ML16154A728
| ML16154A728 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 12/16/1994 |
| From: | Peebles T, Rogers W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16154A726 | List: |
| References | |
| 50-269-94-31, 50-270-94-31, 50-287-94-31, NUDOCS 9412280118 | |
| Download: ML16154A728 (32) | |
See also: IR 05000269/1994031
Text
NUCLEA REUNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
Report Nos.:
50-269/94-31, 50-270/94-31, and 50-287/94-31
Licensee: Duke Power Company
422 South Church Street
Charlotte, NC
28242
Docket Nos.:
50-269, 50-270, and 50-287
License Nos.:
and DPR-55
Facility Name:
Oconee Nuclear Station Units 1, 2, and 3
Inspection Conducted: September 20 through November 3, 1994
Inspector:____
/"- /6
Walter G. Rogers, Team L der
Da e Si ne
Accompanying Personnel: Paul Kellogg
Larry Mellen
Larry King
Curt Rapp
NRC Consultants: D. revatte
Approved by:
Z
Tho as A. P
Da e Si gned
Op
1
--
ee-e
hDate
S4gned
Division of e ctor Safety
SUMMARY
A follow-up to the initial Service Water System Operational Performance
Inspection (SWSOPI) of 1993 was conducted on September 20 through November 3,
1994 according to NRC inspection module 37550 and Temporary Instruction (TI)
2515/118.
RESULTS
The NRC Temporary Instruction for Service Water Inspections (Safety Issues
Management System item TI 2515/118), was not closed since the licensee has yet
to accomplish a number of committed Generic Letter 89-13 actions.
Numerous corrective actions from the previous inspection had not been
adequately accomplished or completed consistent with committed schedules.
Testing of the suction source capability for the low pressure service water
pumps via the siphon mode was not adequate. Deficiencies were identified in
the operational guidance and testing of the Auxiliary Service Water system.
Also, infrastructure weaknesses persist inhibiting efforts to keep design
calculations current.
9412280118 941219
PDR ADOCK 05000269
Enclosure 2
Q
REPORT DETAILS
1. Inspection Objectives
Numerous problems identified at various operating plants in the country
have called into question the ability of the SWSs to perform their design
function. These problems have included:
inadequate heat removal
capability, biofouling, silting, single failure concerns, erosion,
corrosion, insufficient original design margin, lapses in configuration
control or improper 10 CFR 50.59 safety evaluations, and inadequate
testing. NRC management concluded that an in-depth examination of SWSs
was warranted based on the identified deficiencies.
In the original SWOPI conducted in 1993, the team focused on the
mechanical design, operational control, maintenance, and surveillance of
the SWS and evaluated aspects of the quality assurance and corrective
action programs related to the SWS. Numerous deficiencies were identified
by the team which the licensee responded to in letters on March 14, April
20, May 12 and September 1, 1994. This inspection's primary objectives
were to;
assess the licensee's progress in accomplishing the committed actions
specified in these letters,
verify whether the corrective actions resolved the identified
deficiency and did not compromise SWS performance requirements or
design bases,
assess the licensee's planned and completed (since February 1994)
actions in response to Generic Letter 89-13, "Service Water System
Problems Affecting Safety Related Equipment," and
ascertain why there were discrepancies between information provided to
the team and a recent motor operated valve inspection about LPSW
turbine building isolation valves thrust capabilities and types of
tests performed on these valves in the past.
Another issue not associated with the SWS follow-up was included as part
of this inspection. This issue dealt with a postulated feedwater piping
break within containment. The licensee had provided information and
future corrective actions to mitigate the consequences of such an event.
Therefore, another primary objective of this inspection was to understand
the licensee's present response capability to such an event and ascertain
the status of any design changes to reduce the consequences of such an
event.
The team observations and concerns identified are described in sections 3
through 7 of this report. Personnel contacted and those who attended the
exit on October 27, 1994, are identified in Attachment A. Acronyms and
abbreviations are identified in Attachment B.
Enclosure 2
Report Details
2
2. General Description of SWSs
The SWSs at Oconee encompass numerous systems. These are the CCW
(including the ECCW subsystem), LPSW, HPSW, ASW, SSF DG, HVAC, and steam
generator cooling, the SSF submergible pump subsystem, Keowee
hydroelectric station generator air, thrust bearing, packing box, and main
bearing cooling.
The CCW system is common to all three units and takes suction from the
Lake Keowee intake canal.
Twelve pumps (four per unit) supply a common
cross-connected 42-inch discharge header from which numerous other SWSs
take suction. From this header, cooling water passes through the three
condensers. Upon leaving the condensers, the water discharges through six
lines (two per unit) and returns to Lake Keowee upstream of the intake
canal.
A subsystem of CCW is the ECCW system. If the CCW pumps lose power, ECCW
actuates establishing siphon or gravity flow from the intake canal to the
42-inch header and through the condenser sections. Emergency condenser
discharge lines connect the condensers with the Keowee hydroelectric
station's tailrace. Prior to entering the tailrace, all the discharge
lines connect into one line. ECCW actuation involves the automatic
closure of the condensers' normal outlet valves, opening of the
condensers' emergency outlet valves and opening the emergency discharge
valve to the Keowee tailrace, CCW-8, located in the common discharge
piping. The high points of the ECCW piping are connected to a vacuum
priming system which would remove air entrapped within the system that
could impede siphon operation. The licensee considers CCW supplying the
LPSW pumps as the first siphon and CCW passing through the condensers as
the second siphon.
The CCW system performs two distinct safety functions during the LOCA/LOOP
event.
First, it provides a suction source for other systems including
the safety-related LPSW system, and second it provides cooling water to
the condenser to remove decay heat in the ECCW mode. The CCW pumps
contribute to these safety functions in two ways. First, when power is
lost and they are not operating, they provided a siphon conduit from the
intake canal to the CCW piping from which the LPSW takes suction, and to
the condenser for the ECCW system. Second, at the time when the pumps can
be restarted (up to 1/2 hours per emergency procedures), they continue to
provide water for these same functions. Since dissolved air will tend to
come out of solution when the system is in the siphon mode, at least one
of the CCW pumps must be operated after power is restored in order for the
water to continue to be supplied to the CCW piping.
Within the intake canal, is an underwater dam which can trap approximately
67,000,000 gallons of water if Lake Keowee were to fall below the 770-foot
level.
With the CCW pumps operating, the system is capable of
recirculating water from this impounded area, through the condensers,
through the condenser emergency discharge lines and through normally
closed valve, CCW-9, which discharges into the intake canal.
Enclosure 2
Report Details
3
The LPSW system provides cooling to the RBCUs, LPI coolers, the motor and
turbine driven EFW pump coolers, HPI pump motor coolers, the control room
chilled water system, numerous room coolers, and nonsafety-related turbine
building loads. Units 1 and 2 share three 15,000 gpm pumps with one pump
capable of being powered from two separate safety-related busses. The
Unit 3 LPSW system has two 15,000 gpm pumps. The LPSW pumps take a
suction from the 42" CCW discharge header within the turbine building.
The Unit 1/2 LPSW pumps discharge into a common header that splits into
two supply lines; one supply line for each unit. The unit supply lines
further divide into two separate headers supplying the two trains of
safety-related equipment. The two equipment supply lines then
interconnect into a common line which enters containment. This common
line then splits into three parallel lines; each line supplying one RBCU.
These three RBCU supply lines reconnect into one line on the discharge
side of the RBCUs before exiting containment. Also, branching from the
common discharge header is a supply line to the turbine building loads.
The turbine building supply line then splits to provide cooling to each
unit's turbine building equipment. The Unit 3 RBCU and turbine building
cooling arrangement is similar. A normally closed crosstie line allows
either LPSW system to supply the discharge header of the other LPSW
system.
The HPSW system normally functions as the site's fire protection system.
The system is composed of three pumps, an elevated storage tank, and
- interconnecting
piping to fire protection deluge valves throughout the
site and to the CCW pumps. The three pumps, two 6000 gpm capacity and one
jockey, take suction from the 42" CCW discharge header. The jockey pump
maintains system pressure. The other two pumps are to make up lost water
inventory in the 100,000 gallon capacity elevated storage tank. The
system constantly supplies cooling and sealing water to the CCW pumps.
The system is capable of supplying cooling water to specific components
normally cooled by the LPSW system such as the HPI pump motor coolers and
the EFW pumps. Though at reduced capacity, the system can provide backup
cooling to the LPSW system through interconnections at the discharge of
the LPSW pumps.
