ML17164A902
| ML17164A902 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 11/13/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17164A900 | List: |
| References | |
| 50-387-98-05, 50-387-98-5, 50-388-98-05, 50-388-98-5, NUDOCS 9811240054 | |
| Download: ML17164A902 (36) | |
See also: IR 05000387/1998005
Text
U.S. NUCLEAR REGULATORYCOMMISSION
REGION I
Docket Nos:,, 50-387, 50-388
License Nos:
Report Nos.:
50-387/98-05, 50-388/98-05
Licensee:
Pennsylvania Power and Light Company
Facility:
Susquehanna
Steam Electric Station
Location:
Salem Township, Luzerne County, Pennsylvania
Dates:
September 14- October 2, 1998
Inspectors:
Roy L. Fuhrmeister, Sr. Reactor Engineer
Electrical Engineering Branch
Ram Bhatia, Reactor Engineer
Electrical Engineering Branch
Kenneth Kolaczyk, Reactor Engineer
Civil, Mechanical and Materials Engineering Branch
Frank Amer, Reactor Engineer
Systems Engineering Branch
Alan Blarney, Resident inspector
Susquehanna
Steam Electric Station
Approved by:
David C. Lew, Acting Chief
Electrical Engineering Branch
Division of Reactor Safety, Rl
98ii240054 98iii3
ADOCK 05000387
6
0
TABLEOF CONTENTS
PAGE
Executive Summary ..;... ~... ~.... ~........ ~.......................
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eport Details ........,. ~.....................,............
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III. Engineering
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E2
Engineering Support of Facilities and Equipment
E2,1
Core Spray System Electrical Design
E2.2
Incorporation of Core Spray System Design Into Technical
Specifications Surveillance Tests .:
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E2.3
Core Spray Surveillance Test Program Implementation ..
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E7
Quality Assurance
in Engineering Activities ..
E7.1
Problem Identification and Resolution
.
E7.2
Core Spray System Flow Discrepancies
E7.3
10CFR50.59 Safety Evaluation Program.....
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V. Management Meetings
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Exit Meeting Summary ..
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PARTIALLISTING OF PERSONNEL CONTACTED
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LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED .. ~, ~............ ~...
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LIST OF ACRONYMS USED.....
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1 9
Executive Summary
This team inspection was conducted September 7 - October 2, 1998 at the site and in the
Region
I office, to assess
the engineering support of the operation of the Susquehanna
Steam Electric Station.
~En inaerin
The core spray system was found to be installed and operated
in a manner consistent with
the design requirements for electrical power supplies as described in the update final safety
analysis report and design basis documents.
Calculations reviewed were adequate to
assure that the components
and control circuits associated with the operation of the core
spray system had sufficient direct current voltage to perform the intended design function.
Refueling testing and emergency diesel load calculations demonstrated
the adequacy of the
electrical power supply to the core spray system components.
(Section E2.2)
Discrepancies identified in surveillance test procedures indicated weak engineering support
in assuring acceptance
criteria bases were sound.
The acceptance
criteria for Unit 1 core
spray test piessure did not take into account system configuration differences between
Units
1 and 2, even though these differences were identified in design calculations.
The
Unit 2 core spray quarterly flow surveillance test inappropriately included a non-
conservative correction factor for which no basis could be identified. Although the
consequence
of these discrepancies
did not result in system inoperability, the above
failures to incorporate the requirements and acceptance
limits contained in applicable
design documents are two examples of a violation of 10 CFR Part 50, Appendix 8,
Criterion III. (VIO 50-387 & 388/98005-01)
(Section E2.2)
The inservice testing program for the core spray system was sound.
Program documents
were found.to be well organized, with appropriate records of relief requests, test deferral
justifications and supporting technical information. Test failures identified during relief
valve testing were appropriately dispositioned.
The industry experience review program
appropriately considered industry information. (Section E2.3)
PP&L's program and process controls for the identification of conditions adverse to quality
were adequate.
The team's review of sixty condition reports indicated that the initiation
threshold was sufficiently low. However, two conditions, which'were not documented,
reflected inconsistency in the initiation of condition reports.
A pressurization of a portion
of Unit 1 core spray discharge piping was not documented
in a condition report, although a
similar problem with the residual heat removal system was documented.
An unexpected
power increase was not document in a condition report; this event was also documented
in
NRC inspection report 50-387&388/98007.
(Section E7.1)
PP&L's resolutions of condition reports were generally acceptable.
However, the
resolutions for two of sixty condition reports were slow, reflecting weak engineering
support.
One issue, involving an instrument inaccuracy deficiency identified in July 1996,
was not thoroughly evaluated and required a revised operability determination.
PP&L was
slow in identifying actions for the final resolution of the problem.
As a result, PP&L missed
an opportunity to make modifications, which were subsequently
determined to be needed,
during the last refueling outages.
The other issue concerned the slow resolution of heat
exchanger fouling in service water systems, which was initiallyidentified in March 1997.
A detailed evaluation of the acceptability of the heat exchanger fouling was not performed
until May 1998, after the initiation of several additional condition reports on the issue.
(Section E7.1)
The resolution of core spray flow concerns reflected a lack of questioning attitude.
missed opportunities to identify that the loss of coolant accident (LOCA) analysis did not
reflect the correct core spray flow in the facility's design.
The failure to ensure that the
design basis is correctly translated into the LOCA analysis is a third example of a violation
of the design control requirements of 10 CFR Part 50, Appendix B, Section III. (VIO 50-
3875388/98005-01)
(Section E7.2)
PPRL Nuclear Department Administrative Procedures
provide adequate
guidance to
determine if a 10 CFR 50.59 unreviewed safety question exists.
These documents clearly
delineate the responsibilities for various processes
within the 10 CFR 50.59 pro'gram and
provide adequate
controls for record retention and reporting the results of the evaluations.
The team noted several instances
in which the required 10 CFR 50.59 documentation was
not completed for condition reports dispositioned "use-as-is," as required by program
procedures.
