie Island Nuclear Generating Plant
Public Document Room
PL&S
Precautions, limitations and Setpoints
l
PPB
Part Per Billion
OC
Quality Control
l
Refueling Outage
l
SAC
Safety Audit Committee
l
Systematic Assessment of Licensee Performance
Safety Evaluation
l-
Safety Evaluation Report
l
Safety Injection
SOPl
System Operational Performance Inspection
Surveillance Procedure
SPDR
Surveillance Procedure Deviation Report
SWOPI
Service Water Operational Performance Inspection
Turbine Driven Auxiliary Feedwater
Safety Review Plan
TS
Technisal Specifications
Unresolved item
Updated Safety Analysis Report
Violation
WC
Water Column
ZH
Safeguards Chilled Water System
ZN
Control room ventilation system
34
.
,
-
-_
. . _ _ .
._
_
.
.
_
.
g
e
PARTIAL LIST OF PROCEDURES USED AND DOCUMENTS REVIEWED
j
i
l
Calculations
'
I
Auxiliary Feedwater Pump Room Heatup Analysis, Tenera 194001-2.2-004 (NSP
i
ENG-ME-021), Rev. O,11/22/91
{
Calculation of Total Dynamic Head for Auxiliary Feedwater Pumps, Pioneer Services
~
& Engineering Initial Plant Design, Rev. O,6/18/68
Cooling Water Header Pipe Failure Causing Flooding in the Auxiliary Feedwater
Pump / Instrument Air Compressor Room, NSP ENG-ME-148, Rev. O,12/16/94 and
Rev.1, 8/8/95
l
.
Condensate Storage Tank Piping Friction Loss NPSH, Fluor Daniel M-376-CD-001,
Rev. O,10/5/90
.
Control Room Loss of Ventilation, Tenera 192210-2.2.001, Rev. O,1/14/92
'
Control Room Ventilation System Design, NSP ENG-ME-188, Rev. O,5/18/95
Control Room Volume, NSP ENG-ME-314, Rev. O,4/16/97
Detailed Analysis of Auxiliary Feedwater Pump Room internal Flooding, NSP
3
V.SMN.94.006, Rev. O,4/7/94
!
Determination of Possible Flow Rate in Cooling Water (CL) to Auxiliary Feedwater
l
Pump Piping with Gate Valve Half Open to Verify Design Flow Will Pass Thru Half
l
,
Open Gate Valve, NSP ENG-ME-292, Rev. O,10/23/92
{
Determine Auxiliary Feedwater Pump Discharge Piping Design Pressure, Pioneer
Services & Engineering initial Plant Design, Rev. O,6/25/70
Maximum Out-of-Service Time for Steam Line Drains Upstream of the Auxiliary
Feedwater Pump Steam Supply Control Valves CV-31998 & CV-31999, NSP
SYS-AF-002, Rev. O,1/13/92
Reload Safety Evaluation Methods Applicable to Prairie Island Units, NSP
NSPNA-8102-A, Rev. 6, 8/95
Replacement Valve Evaluation - Auxiliary Feedwater Pump Drive Turbine Steam
Supply System, Fluor Power Services 217450 269, Rev. O,2/3/81
Safeguards Chilled Water Evaluation, NSP ENG-ME-028, Rev.1, 5/12/94
Engineering calculation ENG-ME-315, Rev. O
4160 Volt Safeguards Degraded Bus Voltage Setpoint, SPC-EA 006, Rev.1.
j
NSP Prairie Island Nuclear Generating Station, Setpoint Methodology, Revision 1
}
Unit 14 KV Bus Minimum Voltage, ENG-EE-061, Rev. 0
480 Switchgear Branch Breaker Settings, E-385-EA-21, Rev. 2
.