ASW is a system common to all three units. It is designed to provide
cooling to the steam generators. The system was originally designed for
the loss of the intake canal/structure. However, following NUREG 0737
review of the facility for tornado vulnerabilities, the system was
credited in the July 28, 1989, NRC SER to mitigate the consequences of a
tornado. The system can supply cooling water to the high pressure
injection pump motors if the low pressure service water system is
unavailable. The ASW system consists of a suction connection to the unit
2 CCW system at elevation 759.5, a low head, high capacity pump, piping,
and manual valves connected to the emergency feedwater piping in the
penetration rooms of all three units. The ASW pump is operated from the
safety-related Aux Service Switchgear, and the alignment to the SGs is
accomplished manually.
Enclosure 2
Report Details
4
The SSF is a separate onsite building housing the necessary equipment to
maintain all three units in a safe shutdown condition following turbine
building flood, fire, sabotage, and certain classes of tornados or station
blackout. The SWS portion of the SSF is composed of a high head, low
capacity pump and interconnecting piping to all steam generator EFW
discharge lines, solenoid operated flow control valves in the discharge
lines to the steam generators, a pump and piping to cool a tandem diesel
with a common generator, two pumps with a condenser unit to cool the HVAC
within the SSF, and a moveable submersible pump. The SSF ASW, HVAC, and
DG pumps take suction from the Unit 2's CCW pump's discharge header. The
HVAC and DG pumps discharge to the CCW header. There is an option to
divert the DG pump discharge water to the yard drainage system when high
temperature constraints warrants. The submersible pump allows
replenishment of the CCW header from the intake canal.
Lake Keowee is the motive and cooling source for the two hydroelectric
generators which function as Oconee's onsite emergency power. Water flows
from a common penstock, through the turbines and into the tailrace.
Cooling flow comes from a single pipe located in the penstock. Once the
line enters the building housing the hydroelectric units it splits into
two lines, one for each unit. Cooling flow for the turbine bearing oil
cooler, the stuffing box, eight thrust bearing heat exchangers, and six
generator air coolers comes from the unit specific main line.
.
3. Follow-up on Previously Identified Items
The team reviewed all outstanding violations, unresolved items, and
inspector follow-up items identified in the original SWSOPI. For
violations, the corrective actions described by the licensee were
evaluated for adequacy and completeness. The team reviewed whether the
implementation of the corrective actions were accomplished within the time
frames specified by the licensee's NOV response and strengthened the
licensee's QA program procedures or practices to prevent recurrence. If
the corrective action deadline had not occurred, the status of licensee
efforts was ascertained. Unresolved items were updated or dispositioned
depending upon the status of NRC review of these matters. The team
continued to evaluate the matters selected for inspector follow-up. The
status of licensee efforts in these matters also were ascertained. The
team reviewed all matters to ensure the generic implications, if
applicable, were addressed. Inspection findings were:
a. (Open) DEV 50-269, 270, 287/93-25-01 (Deviation A in NRC Inspection
Report 93-25), "Failure to Adequately Perform SWS GL Actions." The
licensee's original response to GL 89-13 was not inclusive of some of
the systems utilizing service water.
In response the licensee indicated a revised response to the GL would
be submitted by September 1, 1994. Included in the September 1, 1994
GL response would be those actions necessary to deal with Keowee
stagnant or intermittent flow. In addition, a schedule for
implementation of modifications and testing of Keowee heat exchangers
Enclosure 2
Report Details
5
would be provided by September 1, 1994. Finally, operating procedures
were created for the Keowee thrust bearing oil heat exchangers and the
generator air coolers by February 4, 1994.
The revised GL response was submitted by September 1, 1994. However,
there were numerous omissions and inadequacies associated with this
response. Therefore, the licensee continues to have not fully
responded to the GL. The omissions and inadequacies outstanding are:
Action I - No date was provided as to when the CCW system
hydraulic model would be benchmarked. No date was provided as to
when the HPSW system hydraulic model would be benchmarked. The
frequency of simultaneous SSF SWS pump testing was not specified.
Action III - No administrative controls existed to ensure the
committed inspection program for the SSF, ASW, and Keowee SWSs
would be accomplished. System engineers interviewed who were to
do the inspection program were unaware of their inspection
responsibilities. There was no criteria by which to judge piping
condition acceptability. Also, no technical bases for the
adequacy of the piping inspection program in terms of scope,
frequency, or corrective action could be ascertained.
Action IV - No date was provided as to when the Keowee single
failure analysis would be completed.
Action V - The GL response referenced a Duke Power Company letter
to the NRC dated April 20, 1994, as providing the discussion on
procedures and training. However, this letter was not applicable
to Action V. Also, the presently docketed correspondence on this
matter indicated that SWS procedures were receiving a two-year
review. This was not correct. The licensee had revised their
procedure review cycle to as long as every six years following a
change to their QA plan.
As indicated above, the licensee's corrective actions to the deviation
included the creation of operating procedures for Keowee thrust
bearing oil heat exchangers and the generator air coolers. However,
the newly created Keowee operating procedures omitted numerous valves
in the Keowee SWSs. These valves included all the generator thrust
bearing cooler inlet valves, and drain valves WL-1, 2, 5, and 6 for
both units.
10 CFR 50, Appendix B, Criterion XVI, "Corrective
Action," requires, in part, that measures be established to assure
that conditions adverse to quality are promptly identified and
corrected. The licensee had developed procedures, but they were not
complete. Failure to adequately correct this condition adverse to
quality is an example of Violation 50-269, 270, 287/94-31-01A,
"Inadequate Corrective Action Controls."
Enclosure 2
Report Details
6
.
b. (Closed) URI 50-269, 270, 287/93-25-02, "Turbine Building Isolation
Single Failure Vulnerabilities."
The licensee's original SER stated that the plant was designed such
that no single failure would prevent safety system functionality in
the event of a LOCA and a LOOP caused by a seismic event. NRC
reviewed the licensee's original SER and because seismic event is a
qualification standard and not an event that requires mitigation,
interpreted that single failure did not apply to seismic event.
Because the reactor coolant system was seismically qualified, a
seismic event did not result in a significant challenge to core
cooling capability. Additionally, NRC credited the SSF as providing
the same safety function as LPSW in the licensee's EFW SER. Based on
NRC's interpretation of seismic event as a qualification standard and
NRC's credit of the SSF in the licensee's EFW SER, no further licensee
action is required. This item is closed.
c. (Open) VIO 50-269, 270, 287/93-25-03 (Violation B in NRC Inspection
Report 93-25), "Failure to Perform Adequate Calculations and
Evaluations to Support Facility Design."
There were seven parts
associated with this violation.
(1) In Item 1, the NPSH of the LPSW pumps was not adequately
considered as a design input in that calculation OSC-5019 was
accepted by the license's engineering personnel with inadequate
NPSH and inadequate technical justification.
The licensee contested this example of the violation.
To better understand the safety significance associated with this
matter the licensee performed a PRA of the conditions necessary
to have inadequate NPSH. The analysis indicated the event was
not a significant accident precursor. However, the information
provided by the licensee in their docketed correspondence
continued to indicate that there was inadequate consideration of
net positive suction head as a design input for the Low Pressure
Service Water pumps. This matter remains open.
(2) In Item 2, no administrative control existed to assure the LPSW's
pump flows used as hydraulic computer model input for the LPSW
system remained valid during quarterly testing of the LPSW pumps.
The licensee responded that the test procedures for LPSW and
other select systems, which do not have clear test acceptance
criteria for pump performance, would be revised by September 1,
1994. In the procedure revision system, engineers would compare
quarterly pump test data, along with full system flow test data,
against computer models and other calculations to ensure the
validity of design basis analyses.
Enclosure 2
Report Details
7
The licensee had included guidance in the quarterly LPSW pump
test procedure ensuring the test results did not invalidate the
hydraulic model.
Discussions with the system engineer indicated
this guidance would be removed and the LPSW pump curve used in
the hydraulic model degraded. The amount of degradation would be
determined by reviewing the decrease in LPSW pump performance
data based on the previous 10-year trend. The quarterly LPSW
pump test acceptance criteria will be modified to reflect the
LPSW pump degradation used in the hydraulic model.
This
violation example is closed. However, transition from the test
procedure to the hydraulic model is considered an Inspector
Follow-up Item 50-269, 270, 287/94-31-02, "Hydraulic Model
Controls Transition."