However, technical evaluations provided bases for no unreviewed safety
question.
The failure to implement the administrativ'e procedure for 10 CFR 50.59
evaluations is considered
a minor violation of procedural adherence,
and is not being cited
for formal enforcement action.
(Section E7.3)
.1
Re ort Details
This inspection was conducted as a Safety System Engineering Evaluation, to assess
the
engineering support to the Susquehanna
Steam Electric'Station (SSES) by means of a
detailed review of the design and licensing bases of the core spray system.
The inspection
was conducted during the period September 7 - October 2, 1998, at the site and in the
Region
I office.
III. En ineerin
E2
Engineering Support of Facilities and Equipment
E2.1
Core S
ra
S stem Electrical Desi
n
aO
Ins ection Sco
e
The team reviewed the core spray system (CSS) electrical design as described in
Susquehanna
Steam Electric Station (SSES) Updated Final Safety Analysis Report
(UFSAR) and in the CSS Design Basis Document (DBD). The review included the
assessment
of the electrical equipment design performance as shown in electrical
schematic and control drawings, system calculations and other engineering
documents used to support system performance during normal and accident
conditions.
A plant walkdown of the Unit 1 and Unit 2 CSS and main control room
control panel was performed.
b.
Observation and Findin s
The core spray system, as described in the UFSAR, is required to provide inventory
makeup and spray cooling during large break loss of coolant accidents
(LOCAs) in
which the core is calculated to uncover.
When assisted by the automatic
depressurization
system (ADS), CSS also provides protection for small break
LOCAs. The system consists of two completely independent spray loops.
Each
loop consists of two core spay pumps and motors, a sparger ring, a spray nozzle,
and the necessary
piping, valves, and control instrumentation.
Each loop takes
water from the suppression
pool by suction and delivers water through the sparger
ring into the plenum chamber above the core.
Each core spray pump motor (four in
each unit) is powered from its associated
safety related 4160 volt bus and each unit
safety bus is backed up by its respective emergency diesel generator
(a common
diesel generator for each bus for both units) upon a loss of offsite power.
Desi
n Documentation Review
The inspector reviewed the CSS design of pump motors and applicable system
valves (inboard and outboard injection valves:
HV-E21-004A and 5A; minimum
flow valves:
HV-E21-1F031A and B; and test return line valves to the suppression
pool: HV-E21-1FO15A and B) and other supporting and interfacing equipment, such
as emergency diesel generator (EDG), safety injection actuation system inputs and
1
found it to be adequate
and consistent with the.design and UFSAR requirements.
The review of the power supply requirements, under the degraded voltage condition
were found acceptable for the above equipment.
The inspector found that all
sensors,
relays, wiring, and controls needed to initiate an automatic start of the
CSS were included and consistent with the UFSAR requirements.
The inspectors
noted that each CSS pump motor was appropriately powered from its respective
safety-related 4160 volt bus and backed up by the respective bus designated
EDG.
The power supply requirements for the valves and the control devices of the CSS,
such as motor and its supporting equipment, valves to the reactor coolant system
and the initiation logic sensors,
were adequately designed and powered from the
applicable power supplies required to support CSS operation during normal and
accident operation.
During plant walkdowns the inspector verified that the controls for the CSS pumps,
control valves, the suppression
pool test return and minimum flow valves,'nd
associated
instrumentation were appropriately provided in the main control room to
support the proper operation of the CSS on demand.
Calculation Review
The inspector reviewed design calculations to determine whether the electrical
power supply to CSS loads'and voltage available to the CSS equipment were
adequate
during the worst-case design basis accident, and found no concerns.
However, in one case, during the validation of the system equipment loads and
verification of the cable impedance data in calculation, EC-004-0516, "Plant Voltage
Study Model," used to demonstrate the voltage drop of plant equipment, the
inspector found that PPSL had used
a single conductor impedance value between
load center 1B210 and 1B217 instead of two in parallel installed in the station.
PPSL issued an engineering work order, M80193, on September
21, 1998.
PPSL
stated that since a higher resistance
value was used to determine the voltages in
the station, the results obtained were adequate
and conservative
in this condition.
Overall, this condition was judged by the inspector to have a minimal effect in
voltage results.
The inspector found it acceptable
since the results were slightly
conservative.
PPS.L stated that they would correct this error in their next revision
of this calculation.
The review of the EDG loading calculation results indicated that during the accident
and loss of offsite power (LOOP) condition, the diesel generators were capable of
accelerating accident loads,'nd the design loading on each diesel generator. would
be within the continuous rating of the machine.
The review of the direct current
(DC) electrical system calculations and associated
CSS equipment voltage indicated
no concern, the inspector observed that PPSL had appropriately assumed the
correct loads and assumed
a minimum battery system voltage of 105 VDC at the
end of the cycle and applied appropriate field cable voltage losses in evaluating
voltage drops.
The inspectors concluded that the DC system component and
control circuits associated with the automatic operation of the CSS had sufficient
voltage and were appropriately powered from the respective divisional DC buses to
perform the intended design function.
Surveillance Tests
The inspectors reviewed the results of the May 1998 surveillance test associated
with 18 Months-DG AC-Bus 1A, 1C LOOP/LOCA (SE-124-107, Revision 9), and
found that all CSS components functioned properly including the auto start of the
core spray pump as required.
PPKL had adequately demonstrated
the functionality
of the CSS and other supporting equipment, such as the EDG.
c.
Conclusions
The core spray system was found to be installed and operated in a manner
consistent with the design requirements for electrical power supplies as described in
the update final safety analysis report and design basis documents.
Calculations
reviewed were adequate to assure that the components and control circuits
associated with the operation of the core spray system had sufficient direct current
voltage to perform the intended design function.
Refueling testing and emergency
diesel load calculations demonstrated the adequacy of the electrical power supply to
the core spray system components.
E2.2
Incor oration of Core S
ra
S stem Desi
n Into Technical S ecifications
Surveillance Tests
Ins ection Sco
e
The team performed a walkdown of the Unit 1 and Unit 2 core spray pump rooms.