Degraded Voltage Relay Drop-out, E-415-EA-3, Rev.1
Cable Sizing Calculation for Mod #96EB01, ENG-EE-095, Rev. O
j
480 VAC Supplemental Coordination Study, ENG-EE-014, Rev. O
Justification for Low Voltage Concerns (230 VAC), ENG-EE-052, Rev. O
Diesel Generator Steady State Loading for a LOOP Coincident with a SBO, ENG-EE-
045,Rev.2
Safeguards Low Voltage Power Systems Ground Fault Current Calculation, ENG-EE-
092,Rev.0
' Cable Ampacity for Control & Power Cables for Mod #96EB01, ENG-EE-089, Rev. O
l
Medium Voltage Ground Fault Calculations, ENG-EE-093, Rev. 0
l
PI Offsite and CR Habitability LOCA dose for Vantage Plus Fuel, Calculation
l
M-834532
I
Control Room Personnel Post-LOCA Dose, Calc. GEN PI-023, Addendum 1
l
35
,
I
9
L
9
PARTIAL LIST OF PROCEDURES USED AND DOCUMENTS REVIEWED (cont'd)
Desian Basis Documents
DBD-SYS-28B, Rev.1, " Auxiliary Feedwater System Design Basis Document,"
DBD-TOP-01, Rev.1, " Accident Analysis Topical Design Basis Document," 12/5/95
DBD-STR-02, Rev.1, " Auxiliary Building"
Drawinas
" Auxiliary Feedwater System, Unit 1," Flow Diagram NF-39222, Rev. A'N
" Auxiliary Feedwater System, Unit 2," Flow Diagram NF-39223, Rev. AU
"AFW Logic Diagrams" NF-40312 and NF-40767
" Cooling & Chilled Water Systems & Fire Protection for Vent Filters in Auxiliary &
Containment Buildings," Flow Diagram NF-39603-4, Rev. T
" Lab & Service Area A/C & Chilled Water Safeguard System," Flow Diagram, NF-39603-3,
Rev.AE
"12-inch Condensate Makeup AFW Pump Suction Piping," Isometric, NQ 118234, Rev A
" Condensate Makeup to AFW Unit 1," Isometric X-HIAW-1106-188, Rev. B
" Condensate Makeup to AFW Unit 2," Isometric X-HIAW-1106-261, Rev. D
"30-foot Diameter and 29-foot High Dome Roof Condensate Storage Tank," Isometric
Detail X-HlAW-74-56, Rev.1
'
" Condensate Storage Tank 12-inch Diameter Shell Nozzle (Butt Welded)," Isometric Detail
X-HIAW-74-57, Rev.1
y
" Main & Aux. Steam Flow Diagrams," NF-39218, NF-39219
g
Miscellaneous
Tank Book, pages for the Condensate Storage Tank,7/1/93
Modifications
Auxiliary Feedwater Pump Flush Strainer,89A0089,11/23/94
Auxiliary Feedwater Pump Suction Cooling Water Vent Loop Seal,92L369,2/8/94
Chilled Water Heat Removal Hanger and Piping Modification,82Y230,1/6/82
Chlorine Monitor Removal,89YO60,4/14/93
Document the As-Found Condition of 2-AFWH-42,89A0110,4/27/89
Prevent Auxiliary Feedwater Pump's Shaft Driven Lube Oil Pump from Becoming
Air-Bound, 90A193,11/30/90
Relocate 11/22 Turbine Driven Auxiliary Feedwater Pump Steam Valves,84L838,1/18/88
Replacement of 122 Control Room Air Handler Cooling Coil,88A0002,2/8/88
Install Flow Meters for Chilled Water Pumps 121 and 122,79L401
Alarm in the Control Room for TD Auxiliary Feedwater Pump Over Speed Trip,79L564
Provide Lo-Lo Level Annunciators for 11 and 21 CST on AFW Panels,79L566
AFWP Low Discharge Pressure and Low Suction Pressure Trip,80L579
Add Phase to Phase PT's to Safeguard 4 KV Busses,93L421, Rev. 0
480 V Common Loads,96EB01, Rev. O
Install Battery Disconnect Switches,93L415, Rev. O
Load Sequencer Source Breaker interlock,95L485, Rev. 0
36
..
. _ . - .
- - .
_ _ _ - . ~ . ~ - - - - -
. - - .
. - - -. - ..
.
t
g-
!
.