(3) In Item 3, the commercial grade evaluation for Belzona as a
suitable material for application to the Unit 2 Reactor Building
Cooling Unit tubes was inadequate.
In response the licensee documented that an effort was underway
to obtain dynamic material property data and to analyze Belzona
for usage under cyclic loading and LOCA conditions by
December 16, 1994. Also, a modification to replace the RBCU
cooling coils had been completed on U3 and Ul, and was currently
underway on U2.
The licensee was continuing to analyze Belzona with the targeted
completion date of December 16, 1994. Also, the RBCU cooling
coils had either been replaced or were being replaced during the
inspection period. This example remains open pending completion
of the licensee's Belzona analysis.
(4) In Item 4, the design basis of the ECCW system was not adequately
translated into design documents in that the calculations
supporting ECCW decay heat removal capability did not include
numerous aspects of the design that would reduce decay heat
removal capability.
Two calculations were involved. The first calculation was OSC
2346, "ECCW System Performance Evaluation."
This calculation was
generated to show that the main condenser in the ECCW mode had
the capacity to transfer the required decay heat without
exceeding the condenser pressure limits or causing flashing on
the CCW side which could cause loss of siphon. The initial
inspection report noted that this calculation contained several
non-conservatisms. As partial response to the violation example
the licensee revised the calculation on September 29, 1994
(Rev. 5).
The new calculation was poorly performed and contained new errors
or did not completely address the original concerns. These
deficiencies included:
Enclosure 2
Report Details
8
I
On page 32o, the specific volume of air was used in a
computation to determine the amount of air that would come
out of solution. The value used was IL/kg - the correct
value for water, but not for air. The specific volume of
air at one standard atmosphere is 847L/kg. Therefore, the
result was non-conservative by a factor of 847. When this
was brought to the responsible engineer's attention, he re
reviewed the calculation and found that in the computation
of the dissolved air on page 32n, there was another
offsetting error in the number of gram moles/liter by a
factor of 502. The net result was that the air coming out
of solution, before correction for other non-conservative
factors, increased from 940 ft3 to 1,590 ft3.
Per the
calculation, the non-conservative limit on outgassing was
1,584 ft3 . Therefore, this result was unsatisfactory.
In subsequent discussions with the licensee the reason for
the gram moles/liter error was due to an incorrect
reference. The team inquired what actions had been taken by
the licensee to deal with the ramifications of such an error
and whether the matter had been identified as a condition
adverse to quality. The licensee responded that the
chemistry section (where the reference had been acquired)
had been contacted but, no PIP had been initiated. The
licensee personnel stated that they were waiting to
understand all the problems associated with this calculation
before initiating a PIP.
"
Outgassing of the CCW water had not been accounted for in
the calculation initially reviewed by the team in 1993. The
revised calculation did consider outgassing but not
completely. Specifically, the calculation only considered
the outgassing effects due to the increase in temperature as
the CCW water passed through the condenser; it did not
consider the outgassing due to the reduction in pressure due
to the siphon effect. Also, the calculation did not
consider the expansion of the air after it had outgassed due
to the reduction in pressure from atmospheric, again, due to
the siphon effect.
On page 32m, the revised calculation determined the
allowable volume of air to be outgassed based on the volume
of the condenser waterboxes above the ECCW outlet piping.
This computation was based on the height from the top of the
waterbox to the centerline of the outlet pipe, 7 feet. It
should have been to the top edge of the pipe, 6.5 feet,
which is the point where the pipe would begin to be
uncovered. This reduced the allowable outgassing volume by
7.1 percent from what was calculated.
The revised calculation did not reconcile competing
assumptions associated with the number of available tubes in
Enclosure 2
Report Details
9
the condenser for heat transfer. The revised calculation
assumed one condenser section was out of service. However,
1/2 of a section can be taken out of service under operating
procedures without engineering involvement. Further tube
reduction can be accomplished by tube plugging and Amertap
ball clogging. The licensee responded that only 4.5 percent
(approximately 700 tubes) were plugged, and this would
produce an insignificant effect. This response only
accounted for the tubes that had been taken out of service
and those which the licensee felt might trap the Amertap
balls due to denting or other damage. In generating that
number, the licensee did not consider that in the siphon
flow mode the differential pressure across the condenser
would be extremely low compared to normal operation
sufficiently low that none of the Amertap balls were likely
to pass through the tubes. Therefore, all of the balls
which entered the inlet waterbox would potentially plug
tubes. The licensee had not verified that the assumed out
of service condenser section would compensate for the other
non-conservative mechanisms capable of reducing the number
of tubes for heat transfer.
The original calculation assumed an even flow split to all
three condensers, whereas the piping configurations were
significantly different for each condenser; therefore, this
assumption was not necessarily valid. This assumption
continued in the revised calculation. The licensee
responded that the three units displayed similar condenser
flow values which are considerably higher than the required
flow value. However, the data cited is not for conditions
similar to the conditions described in the calculation;
i.e., flow through all three of the condensers at the
minimum flow rate. Therefore, the conclusion was not
supported by relevant data.
The responsible engineer stated the calculation would be re
performed making the appropriate corrections and also taking into
consideration a number of significant conservatisms that had not
been considered before. Revising the calculation is considered
Inspector Follow-up Item 50-269, 270, 287/94-31-03,
"Reperformance of Calculation OSC-2346."
The second calculation was OSC-2349, "CCW Intake Piping Degassing
in the ECCW Mode."
The calculation was performed to verify the
CCW system's "first siphon" capability for the four-hour SBO
event. It considered the air inleakage into the system and air
outgassing from the water that would tend to break the siphon,
and it established the acceptance criteria for the ECCW system
flow test. The initial inspection report noted that this
calculation contained several discrepancies and nonconservatisms
Enclosure 2
Report Details
10
as well as several conservative assumptions; the net effect of
which could not be determined without a rigorous re-performance
of the analysis.
In the response letter of May 12, 1994, the licensee stated that
this calculation was intended to be applicable for the SBO event
only, and not for the LOCA/LOOP event; a separate calculation
would be generated to analyze that scenario. Therefore, the
30,000 gpm flow assumed for this calculation was appropriate. It
was also stated that the calculation's use of the incorrect
atmospheric pressure would have an insignificant effect on the
analysis. Therefore, no changes were required.
Considering this response, the licensee had no analysis or test
which verified the "first siphon's" design basis safety function
for events involving LOOP such as the LOCA/LOOP event (90,000 gpm
for 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />) during the initial inspection. Subsequently, a
new calculation was generated (OSC-5670, Rev. 1, March 17, 1994,
"Required Number of CCW Intake Flow Paths") to provide the
analytical basis for the "first siphon" for the LOCA/LOOP event.
This new calculation revealed a new requirement for the system
configuration to support the design basis conditions; at least
two CCW pump discharge valves on the same eleven foot CCW piping
section were required to meet the siphon flow requirements.
Also, the new calculation contained the following minor
deficiencies which were discussed with the responsible engineer
and were found to have no effect on the results. The responsible
engineer indicated the required revisions would be made to
correct these deficiencies. The deficiencies were:
The test data used as benchmark data in the calculation was
of questionable validity. However, the team reviewed
additional test data which appeared to be valid and would
provide appropriate benchmarks.
The calculation did not address the differences in water
temperature and flow rate between the test data used as
benchmark cases and the design basis case. Although this
left the calculation incomplete, the effects appeared
minimal.
Further team review as to the confirmation of the new calculation
via testing did not exist. There was a test that acquired test
data that would be imputed into the LPSW hydraulic model.
However, this test did not contain acceptance criteria associated
with first siphon performance. Therefore, the test data was not
evaluated as to whether the siphon would operate in the most
demanding design bases conditions (lowest lake level, highest
required flow, etc.).
Also, the first siphon test did not assure
proper protection from air intrusion via a pump flange connection
Enclosure 2
Report Details
11
normally underwater. This connection would be uncovered at lower
acceptable lake elevations. The only other test procedure
associated with the ECCW system verified only the second siphon,
not the first, with all test acceptance criteria associated with
the second siphon.
Independently, the licensee had identified that the ECCW system
testing did not accomplish the technical elements of the team's
findings. However, the licensee viewed these deficiencies as
areas for improvement to the present testing, not as
deficiencies. This position was partially based on the
licensee's belief that the Technical Specifications did not
require a test of the first siphon capability of the ECCW system.