The team reviewed the core spray system description found in section 6.3 of the
UFSAR, The review also included:
verification of the appropriateness
and
correctness
of design assumptions; confirmation that design bases were consistent
with the licensing bases;
arid verification of the adequacy of testing requirements.
b.
Observations
and Findin s
Lo ic Testin
Logic System Functional test procedure SE-151-001, "18 month functional test of
CS Div I," with one noted exception discussed
below, satisfied the requirements
found within Technical Specification 4.5.1.c.1.
The team found that electrical logic
circuits associated with the throttling function of the injection valves, were
adequately tested.
Low pressure piping protection logic assured that the injection
valves could not open without a confirmatory low reactor pressure signal.
Additionally, the Iow pressure permissive bypass handswitch (HS-15249A/B LO RX
press perm) was appropriately tested to ensure that a common mode failure of the
low reactor pressure permissive logic did not result in the emergency core cooling
system (ECCS) injection valves failing closed.
The Technical Specification 4.5.1.c.1., associated with the I'ogic system functional
test, required ... "a system functional test which includes simulated automatic
actuation of the system throughout its emergency operating sequence
and verifying
that each automatic valve in the flow path actuates to its correct position." The
team could not identify where the system minimum flow valve was tested to ensure
its automatic closure upon an automatic pump start.
Although this interlock was
not tested in the logic system functional procedure, the team determined that it had
been adequately tested within the core spray quarterly flow tests (S0-1/251-A02 5
802). However, it was not included in the acceptance
criteria for the test nor linked
to the technical specification requirement.
Condition report 98-3068 was initiated
to review the last performance of the tests to ensure the valves were stroked
successfully.
An extent of condition review was performed and PPSL determined
that the residual heat removal system logic system functional tests had been testing
the minimum flow valve closing stroke interlock.
PPRL stated that the resolution to
this issue would be resolved within the corrective actions developed in condition
report 98-3068. The team noted that there was no safety consequence
associated
with this finding, as the procedure required sign-offs for closure of the minimum
flow valves during the quarterly flow test.
This failure to ensure that the regulatory
requirement was correctly incorporated in to surveillance test acceptance
criteria is
a violation of the design control requirements of 10 CFR Part 50, Appendix B,
Criterion III; however, because this failure constituted
a violation of minor
significa'nce, it is not being cited for formal enforcement action.
The team found the instrumentation and control calibration and functional tests of
the drywell pressure,
vessel water level and core spray system reactor pressure
permissive channels to be consistent with the technical specification requirements.
Core S ra
Technical S ecification Test Pressure
Calculation EC-051-0004, "Core Spray tech spec test pressure," approved on
June 18, 1998, supported the implementation of improved technical specifications,
by developing a correlation between the expected core spray flow rate and vessel
pressure during design basis accidents.
The calculation utilized conservative
assumptions for estimating the total developed head of the core spray pumps, such
as neglecting the line losses between the suppression
pool and the point where the
system test line pressure was sensed.
At the time the calculation was approved, the Unit 1 technical specification test
requirement was ".. ~ a Core Spray test pressure of 269 psig at a corresponding flow
of 6350 gpm." This composite pump operating point represented
the minimum
acceptable
performance of the pumps.
For Unit 2, the conclusion section of
calculation EC-051-0004stated,that
a test pressure of 282 pounds per square inch,
gage (psig), at 6350 gallons per minute (gpm) corresponded
exactly to a vessel
pressure of 105 psig.
This criterion was consistent with the SSES improved
technical specifications, which required that a loop of core spray be capable of
injecting greater than or equal to 6350 gpm into the reactor pressure vessel against
a steam dome pressure greater or equal to 105 psig.
However, the calculation indicated that for Unit 1, because of differences in the
calibrations of the test line pressure instrumentation loop, the same 282 psig
indicated on control room instrumentation, would not assure
a level of pump
performance which conformed to the licensing requirements
in improved technical
specification SR 3.5.1.7.
Table 3A of the calculation, indicated that the vessel
must depressurize to 99 psig before the system would be capable of supplying the
design loop flow rate of 6350 gpm. Therefore, the Unit 1 technical specification
requirement had been technically inaccurate and would not have assured
a flow rate
of 6350 gpm at a steam dome pressure of 105 psig.
On July 27, 1998, PP&L revised the Unit 1 quarterly core spray flow verification
test, SO-151-A02, to reflect a new core spray loop discharge pressure requirement
of 282 psig, at a flow of 6350 gpm which was consistent with Unit 2. However,
the team noted that this change was incorrect, because it failed to recognize the
differences in system configuration between Units
1 and 2, which were delineated
in Calculation EC-051-004.
The failure to implem'ent proper test acceptance
criteria
for Unit 1 core spray system flows and pressures
is the first example of a violation
of the design control requirements of Appendix B to 10 CFR 50.
(VIO 50-387 &
388/98-05-01)
The team determined that the licensee was'taking appropriate actions to revise
associated tests, as necessary.
Because of this discrepancy, the team requested
the last completed quarterly flowtest records for both Units, in order to verify the
actual pump performances were satisfying the technical specification requirements
and to review the test methodologies due to the differences in test line pressure
instrument calibrations.
Overall, the team determined that the pumps were
performing adequately.
Unit 1 Core S ra
Quarterl
Flow Test
PPSL initiated condition report 98-3069 on October 1, 1998, in response to the
team's concerns regarding the validity of the existing Unit 1 test pressure
acceptance
criterion of 282 psig.
PPRL confirmed that no elevation correction
factors had been applied to the Unit 1 instrument and that a correction factor of.
approximately 6.25 psig was required.
The condition report, based on the
methodology of calculation EC-051-0004, stated that a pump discharge pressure of
288 psig versus the 282 psig criteria, was required to demonstrate
an acceptable
level of system performance.
The team compared the latest test performance data
for both Unit 1 core spray loops to this 288 psig criterion and determined that at
least 10 psig margins remained above this value for both divisions.