'
PARTIAL LIST OF PROCEDURES USED AND DOCUMENTS REVIEWED (cont'd)
Removal of Automatic Start of AFW Pumps,77L397
' AFW Pump Runout Protection,96AF01
Purchase Specifications
,
Auxiliary Feedwater Pumps,10/1/70
Miscellaneous Reactor Plant Control Valve, 12/21/70
1
Miscellaneous Vaives for Nuclear Service,12/7/70
,
Technical Manuals
,
" Auxiliary Feedwater Pumps," X-HIAW-258-23
" Auxiliary Feedwater Pump Turbine," X-HIAW-258-24
OA - Committee Meetina Minutes
,
Safety Audit Committee Meeting Minutes, 6/7/96,9/19/96, and 12/14/96
Operations Committee Meeting Minutes #2158 - 2237,10/2/96 - 4/8/97
Surveillanc_e Procedures Reviewed / Observed
SP 1100,12 Motor-Driven Auxiliary Feedwater Pump Monthly Test,
SP 1101,12 Motor-Driven Auxiliary Feedwater Pump Once Every RFO Test
SP.1102,11 Turbine-Driven Auxiliary Feedwater Pump Monthly Test
SP 1103,11 Turbine-Driven Auxiliary Feedwater Pump Once Every RFO Test
SP 2100,21 Motor-Driven Auxiliary Feedwater Pump Monthly Test
SP 2101,21 Motor-Driven Auxiliary Feedwater Pump Once Every RFO Test
SP 2102,22 Turbine-Driven Auxiliary Feedwater Pump Monthly Test
SP 2103,22 Turbine-Driven Auxiliary Feedwater Pump Once Every RFO Test
- SP 2216, 4.16 KV Safeguards Bus 25 Undervoltage Relay Calibration
SP 2218, Monthly 4 KV Bus 25 Undervoltage Relay Test
SP 2150, DS Diesel Generator Functional Test
SP1002A, Analog Protection System Calibration
SP1024, Reactor Water Storage Tank Level for Unit 2
SP1035A, Reactor Protection Logic Test at Power
SP2150-DS, Diesel Generator Functional Test-
Emeraency Procedures Reviewed
,
,
1FR-S.1, Response to Nuclear Power Generation /ATWS
2E-0, Reactor Trip or Safety injection, and Basis
Operatina Procedures Reviewed
i
C28-2, System Prestart Checklist, AFW System, Unit 1, dated 2/21/96
C28-2, System Prestart Checklist, AFW System, Unit 1, dated 3/1/96
C28 7, System Prestst Checklist, AFW System, Unit 2, dated 3/23/97
37
..
-
-
__.
---
.'e
,
e
PARTIAL LIST OF PROCEDURES USED AND DOCUMENTS REVIEWED (cont'd)
1C28.1, AFW System Unit 1
l
2C28.1, AFW System Unit 2
C28.1 AOP1, Steam Binding Of An AFW Pump
5AWI 1.5.0, Procedure Conttol
SAWI 1.5.1, Procedure Deviation Process
SAWI 1.5.3, Periodic Procedure and Checklist Review
5AW11.5.4, Temporary Memos
5AWI 3.10.5, Plant Equipment Labeling
5AWI 4.4.0, Drawing Control
PINGP 196, Turbine Bldg Data - Unit 2
NSP Work Order 9702379, Pre-Op Test on 22 TD AFWP Low Pressure
I
Alarm Resoonse Procedures Reviewed
i
ARP C47009
l
ARP C47010
i
Training Documents Revimsed
Job Performance Measures AF-1 through AF-5
Job Performance Measures AF-5F
Job Performance Measures AF-5F-1
Job Performance Measuras AF-6S
i
AFW System Lesson Plan, P8180L-007, R4
'
AFW System Lesson Plan, P8440L-507, R3
Simulator Continuing Training Course Outline, P9160S
License Requalification Training Program Description, P9100
'
Simulator Change #971-002
PINGP 1224, Crew Training on AFW System changes dated 4/15/97
j
Miscellaneous Licensee Documents Reviewed
Licensing Commitments N-964, N-965, and N-794
,
'
USAR Input item 90-098
l
Safety Evaluation 470, AFW Pump Runout Protection
l
,
Safety Evaluation 472, AFWP Operability with Auxiliary LO Pump OOS
Temporary Memo TMA 1997-0022
Temporary Memo TMA 1997-0028
Temporary Memo TMA 1997-0035
Temporary Memo TMA 1997-0041
'
Temporary Memo TMA 1997-0042
Temporary Memo TMA 1997-0059
Temporary Memo TMA 1997-0065
H3.1, Outplant Equipment Labeling
I
PINGP Updated Safety Analysis Report, Various Section
PINGP Technical Specifications
,
38
'
4