Technical Specification Surveillance Requirement 4.1.2, table
4.1-2, item 7, specifies a condenser cooling water system gravity
flow test be performed each refueling. 10 CFR 50, Appendix B,
Criterion XI, "Test Control," requires, in part, that operational
test procedures demonstrate systems and components will perform
satisfactorily within the acceptance limits contained in
applicable design documents.
"Instructions, Procedures, and Drawings," requires, in part, that
activities affecting quality shall be prescribed by procedures
which include appropriate quantitative or qualitative acceptance
criteria. Failure to perform a test that included the first
siphon as part of the test acceptance criteria and assuring that
such acceptance criteria bounded the acceptable operating range
of the ECCW first siphon is Violation 50-269, 270, 287/94-31-04,
"Inadequate LPSW Suction Source Testing Via the ECCW System."
(5) In Item 5, the design basis of the CCW's system capability to
withstand loss of Lake Keowee was not translated into any design
document.
In response the licensee indicated that a "loss of lake" analysis
would be performed and completed by June 1, 1995. The team
confirmed the licensee had targeted June 1, 1995, for completion
of the analysis.
(6) In Item 6, the design basis of the LPSW's system capability to
function as described in Case B of Abnormal Procedure
AP/1/A/1700/13, "Loss of Condenser Circulating Water Intake
Canal/Dam Failure," Step 5.5.1, was not translated into any
design document.
During this follow-up inspection, the licensee stated that the
analysis had not been started, pending completion of the heatup
analysis of the pond area for the loss-of-dam event (see part E
above).
This was based on the assumption that the latter
analysis was required for input to the former. The team pointed
out that these two heatup conditions occur in completely
different time frames - the former over a period of minutes, or
Enclosure 2
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12
at most hours, the latter over a period of days. Therefore, the
LPSW heatup analysis could be performed starting with the initial
conditions of the pond, and could be performed in parallel with
the pond heatup analysis. The licensee indicated the analysis
would be completed by June 1, 1995.
(7) In Item 7, the design basis of the SSF ASW system capability to
remove decay heat was not adequately translated into design
documents in that a minimum flow less than required by 23 gpm per
steam generator pair was established in calculation OSC-4171.
The calculation had been revised and this concern has been
corrected.
In summary, Items 2 and 7 were closed. All other items remain open
pending licensee actions.
d. (Open) VIO 50-269, 270, 287/93-25-04 (Violation A in Inspection Report
93-25), "Inadequate Evaluation of Conditions adverse to Quality by
Engineering." There were two parts associated with this violation.
(1) In Item 1, the evaluation of PIP 92-454 for a postulated water
hammer within the LPSW piping downstream of the RBCUs did not
include the consequences on the structural integrity of the
piping.
In response to the violation, PIP 93-1031 was written and OSC
6020 performed indicating turbine building flood was the bounding
event. To eliminate the water hammer a flow orifice would be
installed downstream of the potential cavitation and a schedule
for modification implementation would be provided by September 1,
1994.
The provided documentation indicating projected orifice
installation at the next respective refueling outages. However,
the documentation also indicated that corporate engineering had
been requested to conduct detailed computer analysis to determine
if the water hammer would occur on the discharge of the RBCUs.
Based on corporate engineering results, the discharge from the
RBCUs was determined to always be in a condition of two-phase
flow. Any waterhammer would be dampened by the two-phase state.
Therefore, installation of a flow orifice to increase downstream
pressure would have the detrimental effect of eliminating the
dampening effect of the two-phase state. The results of these
tests were to be available at a later date.
(2) In Item 2, the evaluation for corrective action to design study
ONDS 327 and Problem Investigation Report 92-084 of the
postulated response of the HPSW system to the maximum
hypothetical earthquake did not include spurious fire protection
component activations. In response to the violation, the
Enclosure 2
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13
licensee stated calculation OSC-2280,"LPSW NPSHa and Minimum
Required Lake Level," was revised to account for HPSW system
malfunction. Consequently, SLC 16.9.7 was revised.
The team confirmed the calculation had been performed and the SLC
revised. Also, the licensee indicated that the deluge valve had
been included in the components to be qualified via SQUG.
Item 1 of this violation remains open pending orifice installation or
completion of additional analyses showing the orifices are not
required.
Item 2 is considered closed.
e. (Open) IFI 50-269, 270, 287/93-25-05, "Additional Validation of RBCU
Evaluation Inputs."
There was two inputs in question dealing with
LPSW flow orifice accuracy and assumptions on air flow distribution
The licensee reinstalled the flow orifices after replacing the RBCUs
in all units. The team inspected the piping that was replaced on the
inlet and outlet of the RBCUs for Unit 1 and determined that the
corrosion buildup was minimal. A review of the calculations to show
that the new coolers were operable used data from the cooling water
side to calculate the heat removal capability. It was as.sumed that
the heat removal was the same for the air side and this was used to
calculate the air flow. The team's review of the calculations showed
that there was adequate margin in the coolers' heat removal
capability.
The team observed licensee attempting to take air flow measurements
during the current refueling outage but the attempt was poorly
coordinated and not accomplished. The licensee stated air flow
measurements would be obtained during the next refueling outage. This
inspector follow-up item remains open pending the licensee acquiring
the air flow data.
f. (Open) IFI 50-269, 270, 287/93-25-06, "Actions to Improve Operator
Responses to Abnormal Events." There were three parts associated with
this item.
(1) In part A, the prerequisite for the total loss of LPSW was no
LPSW pump operating; not inadequate LPSW flow. The licensee
revised the prerequisite of the procedure with no problems
identified.
(2) In part B, Abnormal Procedure AP/1/A/1700/13, "Loss of Condenser
Circulating Water Intake Canal/Dam Failure," had several
weaknesses. The licensee generated PIP 0-094-0514 to revise the
procedure and improve operator training to address these
, concerns.
Operator training had been revised and taught to the 1994-95
licensed reactor operator and senior reactor operator class.
Also, other licensed operators would be taught during the 1994-95
Enclosure 2
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14
PTRQ classroom training. The procedure revision was scheduled to
be completed by November 30, 1994.
(3) In part C, potential weaknesses in the operator guidance for
response to a severe tornado were identified. The licensee
indicated that a tornado would be considered as part of an
upcoming exercise to ascertain whether further operator guidance
was warranted.
In summary, part A is closed. Part B will remain open until the
revision to Abnormal Procedure AP/1/A/1700/13, "Loss of Condenser
Circulating Water Intake Canal/Dam Failure," is issued. Part C will
remain open until the exercise is accomplished and any additional
guidance provided.
g. (Open) VIO 50-269, 270, 287/93-25-08 (Violation D in NRC Inspection
Report 93-25), "Inadequate SSF and ECCW Testing."
There were three
parts associated with this violation.
(1) In Item 1, ECCW flow test procedure PT/1/A/0261/07 did not
account for the potential + 2,000 gpm error which could result
from the method used to measure flow - observation of the impact
point of the ECCW discharge flume.
In response the licensee committed to produce an analysis by July
1, 1994, and incorporate its results in the test procedure by
August 1, 1994.
A revision to the analysis, OSC-5629, "ECCW Test Acceptance
Criteria Inputs," was issued on July 13, 1994. There were no
technical discrepancies associated with the new analysis.
However, the results were not incorporated into the test
procedure at the time of the follow-up inspection. The licensee
stated that they had intentionally delayed incorporation until
just before the next required procedure performance at the next
refueling outage so that all other ensuing changes can be
incorporated at the same time in one overall revision. The NRC
had not been informed of the implementation schedule change. The
licensee indicated a letter would be submitted on the schedule
change.
(2) In Item 2, the preoperational test program for the SSF's SWS and
the post-construction flushing procedure for the SSF's discharge
lines to all the SGs were inadequate.
In response the licensee committed to performing reverse flow
testing of each unit's SSF ASW supply piping. Adequate flush
velocities would be achieved during the testing along with water
samples to verify the flush was adequate.
Procedures were revised and the first test (Unit 1) had been
completed. The preliminary results appeared to address the
Enclosure 2
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15
initial concerns. There was provision for assuring the
velocities would be adequate and that condensate would be used to
flush the lines. The procedure also had steps to ensure that the
condensate flow out of sample lines were clear. Also, the
licensee had replaced the SSF feedwater control valves and added
bypass valves to assist in the control of the SSF feedwater flow
to the steam generators. The modifications appeared adequate.