The condition
report documented that the test line pressure instruments required calibration prior
to performing the next scheduled flow test.
The team found this resolution
acceptable.
0
0
Unit 2 Core S ra
Quarterl
Flow Test
Condition report 98-3070 was initiated on October 1, 1998, due to questions with
the Unit 2 quarterly flow surveillance test acceptance
criteria.
Based on discussions
with IRC Engineering, PPSL determined that the Unit 2 core spray flow surveillance
tests, SO-251-A02 and B02, had been non-conservatively adding a 7 psig
correction factor to the indicated discharge pressure reading, before comparing the
value to the acceptance
criterion of 282 psig.
However, ISC Engineering stated
that the instrument was properly calibrated and no basis existed for this additional
7 psig factor.
The failure to translate the design basis requirements correctly into
surveillance procedure acceptance
criteria constituted a second example of a
violation of design control requirements of Section III of Appendix B to 10 CFR 50.
(VIO 50-387 & 388/98005-01)
A review of the most recent completed surveillance tests indicated that for the
'A'oop
of Core Spray, 277 psig discharge pressure was achieved at 6500 gpm.
98-3070calculated
the corresponding pressure at the
required flowrate of 6350 gpm and found the pressure to be 282.3 psig. Therefore,
the actual pump performance had margin (.3 psig), albeit greatly reduced, over the
282 psig acceptance
criteria. The proposed corrective action was to revise the
tests to cor'rect the methodology.
The team found the proposed corrective actions
acceptable.
Core S ra
s stem res onse time testin
Licensin
basis assum
tions
UFSAR Table 6.3-1A (Event Scenario for 100% design basis accident suction line
break), describes,
in part, the nominal input assumptions
utilized for the co're spray
system parameters for the limiting design basis accident (DBA) recirculation pump
suction line break.
The core spray pumps were at rated speed at 40 4 seconds
after the design basis suction line break.
When the pumps 'accelerate to rated
speed and reactor pressure drops below the core spray pump shutoff head, flow will
commence to the vessel through the core spray injection valves HV-152F005A/B.
The flow through the injection lines is detected by flow switch FIS-E21'-1N006A/B,
which sends
a close signal to the minimum flow valve HV-152-F031A/8, The team
noted that UFSAR Table 6.3-1A timeline had not documented the minimum flow
valve closure assumption and, therefore, it was not clear whether the associated
diversion of flow (i.e., bypass flow) was specifically accounted for in the LOCA
analysis.
In response to this concern, on September 23, 1998, PPSL initiated condition
report 98-3010, specifically to address the discrepancy that the design basis
accident nominal input assumptions
assumed full core spray flow to the Reactor
pressure vessel (RPV) at 10.1 seconds after CSS pumps achieve rated speed,
whereas the minimum flow valve closing stroke time was 14 to 20 seconds.
CR 98-3010, concluded that the actual flow delivered to the
RPV would be greater than that assumed
in the ECCS analysis even with a
..maximum flow deficiency of 200 gallons created by the minimum flow path
diversion.
The team concurred that the minimum flow path diversion did not
invalidate the input assumption of core spray at rated flow in 50.5 seconds, found
in Table 6.3-1A. This was based on a review of diesel generator response time
tests, core spray pump start logic and the expected vessel pressure response for
the limiting suction break event.
Actual core spray injection flow would be
expected to occur at a nominal 30 seconds versus the assumed 40 second time
documented
in the DBA suction line break timeline. As such, the core flow deficit
created by the minimum flow path diversion, would be accounted for by the
additional 10 seconds of flow not taken credit for by the LOCA analysis.
Therefore,
the minimum flow path deficit was bounded by other conservatisms
in the analysis.
The team made the observation that the minimum flow path diversion, when
accounted for, reduced other conservatisms
inherent in the analysis.
PPSL, as part
of their evaluation under condition report 98-3010, stated that an action item will
be performed to review and revise, as appropriate, the SSES design and licensing
documents to assure the licensing basis is accurately characterized.
At a minimum,
the evaluation would consider a change to the SSES UFSAR to identify the
maximum allowable stroke time for the core spray minimum flow valves.
. Additionally, if any change is required to the LOCA analysis time line, appropriate
revisions will be made.
C.
Conclusion
Discrepancies identified in surveillance test procedures indicated weak engineering
support in assuring acceptance
criteria bases were sound.
The acceptance
criteria'or
Unit 1 core spray test pressure
did not take into account system configuration
differences between Units
1 and 2, even though these differences were identified in
design calculations.
The Unit 2 core spray quarterly flow surveillance test
inappropriately included a non-conservative correction factor for which no basis
could be identified. Although the consequence
of these discrepancies
did not result
in system inoperability, the above failures to incorporate the requirements and
acceptance
limits contained in applicable design documents are two examples of a
violation of Section III of Appendix B to 10 CFR 50.
(VIO 50-387 5 388/98005-01)
E2.3
Core S ra
Surveillance Test Pro ram lm lementation
Ins ection Sco
e
The inspector compared the core spray surveillance test program to system testing
requirements and performance criteria, described in the Susquehanna
Technical
Specifications (TS), UFSAR, and Inservice Test (IST) program.
To assess
how PP5L
dispositioned deficient conditions identified during surveillance testing, the inspector
reviewed a sample'of condition reports written during the performance of IST
activities.
Finally, to determine how PPS.L responded to industry events in the IST
area, the inspector reviewed what action, if any, PPRL took in response to NRC
Information Notices (IN)s that discussed
IST program issues.
Observations and Findin s
PPSL was implementing the second 10-year interval of the IST program as
described in program submittals to the NRC dated June 30 and December 29,
1974. The submittals included requests for relief from several American Society of
Mechanical Engineers (ASME) Boiler and Pressure
Vessel Code (Code) requirements,
and incorporated PPSL responses to the regulatory positions contained in Generic Letter (GL) 89-04, "Guidance on Developing Acceptable Inservice Test Programs."
.
An NRC letter, dated April 26, 1995, forwarded the safety evaluation report (SER)
which provided the results of the NRC staff's review of the Susquehanna
- program.
'he
Susquehanna
IST program was described in administrative procedure
NDAP-QA-0423, "Station Pump and Valve Testing Program."
Testing was
performed pursuant to Section XI of the Code (1989 Edition), which incorporated by
reference Parts 6 (OM-6) and 10 (OM-10) of ASME/ANSI OMa-1988 for pumps and
valves, respectively, and Part
1 (OM-1) of ASME/ANSI OM-1987 for pressure relief
devices.
Design information and test requirements for specific components, relief
requests,
and test deferral justifications were contained in detailed program plans.
Supporting technical details were contained in sub-tier procedures, calculations, and
engineering specifications.
The inspectors found the program documents to be well organized, cross-
referenced,
and readily available.
Program scope was adequate with the correct
number of core spray components included in the IST program.
Code relief requests
were well supported and implemented in accordance with program guidance.
Relief valves installed in the core spray system were tested in accordance with
.
ASME code requirements.
Test failures identified during relief valve testing, were
appropriately dispositioned.
As-part of its industry experience review program,
PPRL had appropriately considered the information contained in NRC Information
Notices including 97-90, "Use of Nonconservative Acceptance Criteria in Safety
Related Pump Surveillance Tests," and 97-09, "Inadequate
Main Steam Safety
Valve Setpoints and Performance
Issues Associated With Long MSSV Piping," for
applicability to the Susquehanna
IST program.
Conclusions
The inservice testing program for the core spray system was sound.
Program
documents were found to be well organized, with appropriate records of relief
requests, test deferral justifications and supporting technical information. Test
failures identified during relief valve testing were appropriately dispositioned.
Industry experience review program appropriately considered industry information.
E7
Quality Assurance in Engineering Activities
E7.1
Problem Identification and Resolution
a0
Ins ection Sco
e
The team reviewed PPS.L's overall program and process for the identification and
'resolution of nuclear safety issues as they related to the Operational Quality
Assurance
Program required by 10 CFR 50, Appendix B, and as described in the
UFSAR, Section 17.2, "Quality Assurance During the Operational Phase."
The team
focused mainly in two areas,
The first area reviewed involved selected portions of
the upper tier program documents, Operational Policy'Statements
(OPS) and the
Nuclear Department Administrative Procedures
(NDAP). In addition, the team
focused specifically on condition reports issued on the core spray system and other
condition reports that were generated
during the inspection period.
Focusing on
these areas, the overall performance of the problem identification program was
assessed.
b.
Findin s and Observations
Corrective Action S stem
Operational Policy Statement OPS-5, Deficiency Control System, Rev. 8, dated
4/3/98, provided the overall purpose and responsibilities of the condition report (CR)
program.
NDAP-QA-0702, Revision 4, dated 5/12/98 and Revision 5, dated
9/25/98 provided the current PPSL process for the CR Program.
The team
determined that PPSL implementation of a program to identify, correct and prevent
recurrence of conditions adverse to quality was acceptable.
However, the following
'weaknesses
were identified during the inspection.
Initiation of Condition Re orts
H
Review of approximately sixty condition reports demonstrated that the initiation
threshold was sufficiently low. However, in the previous three months, the NRC
identified two events in which PPRL did not generate
a condition report.
The first
event involved the Unit 1 Core Spray Injection Check Valve HV152F006A. This
check valve did not form a tight seal and allowed reactor pressure to slowly
pressurize the Division I core spray discharge piping. This condition started after
the recent Unit 1 startup from the tenth refueling outage and stopped pressurizing
prior to mid-September 1998. The Unit 1 Residual Heat Removal (RHR) Division I
and Division II discharge Check valves also had experienced similar problems;
however, condition report 96-2028 evaluated the acceptability of this RHR
condition.
PPSL does not plan to initiate a condition report for the Core Spray
Injection Check Valve, because this condition is no longer present.
Since no CR
was initiated on the CSS discharge piping pressurization,
no reason for the
commencement
nor cessation of the'eakage
was ever determined.
10
The second issue involved an unexpected power increase that occurred on June 26,
1998, during a startup.
In this event the reactor operator inserted
several notches to terminate the event.
A condition report was not initiated for this
event.
This event reoccurred six days later during a subsequent
reactor startup,
and the reactor tripped when two reactor operators mis-ranged intermediate range
monitors (IRMs). This event is discussed
in detail in NRC inspection report
IR 50-387 and 388/98-07.
The Operational Experience. Services Screening and Corrective Action Team (CAT)
Meetings were observed and found acceptable.
Corrective Action Reviews
The team reviewed condition reports (CRs) that were in various stages of closure to
determine whether identified issues were being dispositioned appropriately.
This
review identified two condition reports in which PPSL was slow in implementing
corrective actions to ensure the plant was within the design and licensing bases.
Low Pressure
Coolant Injection (LPCI) / Core Spray (CS) Low Pressure
Permissive Instrumentation
FSAR Section 7.6.1a.3.3.1 states that "The LPCI injection valves E11-F015
and E11-F017; and the core spray system injection valves E21-F004 and
E21-F005 are interlocked with a reactor pressure low signal which protects
the system from overpressurization
by not allowing these valves to open
until reactor pressure
is below the system design pressure."
On July 16,
1996, PP5L identified and documented
in CR 96-0905, that (1) the LPCI
injection valves may open above the system design pressure of 450 psig,
when instrument uncertainties were considered
and (2) that the nominal trip
setpoint ranges may exceed the capabilities of the installed instruments.
The
LPCI injection valves must consistently open below the RHR system design
pressure (450 psig) and above the reactor pressure
assumed
in the LOCA
analysis (Reactor Pressure of 400 psig).. CR 96-0905 concluded that the
LPCI valves could be given an open signal at a reactor pressure
corresponding to 477 psig, which is 27 psig above the RHR design pressure..
A review of past instrument calibrations determined that several of the as-
found setpoint were above the LPCI design pressure.