(3) In Item 3, "Periodic Safe Shutdown Facility Auxiliary Service
Water Pump Operability Test," PT/O/A/0400/05, was not performed
under suitable environmental conditions in that the pump was
preconditioned in step 12.2 by venting the pump just prior to it
being started.
In response the licensee committed to eliminate the
preconditioning from the procedures by September 1, 1994. The
team verified the procedure had been adequately revised.
In summary, Item 3 is closed.
Items 1 and 2 remain open pending
completion of corrective action by the licensee.
h. (Closed) IFI 50-269, 270 ,287/93-25-09, "CCWPump NPSH Information."
The initial inspection report noted incomplete documentation of the
NPSH requirements and availability for design basis conditions for the
CCW pumps for the Keowee Dam failure event.
The licensee provided three letters from the pump manufacturer, one
dated June 29, 1967 and two dated July 3, 1967, which had been
discovered after the initial inspection when a vendor letter dated
February 16, 1968, had been provided. These verified the capability
of the pumps to operate at conditions down to lake elevation 770' (the
elevation of the top of the impounded pond weir) and 90'F (the design
temperature for plant components served by LPSW), and down to 767' at
an unspecified temperature, without NPSH problems. This information
encompassed the LOOP/LOCA situation. The licensee indicated there
would be additional attempts to obtain more definitive information
from the vendor on the minimum NPSH requirements.
However, the worst case design basis conditions of available NPSH were
for the loss-of-Lake Keowee event which produced the lowest intake
level and highest intake temperature. This event begins with the
level at the top of the weir and the water at the design maximum
temperature. During the event, the level decreases due to evaporation
and seepage from the impounded area, and the temperature increases as
the CCW water is recirculated to the impounded area carrying the plant
decay heat. The analyses of this event will be completed in response
to Violation 50-269, 270, 287/93-25-03F. Therefore, the acceptability
of the CCW pump NPSH requirements will be reviewed in conjunction with
the completed licensee analysis.
Enclosure 2
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16
i. (Open) DEV 50-269, 270, 287/93-25-10 (Deviation B in NRC Inspection
Report 93-25), "Inadequate HPSW SBO Test."
The test did not properly
establish initial testing conditions and provided weak guidance when
problems were identified. In response the licensee committed to
revise the test procedure.
The test procedure had been revised, and all but one initial issue had
been addressed. For the condition of a severely leaking HPSW pump
discharge check valve, the updated procedure still directed the
operator to isolate the faulty valve and allowed the test to proceed
and the results to be accepted, when the test would not have passed
with the valve un-isolated. The PIP contained a statement that "The
test can continue with the leaking check valve isolated", and a note
still existed in the procedure to make an entry in the turnover sheets
to inform the Operators to shut the affected pump's discharge valve
upon loss of power to prevent excessive losses of the EWST, implying
that a leaking check valve was acceptable with regard to the test
results. As noted in the original inspection report, this is not
acceptable since it is not reasonable to expect that an operator would
isolate the valve before excessive losses from the EWST could have
occurred in an actual SBO event. Numerous, complex operator actions
are necessary to respond to an SB0 event. The guidance for performing
the isolation is not contained in an emergency procedure but on a
rounds checklist.
This deviation remains open pending appropriate resolution to a
leaking HPSW pump discharge check valve when performing the test.
j. (Closed) IFI 50-269, 270, 287/93-25-11, "Jocassee Dam Failure IPE."
Inaccuracies:
contrary to the IPE submittal the SSF could not
withstand the postulated external flood. Also, IPE Submittal report,
Section 3, Subsection 13, indicated there was an 8' waterproof flood
wall around the SSF ground level entrances. The wall was actually 5'
in height.
The licensee stated a supplemental response to the IPE on external
events in 1995 would include re-analysis of risk impact of external
flood. Also, further enhancements would be evaluated as a result of
this re-analysis.
The licensee had not completed the analysis of the Jocassee dam
failure. Calculation OSC-5781, "USQ Evaluation for Change in FSAR
Concerning SSF and Jocassee Flood," provided the justification for
changing the FSAR. The change removed the requirements of SSF
mitigation for a rapid Jocassee Dam failure. This was based, in part,
on PRA data, IPE information, and other information submitted to the
Commission. The revised IPE will be reviewed by the NRC as part of
the external events IPE submittal.
This item is closed.
Enclosure 2
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17
k. (Open) VIO 50-269, 270, 287/93-25-12 (Violation C in NRC Inspection
Report 93-25), "SWS Procedure/Drawing Content or Procedure
Implementation Inadequacies." There were five parts associated with
this violation.
(1) In Item 1, engineering administrative procedures did not
establish a definitive length of time for revising calculations
following design changes.
In the licensee's original response to the violation the licensee
stated that Procedure EDM-101, Engineering Calculations/Analysis,
would be revised to provide the necessary guidance by September
1, 1994. However, in a letter dated September 13, 1994, almost
two weeks beyond the committed dated, the licensee stated that
the plant modification process would be revised by November 1,
1994, to provide the necessary guidance.
The original inspection finding dealt with calculations
associated with the SSF SWSs. With regard to these, many of the
older calculations have been deleted. Some calculation revisions
are on hold while the DBD is being completed. This is scheduled
for mid-1995.
The definition of design documents to be updated with a facility
change had been modified to include affected design calculations.
However, the infrastructure to implement the requirement did not
exist. Other than engineer memory, there was no method to
identify all other calculations affected by the calculation
needing revision. Even if recognized by the engineer, there was
no method to flag that a calculation needed revision. Also, a
calculation could be revised without using the administrative
requirements of the facility change process. Further licensee
actions were necessary to reasonably assure administrative
requirements were properly implemented. This violation remains
open pending such corrective action.
(2) In Item 2, no flow instruments existed to confirm 200 gpm was
being provided to each steam generator or 400 gpm to an un
isolated steam generator by the Auxiliary Service Water pump as
directed by Emergency Procedure EP/1,2,3/A/1800/01, Section 502.
In the response to the violation, the licensee stated the
emergency procedure would be revised and training on the
procedure revision completed by October 1, 1994.
The procedure was revised by the committed date. However, step 7
of the procedure controlled flow via the recirculation valve.
Such an action could not actually control flow to all the units
or SG pairs.
10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures,
and Drawings," requires that activities affecting quality shall
Enclosure 2
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18
be prescribed by documented instructions, procedures, or
drawings, of a type appropriate to the circumstances. Failure to
provide adequate procedural direction to accomplish this task is
violation 50-269, 270, 287/94-31-05, "Inadequate ASW Procedure."
However, the licensee had previously identified the error and was
in the process of revising the procedure. This violation will
not be subject to enforcement action because the licensee's
efforts in identifying and correcting the violation meet the
criteria specified in Section VII.B of the Enforcement Policy.
(3) In Item 3, Keowee Turbine Generator Cooling Water system
drawings, KFD-100A-1.1 and KFD-100A-2.1 did not indicate the
existence of an additional valve downstream of valve 2WL-3 for
Unit 2, the supply line to the air compressor coolers was
interconnected to the 12" main piping for Unit 1, the piping
downstream of valve WL-76 was copper for both Units, or a
consistent piping class break in the supply line to the generator
thrust bearing coolers for both Units.
In the response to the violation, the licensee stated PIP 0-093
0986 was initiated to address these items. Also, the drawings
would be re-verified by walkdown with all identified errors to be
corrected by July 1, 1994.
The KFD-100A-1.1 and KFD-100A-2.1 drawings had been revised in
July 1994. A walkdown of select Keowee mechanical systems with
the revised drawings reflected an additional valve downstream of
valve 2WL-3 for Unit 2 not shown on the drawing. This was one of
the original discrepancies documented in the Notice of Violation.
The team determined through interview with the engineering
personnel involved in the resolution of the PIP that only a
partial walkdown of the service water mechanical systems was
performed through verbal mis-communication. Also, the drawing
editorial change process was used to update the drawings which
contained a limited check for accuracy of the walkdown
activities.
Once the licensee was notified of the drawing discrepancy by the
team, the additional valve downstream of valve 2WL-3 was removed.
However, the licensee failed to adequately correct the design
document error in July 1994 or adequately perform a walkdown of
the mechanical systems.