PPRL performed an
operability determination (OD) which concluded that opening of the
RHR'njection
valves, at a reactor pressure of 490 psig, would maintain the piping
stresses
within the code allowable stresses.
11
In June 1997, PP&L initiated CR 97-2013 to document that the previous
analysis performed under CR 96-0905 did not account for static head
pressure differences between the elevation of the LPCI/CS injection valves
and the pressure tap utilized for this low pressure permissive interlock.
CR 97-2013 concluded that the existing pressure instrumentation for control
of the LPCI/CS low pressure permissive interlock does not provide the
needed setpoint accuracy.
A second operability determination was
completed that evaluated
a new maximum pressure that could be seen in the
RHR system and 'determined that the system would not exceed code
allowable stresses.
The corrective actions for this CR include modifications
to replace the LPCI/CS low pressure permissive instrumentation.
The
modifications are 97-9075 for Unit 1 (targeted for installation'during the
2000 refueling outage), and 97-9076 for Unit-2 (targeted for installation
during the 1999 outage).
A lack of rigor in the evaluation of CR 96-0905
resulted in not identifying and evaluating at that time, the static head and
instrument accuracy issues which contributed to the potential for
overpressurizing piping connected to the reactor vessel.
This lack of rigor
resulted in a missed opportunity to implemented these modifications, which
were identified as needed for final resolution by the licensee, during the
recent refueling outages,
Core Spray Room Cooler and Residual Heat Removal Service Water (RHRSW)
Heat Exchanger Cleanliness Control
PPRL Design Basis Document DBD009- ESW, RHRSW, and Ultimate Heat
Sink, Section 2.10.4.1, discusses
the periodic inspection of heat transfer
components to ensure adequate
heat transfer capacity is maintained.
The
Core Spray Room Coolers are inspected utilizing PPSL specification H-1004-
Heat Exchanger/Condenser
Inspection and Condition Assessment
and the
RHRSW Heat Exchangers
are cleaned utilizing specification H-1001 - Heat
Exchanger/Condenser
Tube Cleaning at SSES.
On March 19, 1997, CR 97-
0771 documented that the Unit 2 Core Spray Room Coolers (2E231 A/C) did
not meet the required cleanliness requirements
as specified in specification,
H-1004, paragraph 6.6.1.1.
The cleanliness requirements were not met
because
the room cooler tubes were coated with a thin layer of a hard brown
material that could not be removed.
The operability determination for CR 97-
,0771 was weak in that it did not quantify the effects of this degraded
condition, and the final action plan documented that this condition would be
dispositioned "use-as-is" in CR 97-0980.
On March 22, 1997, CR 97-0801 documented that the Unit 2 "A" Residual
Heat Removal Service Water (RHRSW) heat exchanger (2E-205-A) did not
meet the requirements of specification H-1001, because
a brown deposit
could not be removed from the inside of the heat exchanger tubes.
The
operability determination for CR 97-0801 again did not quantify the effects
of this degraded condition, and the final action plan again documented that
this condition would be dispositioned "use-as-is" in CR 97-0980.
12
On March 31, 1997, CR 97-0980 documented that the unit 2 "B" RHRSW
heat exchanger (2E-205-B) did not meet the requirements of specification
H-1001, because
a brown scale was still present on the inside of the heat
exchanger tubes.
On June 20, 1997, PLI-83761 was issued in reference to
CR 97-0980. This document identified the brown deposits as manganese
and stated that the deposits were acceptable if the heat transfer properties
were evaluated by Nuclear System Engineering (NSE).
On June 30, 1997,
this condition report was dispositioned without (1) a "Use-as-is" disposition,
(2) an extent of condition review, and (3) a detailed evaluation of the heat
exchangers
operability. The action plan developed in CR 97-0980 only
included plans to (1) include new tooling in the future cleaning of heat
exchangers
and (2) removal of the manganese
from the previously identified
heat exchangers
by May 1999.
On September 17, 1997, Nuclear Assurance Services (NAS) initiated CR 97-
3199 to document that CR 97-0771 and CR 97-0801 were closed with the
expectation that CR 97-0980 would disposition these conditions as "use-as-
is."
CR 97-0980 documented that an acceptable
means of cleaning the
is available, but did not include a "use-as-is" disposition.
PP5L
dispositioned CR 97-3199 as "use-as-is," but did not include a 10 CFR 50.59 safety determination as required by NDAP-QA-0702, rev. 3 to review
the existing conditions against the licensing basis.
The RHRSW heat
exchanges
remained in this condition, without a detailed evaluation,
documented,
until May 1998.
In May, CR 98-1532 identified that the Unit 1
"B" RHRSW heat exchanger tube cleanliness did not meet the acceptance
criteria in specification H-1001. This CR provided a detailed evaluation of
the conditions of the RHRSW heat exchangers
and found the heat
exchangers to be operable, but degraded.
A period of approximately
14 months elapsed between the time that initial fouling of the RHRSW heat
exchangers were identified until a detailed evaluation was performed.
In
addition, a 10 CFR 50.59 review was not performed as required on "use-as-
is" dispositions in late 1997.
Conclusions
PPRL's program and process controls for the identification of conditions adverse to
quality were adequate.
The team's review of sixty condition reports indicated that
the initiation threshold was sufficiently low. However, two conditions, which were
not documented, reflected inconsistency in the initiation of condition report's.
A
pressurization of a portion of Unit 1 core spray discharge piping was not
documented
in a condition report, although a similar problem with the residual heat
removal system was documented.
An unexpected power increase was not
document in a condition report; this event was also documented
in NRC inspection
report 50-3875388/98007.
13
PPS.L's resolutions of condition reports were generally acceptable.
However, the
resolutions for two of the sixty condition reports were slow, reflecting weak
engineering support.
One issue, involving an instrument inaccuracy deficiency
identified in July 1996, was not thoroughly evaluated and required a revised
PPRL was slow in identifying actions for the final
resolution of the problem.
As a result, PPSL missed an opportunity to make
modifications, which were subsequently determined to be needed, during the last
refueling outages.