10 CFR 50, Appendix B, Criterion XVI,
"Corrective Action," requires conditions adverse to quality be
promptly identified and corrected. This is considered an example
of Violation 50-269, 270, 287/94-13-018, "Inadequate Corrective
Action Controls."
(4) In Item 4, a condition adverse to quality report dealing with the
removal of the Keowee Unit 2's turbine guide bearing oil cooler
was neither properly processed nor did it receive a written
operability evaluation.
Enclosure 2
.
Report Details
19
In response to the violation, the licensee stated an operability
evaluation would be completed on the ramifications of removing
the oil cooler from service without declaring the unit inoperable
by November 1, 1994. Also, involved personnel were retrained on
the condition adverse to quality procedure.
The involved personnel were retrained. Also, on November 1, 1994
the licensee satisfactorily completed an operability
determination in calculation KC Unit 1-2-0107, "Keowee Turbine
Guide Bearing Temperature Calculation," with results indicating
the oil cooler was not necessary for unit operability. This
violation example is closed.
(5) In Item 5, the appropriate housekeeping zones were not being
assigned to select maintenance activities at Keowee.
In response to the violation, the licensee stated that all
applicable maintenance procedures would be revised by October 1,
1994. Also, training on housekeeping zone requirements would be
given to Keowee personnel by August 1, 1994.
The applicable procedures were revised, and training was provided
to the Keowee personnel.
However, the training was given 50 days
after the committed date. Keowee personnel were aware the date
assigned was not met and had contacted regulatory assurance
personnel. The regulatory assurance personnel involved did not
understand NRC concurrence would be necessary to extend the
commitment date and stated that the missed commitment date would
be updated in quarterly correspondence with the NRC on electrical
inspection issues.
In summary, Items 2, 3, 4, and 5 are closed.
Item 1 remains open
pending completion of additional licensee corrective actions.
1. (Closed) IFI 50-269, 270, 287/93-25-14, "Review of Revised ASW Pump
NPSH Calculation."
During the original inspection calculation OSC-5125, "ASW NPSH
Analysis," assumed siphon flow from the intake canal to the ASW pump
suction would be in operation following the tornado. However, the
ECCW siphon lacked tornado protection, and would not be operational.
Therefore, the minimum suction height was contingent upon the
inventory losses in the CCW piping as a result of ASW pump operation.
Minimum NPSH for the ASW pump was -2.22 psig which meant that the pump
could draw water from 5.12 feet below the pump's impeller eye and
still have adequate NPSH. However, the licensee failed to consider
the actual configuration of the CCW piping going to the suction of the
ASW pump. Therefore, when the water in the CCW piping dropped to a
height of 770.46 feet, inadequate NPSH would occur. Consequently, the
amount of water available for ASW pump use was noticeably reduced.
Enclosure 2
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20
The licensee failed to correct the calculation and failed to identify
that the error in the calculation constituted a condition adverse to
quality and required the initiation of a PIP. During the follow-up
inspection this failure to initiate a PIP was identified to the
licensee. PIP 94-1500 was subsequently initiated which also
identified OSC-0864, "RC System DH Removal following a Loss of Intake
Structure," as being deficient. The licensee's site directive on the
problem identification process requires the initiation of a condition
adverse to quality report (PIP) when there are errors in design bases
documents and when documents are not updated.
Criterion XVI, "Corrective Action," requires in part that conditions
adverse to quality be promptly identified. Failure to originally
identify this condition adverse to quality by initiating a PIP was an
example of Violation 50-269, 270, 287/94-13-01C, "Inadequate
Corrective Action Controls."
m. (Open) IFI 50-269, 270, 287/93-25-15, Administrative Controls for Lake
Keowee: Calculation OSC-3528, "Keowee Lake Level Minimum
Administrative Limits," had numerous technical weaknesses. The
calculation was an attempt to establish a minimum lake level necessary
to ensue operability of Oconee and Keowee for design basis events.
No further actions had been accomplished since the original
inspection. The licensee indicated that this matter had "dropped
through the cracks" following a reorganization and changes in
personnel within the engineering department. The licensee indicated
an individual would be assigned to address this matter. This issue
remains open pending licensee action.
4. Inspection Report 93-25 Cover Letter Responses
The SWSOPI cover letter dated February 11, 1994, requested a written
response describing analysis, rational or actions planned regarding:
The presence of only one valve isolating the safety-related portion of
the LPSW system from the nonsafety-related turbine building portion.
- The SSF could not withstand a postulated failure of the Jocassee Dam.
The HPSW system was not designed or maintained commensurate with its
importance to safety.
Also, the cover letter requested the licensee's design control measures,
engineering evaluations, testing program, and the safety classification of
components system be evaluated to determine any necessary programmatic
corrective actions warranted by this inspection report.
In letters dated March 12, 1994, and April 20, 1994, the licensee
discussed these issues defined in the cover letter to the SWSOPI report.
The team reviewed the licensee responses and ascertained the status of the
corrective actions identified within the body of the letters. The results
of the reviews were as follows:
Enclosure 2
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a. LPSW Single Isolation - This matter is closed as discussed in
paragraph 3.b of this inspection report.
b. Ramifications of Jocassee Dam Failure on the SSF - This matter is
closed as discussed in paragraph 3.j of this inspection report.
c. Design and Maintenance of the HPSW System
(1) The initial inspection report discussed that covers for sections
of the trench in which the power and control cables for the CCW
pumps run, as well as the HPSW sealing/cooling water supply line
to the pumps, were not bolted down and could fall into the trench
in a seismic event, potentially damaging these components. It
was also reported that the cover for the structure housing the
ECCW valve CCW-8 was not restrained and could potentially fall on
the valve in a seismic event.
The licensee generated PIP 0-094-504 to perform a minor
modification to provide a seismic design for the trench covers in
question. However, this PIP was closed out on June 29, 1994,
when the design package was completed, but the work still had not
been started at the time of the follow-up inspection. When this
was discovered by the team, the licensee indicated the PIP would
be reopened to ensure completion of the installation work.
The team also found that no actions had been performed on the
structure cover for valve CCW-8, and inspection revealed that one
of the three cover plates was out of position and resting on one
of the other plates, making it particularly vulnerable to a
seismic event. The initial licensee response was that since
functions for which this valve were required did not have to be
considered in conjunction with a seismic event, it did not have
to be seismically qualified. The team pointed out to the
licensee that the requirement for safety-related equipment to be
seismically qualified is solely because it is safety-related; it
is not dependent on there being a seismic event linked to the
event for which it is required.
The licensee indicated the cover would be restored to its proper
location and signs installed on these covers and the trench
covers indicating they must remain in place for the seismic
qualification of the equipment to remain valid.
(2) The initial inspection report discussed that the operator rounds
sheets contained no upper limits on the HPSW flows to the CCW
pumps and motors for sealing and cooling respectively, and that
17 of the 24 flow instruments for these pumps were above the
values used to calculate the 4-hour, SBO capacity of the EWST.
The licensee's response in the March 14, 1994, letter was that if
the EWST SBO test passed, it was irrelevant if the flows were
above the values used in the EWST capacity calculation. This is
Enclosure 2
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22
not correct. Without upper limits on the flow, even with
satisfactory test results, during the one year interval to the
next test, the flow could be significantly increased, without
constraint or indication, potentially rendering the test results
invalid.
During the follow-up inspection, the licensee acknowledged that
upper limits on the flows were appropriate and indicated
necessary actions would be to taken.
(3) The initial inspection report discussed that HPSW performs the
function of providing sealing and cooling water to the CCW pumps
and motors respectively. These flows are set and monitored using
rotameters at the CCW pumps. The initial inspection found that
these instruments were being improperly set and poorly
maintained.
In the licensee's letter response of March 14, 1994, it was
stated that if the flow were actually inadequate, it would
adversely affect pump performance, implying that this reduced
performance would be detected during normal operation. This is
not correct. Normal pump performance is not at all affected by
loss of seal water. This loss only affects its safety-related
function of maintaining the "first siphon" integrity when the
pumps are not running.
(4) The initial inspection report discussed the poor material
condition of the CCW rotameters.
The licensee responded in the March 14, 1994, letter that a PIP
had been written to document the off-scale high reading of a
number of rotameters. As corrective action to this PIP the
licensee initiated a preventative maintenance activity to
periodically clean the rotameters.
The team reinspected these devices during the follow-up
inspection and found essentially the same conditions as the
initial inspection. Ten of the twenty-four instruments contained
significant slime contamination, and one contained three clams,
making the accuracy of their indication questionable. Eleven of
the flow instruments were pegged at the high end of the scale.