The other issue concerned the slow resolution of heat exchanger
fouling in service water systems, which was initially identified in March 1997. A
detailed evaluation of the acceptability of the heat exchanger fouling was not
performed until May 1998, after the initiation of several additional condition reports
on the issue.
E7.2
Core S ra
S stem Flow Discre ancies
ao
Ins ection Sco
e (IP 40500)
The inspector reviewed the resolution of CR 97-2874, and the corrective actions
planned for CR 98-1197, along with the information in PP5L Calculation EC-051-
0004, Rev. 2, "Core Spray Tech Spec Test Pressure."
b.
Observations
and Findin s
In August 1997, the SSES resident inspectors raised the issue that the flows from
ECCS pumps might not meet accident analysis assumed flows at the lower limit of
diesel generator technical specificatio'n allowable speed.
The pump flows would be
reduced by the lower pump speed caused by the lower frequency supplied to the
electric motors which drive the pumps.
PPSL issued CR 97-2874'to document and
evaluate the condition. Through improved technical specification engineering
research
and subsequent
calculations, PPRL determined that the minimum level of
ECCS pump performance verified by technical specification surveillance tests did
not assure that the flows assumed
in the LOCA analyses were bounded at the
lowest allowable diesel generator frequency.
The results of the evaluation of the
CSS were documented
in calculation EC-051-1006, Rev..0, "Core Spray System:
Determination of Pump Flow at Reduced Emergency Diesel Generator Speeds."
This
calculation determined that the CSS performance did not envelope the flows
assumed
in the accident analysis even at rated frequency (60 Hz). This matter was
dispositioned by PPSL through the adoption of a "licensing position" that diesel
generator governor tolerances
and instrument inaccuracies do not need to be
accounted for in accident analysis calculations, due to existing conservatisms
inherent in the Appendix K methodology, as well as the margin between best
estimate analyses
and the 10 CFR 50.46 limit on peak cladding temperature.
14
In April 1998, CR 98-1197 was issued to document the fact that PP&L had
determined even when actual pump performance at rated frequency (60 Hz) was
used, the core spray system flows assumed
in the LOCA accident analyses were
not enveloped at low reactor vessel pressures.
At the time of this inspection, the
CR was still open.
The OD for this CR addresses
both the potential flow
deficiencies for CSS and RHR system, since the calculation for the RHR had not yet
been completed.
A best estimate analysis was performed, using the methodology
of EC-051-1006, and concluded that there would be a LPCI flow above that
assumed
in the LOCA analysis, and this excess would more than make up for the
CSS flow deficit. The inspector was unable to review the methodology in EC-051-
1006, since the calculation has been canceled,
and withdrawn from the PP&L
records system.
Calculation EC-051-0004, Rev. 2, "Core Spray Tech Spec Test Pressure," was
issued June 18, 1998, to support the implementation of ITS. During the
engineering research for ITS, and that conducted to resolve CR 97-2874, the basis
of the Unit 1 technical specification CSS flow and pressure acceptance
criteria
could not be located, while PP&L determined those for Unit 2 were based on
preoperational testing results.
The calculation determined that the flow rates
assumed
in the accident analyses for the CSS would not be met in all cases
(particularly at low vessel pressures),
but would provide an interim basis for Unit 1
and 2 surveillance test acceptance
criteria while CR 98-1197 was resolved.
The
calculation stated that future revisions were probable, and that a new "licensing
basis" flow for the core spray system would be developed based on the actual
system performance.
This new "licensing basis" flow would provide the final
design and testing basis CSS test pressure,
as well as define the CSS accident flow
profile.
During review of Calculation EC-051-0004,
the inspector determined that the
LOCA analysis assumed
CSS flows of up to 8143 gpm with the reactor vessel and
drywell pressures
equalized.
The CSS DBD states that the system is orificed to limit
CSS flow to 7900 gpm, since spray sparger discharge patterns become erratic,'nd
adequate
core cooling can not be assured,
at flows above 8000 gpm per loop.
PP&L had not identified this error in the accident analysis assumptions,
only that
there was a disparity between the flow achievable by the system, and that assumed
in the accident analysis.,
The team concluded that the lack of questioning attitude,
associated with the resolutions for CR 97-2874 and CR 98-1197, reflected missed
opportunities to identify this error.
The failure to ensure the adequacy of the LOCA analysis is a violation of Section III,
"Design Control," of Appendix B to 10CFR 50, which requires that measures
be
established to ensure that the design basis is correctly translated into specifications,
drawings, procedures
and instructions.
(VIO 50-387 & 288/98005-01)
15
c.
Conclusions
The resolution of core spray flow concerns reflected a lack of questioning attitude.
PP&L missed opportunities to identify that the loss of coolant accident analysis did
not reflect the correct core spray flow in the facility's design.
The failure to ensure
that the design basis is correctly translated into the LOCA analysis is a third
example of a violation of the design control requirements of 10 CFR Part 50,
Appendix B,Section III. (VIO 50-387&388/98005-01)
E7.3
10CFR50.59 Safet
Evaluation Pro ram
aO
Ins ection Sco
e (IP 37001)
The team reviewed PP&L's implementation of the 10 CFR 50.59 Program.
This
review involved selected portions of Nuclear Department Administrative Procedures
(NDAPs).
In addition, the team reviewed core spray plant modifications, procedure
changes,
Replacement Item Evaluations and condition reports.
The team also
reviewed UFSAR changes,
previous 10 CFR 50.59 determinations and 10 CFR 50.59 determinations performed under the recently revised NDAP-QA-0726,
Revision 3.
Focusing on these areas allowed the overall performance of PP&L's
10 CFR 50.59 Program to be assessed.
b.
Findin s and Observations
Procedures
and Controls
NDAP-QA-0726, Revision 3, "10 CFR 50.59 Evaluations," and NDAP-QA-0730,
Revision 1, "Implementation and Control of Licensing Documents," provided
adequate
guidance, when combined with training, to determine if an unreviewed
safety question (USQ) existed.