Therefore, this parameter was not monitorable with these
instruments.
Since readings from these instruments were taken as a part of the
normal operator rounds, the team reviewed the non-licensed
operator turnover sheets, OP/2/A/1102/20, Enclosure 5.7, and
rounds sheets, Enclosure 5.11, dated October 9, 1994, and
October 10, 1994, to determine if any notation had been made of
their material condition. No notation had been made.
Enclosure 2
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23
Operations supervisors were questioned on the training of
operators regarding recognition of discrepant conditions and how
conditions, such as were found, could exist. Operations
personnel indicated that as long as flow could be determined or
pegged high, since engineering had not established an upper
limit, the condition would not be identified.
The licensee had initiated a PIP and took the corrective action
identified. However, the actions were ineffective. 10 CFR 50,
Appendix B, Criterion XVI, "Corrective Action," requires in part
that conditions adverse to quality be promptly corrected. The
failure of the PIP corrective actions to adequately resolve the
poor material condition of the CCW rotameters or even ensure that
the material condition discrepancies were identified is an
example of Violation 50-269, 270, 287/94-31-OlD, "Inadequate
Corrective Action Controls."
(5) The initial inspection report identified that the HPSW pump check
valves, HPSW-2, 5, and 8 were not being properly tested. Also,
the these valves and the pumps had not been properly classified.
The licensee responded in the March 14, 1994, letter that a PIP
had been written to add these valves to the IST program. Also, a
PIP was written to update the QSM and DBD for the HPSW system.
The team found that the QSM and IST corrective actions were
predicated upon revision of the DBD. The DBD revision was still
in draft form with the corrective action completion schedule
extended to the end of the year.
(6) The initial inspection report discussed the structural capability
of the HPSW system.
The licensee responded in the March 14, 1994, letter that
inspected piping met minimum wall thickness criteria, the hanger
design was acceptable, and appropriate consideration had been
enacted with a revision to the SLC 16.9.7 to account for spurious
HPSW actuation. The response also stated, "Oconee recognizes
that the HPSW System was not required to be designed and
constructed to the seismic design criteria presented in Section
3.7 and 3.9 of the Oconee FSAR."
The team confirmed the SLC had
bee revised. However, the overall design and construction
requirements of the HPSW system continues to be reviewed by the
NRC as part of URI 269, 270, 287/93-13-03, "ECCW System Design
and Testing."
d. Design Control/Engineering Evaluations - The licensee indicated EDM
101, "Engineering Calculations/Analyses," would be revised to clarify
management expectations on the verification and validation of design
inputs and assumptions. Also, all required functions identified in
Enclosure 2
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24
the mechanical systems DBDs would be reviewed against both the
existing calculational support for that function and the existing
emergency operating procedures and the abnormal procedures.
The team verified the revision to EDM-101 and determined the status of
the mechanical systems DBD review. The review was in its initial
stages.
Also, the team selected another subsystem of the SSF to determine
whether there were additional problems within the design control area.
A review of the SSF RC make-up calculations revealed deficiencies.
Some of the calculational inconsistencies that were similar to those
present in the SSF calculations reviewed during the previous
inspection. The licensee indicated that many of these would be
corrected when the DBD was issued. The DBD was scheduled to be issued
in November 1994.
The most significant deficiency was in OSC-619, "Analysis for the use
of Spent Fuel Pool Inventory for Standby Shutdown Facility."
The
deficiency was the failure to fully account for the high radiation
levels of the Spent Fuel Pool in a timely manner when the water level
dropped to one foot above the top of the spent fuel.
The licensee's
preliminary analysis indicated the radiation levels would be
approximately 2,000,000 Roentgens per hour at the pool surface at 72
hours following loss of fuel pool cooling. There were no time
specific requirements for restoration of fuel pool make up.
Additionally, there were no specific procedural steps for performing
this evolution nor was equipment staged for this repair. This is
Unresolved Item 50-269, 270, 287/94-31-06, "High Spent Fuel Pool
Radiation Levels."
e. Testing - The licensee indicated that significant progress was being
made in developing and implementing integrated system testing. Also,
all required functions identified in the DBDs were being reviewed
against existing test procedures to ensure the function was being
appropriately verified.
The team ascertained the DBD/testing review was in progress.
f. Safety Classification - The licensee indicated that further review as
to whether the QSM was complete was ongoing. For those cases
maintenance and testing procedures would be upgraded consistent with
the Quality Assurance program.
The team recognized the licensee's effort but additional evaluation of
Generic Letter 83-28 and a review of the licensee's response to that
GL would be necessary to fully understand the adequacy of the
licensee's corrective actions in this area.
Completion of these programmatic reviews in the areas of
Testing/QSM/Design Control is an Inspector Follow-up Item 50-269, 270,
287/94-31-07, "Quality Programs Review."
Enclosure 2
Report Details
25
5. Review of Valve LPSW 139 to Close
The licensee had recalculated the closing torque requirements using the
EPRI methodology developed for butterfly valves. These calculations
indicated that the valve operators had sufficient torque to close and seat
the valves. This result differed from the calculation provided with the
licensee's response to IR 93-04 in that there was no assurance that
sufficient torque to seat the valves. The licensee had conducted
laboratory testing for valve closure against high differential pressure
for the new LPSW-139 valve, but no high differential pressure testing has
been conducted on the valve currently installed. As documented in the
licensee's response to IR 93-04, the licensee plans to install the new
LPSW-139 valve in parallel with the current valve during the next Unit 1
outage currently scheduled for October 1995.
6. IST Program Scope versus Appendix B Testing Program Scope
During the initial SWS inspection certain aspects of the licensee's ASW
system testing program as it related to the IST requirements arose.
Specifically, the licensee used a combination of IST and an Appendix B
test program to encompass the testing of the safety-related valves. As a
result of the discussions with the licensee regarding the scope of their
testing program, the team expanded the scope of review to include all
valves included in the Appendix B program which were not included in the
IST program. The results of that review were as follows:
a. The scope of the licensee'sSection XI test program only encompassed
that equipment used to mitigate accidents discussed in chapter 15 of
the FSAR. Due to Oconee's unique design, other equipment not credited
in the chapter 15 accidents is used to mitigate accidents discussed in
other chapters of the FSAR such as a tornado. Therefore, there were
omissions in the ASME Section XI test program.
b. The ASW check valves (LPSW-502) allowing flow to the HPI pump motor
coolers had not been tested. HPI pump motor cooling via the ASW
system was assumed to mitigate the consequences of certain types of
tornadoes and to mitigate the consequences of a complete loss of the
intake canal water. The licensee had previously identified the
testing omission and initiated a PIP. Plans and preparations were
being made to accomplish the testing before the end of the year. This
situation was similar to NCV 50/269, 270, 287/93-25-13, "Omissions of
LPSW Check Valves from IST Program."
c. Other valves necessary to function to mitigate the consequences of a
tornado were not included within the IST program. Most notable were
the atmospheric dump valves (MS 153-156 & 161-164) and the condenser
water box isolation valves (CCW 21-25).
These valves were tested
during shutdown conditions but not at the frequency specified in
Section XI of the ASME code. No relief request had been submitted to
the NRC concerning these valves.
Enclosure 2
Report Details
26
d. Numerous valves associated with the air start and fuel supply systems
to the SSF DGs were not identified as part of the IST program.
However, the valves were being tested at the required frequency.
f. The manual MTOTC bypass valve, LPSW-51, was not identified as
requiring testing, ASME Section XI nor Appendix B. The licensee's
analysis credited its closure (when the MTOTC valve was out of
service) during a LOCA/LOOP. When identified to the licensee PIP 94-438 was initiated.
10 CFR 50.55(a) requires safety related values be included within the
Section XI valve test program. Failure to include the ASW check valves,
atmospheric dump valves, and the MTOTC bypass valve within the scope of
the ASME code Section XI test program is Violation 50-269, 50-270,
50-87/94-31-08, "ASME Section XI Test Program Omissions."
7. Review of High Energy Break Ramifications within Containment and Planned
Corrective Actions
On June 2, 1993, the licensee determined that the original MSLB within
containment analysis was nonconservative and LER 50-269/93-06 was
submitted on the subject. In a letter dated May 27, 1993, the licensee
discussed the rationale as to why there should be continued reliance upon
the control grade integrated control system and operator action prior to
- implementation
of a long term solution. In a letter dated August 19,
1993, the licensee also discussed the long term solution, an automatic
feedwater line isolation scheme, to be implemented in the 1995/96
timeframe. In a letter dated October 6, 1993, NRC indicated this approach
was viable.
The worst scenario discussed in the licensee's correspondence involved the
MSLB with the accompanied failure of the feedwater control valve to close.
The analysis concluded that containment design pressure would be exceeded
(but structural yield pressure would not be reached) if manual action to
close the feedwater block valve was taken within two minutes.
The team reviewed the containment temperature and pressure curves for this
case of "Without Credit for Automatic Main Feedwater Control and Main
Feedwater Control Valve Sticks Open". This case indicated that the EQ of
equipment (mostly instrumentation) used to mitigate a MSLB was exceeded
from a temperature perspective. The temperature EQ would be exceeded in
the short term and long term.
This observation appeared to contradict other licensee statements in their
correspondence of May 27th and August 19th which stated that the equipment
required to mitigate the consequences of the MLSB was qualified and would
perform its safety function. Discussions with the licensee indicated that
the EQ statement was for the equipment after implementation of the long
term solution for MSLB or in the design bases LOCA, and the equipment had
not been EQ reviewed for the pressures and temperatures in the MSLB with a
control valve failure case. Since this information was not clearly stated
in the licensee's correspondence to the NRC (letters dated May 27, 1993
Enclosure 2
Report Details
27
and August 19, 1993), the team notified the NRR Project Manager
responsible for review of the adequacy of the licensee's response.
Subsequently the Project Manager informed the team that the new
information did not change the original NRC decision on this matter.
The team reviewed the current status of the proposed long term solution.
The licensee stated that the modification would close non safety related
valves and that the equipment would be EQ qualified for MSLB's. The
schedule for implementation of the modification was feasible considering
the fact that advantage will be taken of already installed safety-related
equipment. The licensee indicated that some of the long term solution
discussed in their letter of August 19, 1993, was going to be modified. A
discussion with the NRR Project Manager indicated that the NRC understands
that the licensee intends to submit surveillance and technical
specifications that would ensure the operability of the modification.
8. Exit Interview
The team conducted an exit meeting on October 27, 1994, at the Oconee
Nuclear Power Station to discuss the major areas reviewed during the
inspection, the strengths and weaknesses observed, and the inspection
results. Licensee representatives and NRC personnel attending this exit
meeting are documented in Appendix A of this report. The team also
discussed the likely informational content of the inspection report. The
licensee did not identify any documents or processes as proprietary.
There were three dissenting comments at the exit meeting associated with
the lack of gravity/siphon flow testing, the scope of the ASME code
Section XI valve test program and the failure to initiate a PIP when an
inaccurate reference was used when performing calculation OSC-2346, "ECCW
System Performance Evaluation." The licensee indicated a thorough review
of the inspection findings would be necessary to ascertain the appropriate
responses or corrective actions to the issues identified.
Also, an exit was held with the cognizant SSF engineer associated with the
team's attempt to witness SSF SWS testing. There were no findings since
the test could not be performed due to unanticipated scheduling delays in
establishing the plant conditions for the testing.
Enclosure 2
Report Details
28
ITEM NUMBER
STATUS
PARAGRAPH
DESCRIPTION
93-25-01
Open
3.a
DEV - Failure to Adequately Perform
SWS GL Actions
93-25-02
Closed
3.b
UNR - Turbine Building Isolation
Single Failure Vulnerabilities
93-25-03
Open
3.c
VIO - Failure to Perform
Adequate Calculations and
Evaluations to Support
Facility Design
93-25-04
Closed
3.d
VIO - Inadequate
Evaluation of Conditions Adverse to
Quality by Engineering
93-25-05
Open
3.e
IFI - Additional Validation of RBCU
Evaluation Inputs
93-25-06
Open
3.f
IFI - Actions to Improve
Operator Responses to
Abnormal Events
93-25-08
Open
3.g
VIO - Inadequate SSF and ECCW
Testing
93-25-09
Closed
3.h
IFI - CCW Pump NPSH Information
93-25-10
Open
3.i
DEV - Inadequate HPSW SBO Test
93-25-11
Closed
3.j
IFI - Jocassee Dam Failure IPE
Inaccuracies
93-25-12
Open
3.k
VIO - SWS Procedure/Drawing Content
or Procedure Implementation
Inadequacies
93-25-14
Closed
3.1
IFI - Review of Revised ASW Pump
NPSH Calculation
93-25-15
Open
3.m
IFI - Administrative Controls for
94-31-01
Open
3.a,
VIO -
Inadequate
3.k(3)
Corrective Action
3.1
Controls
4.c(4)
94-31-02
Open
3.c(2)
IFI - Hydraulic Model Controls
Transition
94-31-03
Open
3.c(4)
IFI - Reperformance of Calculation
Enclosure 2
Report Details
29
OSC-2346
94-31-04
Open
3.c(4)
VIO - Inadequate LPSW Suction Source
Testing Via the ECCW System
94-31-05
Closed
3.k(2)
NCV - Inadequate ASW Procedure
94-31-06
Open
4.d
UNR - High Spent Fuel Pool Radiation
Levels
94-31-07
Open
4
IFI - Quality Programs Review
94-31-08
Open
8
VIO - ASME Section XI Test Program
Omissions
Enclosure 2
LIST OF PERSONS CONTACTED
Duke Nuclear Power Plant
Persons Contacted
L. Azzarello, Mechanical Engineering
S. Baldwin, Mechanical Systems Engineering
D. Coyle, Mechanical Systems Manager
B. Dolan, Safety Assurance Manager
W. Foster, Maintenance
R. Harris, Mechanical Systems Engineering
W. Horton, Operations Support
D. Hubbard, Maintenance
$ H. Lefkowitz, Mechanical Systems Engineering
- G. McAninch, Mechanical Systems Engineering
- B. Millsaps, Mechanical/Civil Engineering
- $ J. Smith, Regulatory Compliance
R. Swigant, Work Control
U.S. Nuclear Regulatory Commission
- $ L. Mellen, Reactor Inspector
- D. Prevatte, Powerdyne Corporation
C. Rapp, Reactor Inspector
W. Rogers, Team Leader
L. King, Reactor Inspector
P. Harmon, Senior Resident Inspector
L. Keller, Resident Inspector
- Indicates those present at the exit meeting on October 27, 1994
$ Indicates those involved in the exit on November 3, 1994
Enclosure 2, Attachment A
LIST OF ACRONYMS AND ABBREVIATIONS
.
ASME -
American Society of Mechanical Engineers
ASW
-
Auxiliary Service Water
-
Condenser Cooling Water
CFR
-
Code of Federal Regulations
-
Design Basis Document
DEV
-
Deviation
-
Diesel Generator
DH
-
Decay Heat
ECCW -
Emergency Condenser Cooling Water
-
Emergency Feedwater
EPRI -
Electric Power Research Institute
-
Environmental Qualification
EWST -
Elevated Water Storage Tank
FSAR -
Final Safety Analysis Report
GL
-
Generic Letter
GPM
-
Gallons Per Minute
-
High Pressure Injection
HPSW -
High Pressure Service Water
HVAC -
Heating Ventilation and Air Conditioning
IFI
-
Inspector Follow-up Item
-
Individual Plant Examination
-
Inservice Test
LOCA -
Loss of Coolant Accident
LOOP -
-
Low Pressure Injection
LPSW -
Low Pressure Service Water
-
Main Steam Line Break
MTOTC -
Main Turbine Oil Temperature Control
-
Non-Cited Violation
NPSH -
Net Positive Suction Head
NPSHA-
Net Positive Suction Head Available
-
Problem Investigation Process
-
Probabilistic Risk Analysis
PSIG -
Pounds per Square Inch Gauge
PTRQ -
Personnel Training Requiremental Qualification
-
Quality Assurance
QSM
-
Quality Standards Manual
RBCU -
Reactor Building Cooling Unit
RC
-
-
Station Blackout
-
Safety Evaluation Report
-
-
Selected Licensee Commitments
SQUG -
Seismic Qualification Utility Group
SSF
-
Safe Shut Down Facility
-
Service Water System
SWSOPI-
Service Water System Operational Performance Inspection
-
Unresolved Item
-
Unreviewed Safety Question
Violation
Enclosure 2, Attachment B