These documents also clearly delineate the
.
responsibilities for various processes
within the 10 CFR 50.59 program,
In addition,
these documents provided adequate
controls for record retention and reporting the
results of 10 CFR 50.59 evaluations.
Im lementation of the 10 CFR 50.59 Process
The 10 CFR 50.59 determinations
and evaluations reviewed by the team were
adequate.
These team focused on recent 10 CFR 50.59 determinations and
evaluations associated with the core spray system and core spray support systems.
Overall, these evaluations were acceptable,
in ensuring that the technical issues
were fully addressed,
and that an adequate
engineering basis existed to determine
no unreviewed safety question existed.
16
However, the'team noted that the administrative implementation of the 10 CFR 50.59 process was found to be weak with regard to condition reports that
disposition deficiencies as "use-as-is."
Of the eight condition reports reviewed, in
which the licensee dispositioned as "use-as-is,".the team noted that six did not
contain completed forms documenting
a 10 CFR 50.59 determination or evaluation,
as required by procedure NDAP-QA-0726.
98-0839
Laminar indications found in the stainless steel cover plate on the Unit
1 RCIC Room Cooler (1E228B).
PP&L engineering determined that
these indications did not reduce the strength of the plate and were
acceptable.
98-0890
Internal cleanliness inspection on the D-1 intercooler noted a foreign
material identified as general purpose silicone sealant (RTV 102/ RTV
108) inside the air side of the cooler.
Maintenance Engineering and
the Diesel vendor concluded that this will not effect the performance
of the engine.
98-0991
During maintenance activities under work authorization (WA) No.
A70350, an unexpected wear pattern was identified on 7L and 8L
intake cams of "D" emergency diesel generator.
PPRL engineering
and the vendor concluded that these wear marks were the result of a
vendor applied coating.
There were no similar indication on other
diesel generators.
98-1 683
A review of the previous Unit 1 inspections of the H4 and H5 shroud
welds revealed that a 62 inch long crack exists in the shroud H5 weld
centered at the exact location of the vertical weld at azimuth
135 degrees.
The vertical welds have never been inspected.
The
inservice inspection (ISI) and analysis conducted at the completion of
the Unit 1 tenth refueling outage determined that integrity of
the'hroud
was acceptable.
98-1 81 5
During Scheduled
ISI inspections on Unit 1, four ultrasonic indications
analysis conducted at the completion of the Unit 1 tenth refueling
outage determined that integrity of the'shroud was acceptable.
98-2082
WA C73770 required 4 quality control verifications.
One of the four
was not verified by QC, however, field support engineering performed
the verification and determined the condition to be acceptable,
In addition to these examples,
CR 97-3199, was dispositioned "use-as-is" and did
not contain a 10 CFR 50.59 determination or evaluation.
This is discussed
in the
condition reporting section of this report.
17
PPRL initiated condition report 98-3076 to investigate this issue and determine
appropriate corrective actions.
This violation of the requirement of NDAP-QA-0726
was considered to be minor in nature, and is not being cited for formal enforcement
action.
C.
Conclusions
PPRL Nuclear Department Administrative Procedures
provide adequate
guidance to
determine if a 10 CFR 50.59 unreviewed safety question exists.
These documents
clearly delineate the responsibilities for various processes
within the 10 CFR 50.59
program and provide adequate
controls for record retention and reporting the results
of the evaluations.
The team noted several instances
in which the required 10 CFR 50.59 documentation was not completed for condition reports dispositioned "use-
as-is," as required by program procedures.
However, technical evaluations provided
bases for no unreviewed safety question.
The failure to implement the
administrative procedure for 10 CFR 50.59 evaluations is considered
a minor
violation of procedural adherence,
and is not being cited for formal enforcement
action.
V. Mana ement Meetin s
X1
Exit Meetin
Summa
'- The results of the inspection were discussed
at an exit meeting conducted at the site on
October 2, 1998.
During the inspection, some of the drawings, specifications, and calculations reviewed by
the team were identified as proprietary information. All copies of documents used by the
team were destroyed after the end of the inspection.
PARTIALLISTING OF PERSONNEL CONTACTED
Penns
Ivania Power and Li ht
G. Miller, General Manager, Nuclear Engineering
R. Pagodin, Manager, Nuclear System Engineering
M. Simpson, Manager, Nuclear Technology
T. Gorman, Project Manager, Nuclear Engineering
J.
Kenney, Supervisor, Nuclear Licensing
'R. Prego, Supervisor, Site Surveillance Services
R. Wehry, Supervising Engineer, licensing
Nuclear Re viator
Commission
W. Axelson, Deputy Regional Administrator
R. Crlenjak, Deputy Director, Division of Reactor Projects
C. Anderson, Chief, Reactor projects Branch 4
W. Ruland, Chief, Electrical Engineering Branch
K. Jenison, Senior Resident Inspector
J.
Richmond, Resident Inspector
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
~Oened
50-3875.388/98005-01
Three examples of failures to correctly translate regulatory
requirements
and design bases into test acceptance
criteria or
accident analyses.
Closed
None
Discussed
None
LIST OF ACRONYMS USED
CFR
CR
GL
GPM
IP
NRC
PPS.L
TS
WA
Automatic Depressurization
System
American Society of Mechanical Engineers
Code of Federal Regulations
Condition Report
Core Spray System
Design basis Accident
Direct Current
Essential Safeguards
Final Safety Analysis Report
NRC Generic Letter
Gallons per Minute
Inspection Procedure
Inservice Inspection Program
Inservice Testing Program
Improved Technical Specifications
Licensing Document Change Notice
Loss of Coolant Accident
Low Pressure
Coolant Injection
Nuclear Regulatory Commission
Pennsylvania Power and Light
Pounds per Square Inch, Gage
Quality Control
Residual Heat Removal Service Water
Safety Evaluation Report
Susquehanna
Steam Electric Station
Technical Specifications
Updated Final Safety Analysis Report
Work Authorization
4~
4
I