ML15118A175
| ML15118A175 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 01/27/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15118A173 | List: |
| References | |
| 50-269-96-17, 50-270-96-17, 50-287-96-17, NUDOCS 9702100360 | |
| Download: ML15118A175 (53) | |
See also: IR 05000269/1996017
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-269, 50-270, 50-287. 72-04
License Nos:
DPR-38, DPR-47, DPR-55, SNM-2503
Report No:
50-269/96-17, 50-270/96-17, 50-287/96-17
Licensee:
Duke Power Company
Facility:
Oconee Nuclear Station, Units 1, 2 & 3
Location:
7812B Rochester Highway
Seneca, SC 29672
Dates:
November 17 - December 28, 1996
Inspectors:
M.
Scott, Senior Resident Inspector
D. Billings, Resident Inspector
G. Humphrey, Resident Inspector
N. Salgado, Resident Inspector
N. Economos, Reactor Inspector
D. Forbes, Reactor Inspector
R. Moore, Reactor Inspector
P. Kellogg, Reactor Inspector
J. Lenahan, Reactor Inspector
R. Baldwin, Reactor Inspector
R. Aiello, Reactor Inspector
Approved by:
L. D. Wert, Acting Chief, Projects Branch 1
Division of Reactor Projects
ENCLOSURE 2
9702100360 970127
ADOCK 05000269
G
EXECUTIVE SUMMARY
Oconee Nuclear Station, Units 1, 2 & 3
NRC Inspection Report 50-269/96-17,
50-270/96-17, 50-287/96-17
This integrated inspection included aspects of licensee operations,
engineering, maintenance, and plant support. The report covers a six week
period of resident inspection; in addition, it includes the results of
announced inspections by eight regional reactor inspectors.
Operations
A configuration control violation with two examples was identified
this period. The first example involved a mispositioned valve
that resulted in the formation of a void in the Reactor Coolant
System (RCS) during loop fiil (Section 01.2). The second example
involved a mispositioned pressure sensing line isolation valve
which rendered valve 3LP-2 inoperable (Section 01.3).
0
During review of the RCS void issue described above, a weakness in
Control Room (CR) log practices was identified (Section 01.2).
The licensee identified incorrect connections (rolled electrical
power leads) to motor operated valves 2LP-1, 2LP-2, 3LP-1 and 3LP
2. This problem resulted in these valves potentially unable to
perform their safety function of achieving and maintaining safe
shutdown during an Appendix R event. A 10 CFR 50.72 report was
made. A URI was identified on the issue (Section 01.4).
On-going licensee efforts in the area of operator training to
address procedural and equipment changes after the reheater line
rupture event were observed to be adequate. Additionally,
malfunction training conducted on the new digital Integrated
Control System model was considered to be satisfactory (Section
05).
An apparent violation was identified because the plant was not
maintained in accordance with approved procedures, in that an
Operations Procedure was not placed on Administrative Hold to
prevent its use prior to revision. Initially addressed in
Augmented Inspection Team Report 50-269,270,287/96-15, this was a
major factor in the September 24, 1996, Unit 2 water hammer event
(Section 07.1).
The licensee performed an extensive root cause investigation of
two similar safety-related relay failures to assess the
possibility of a generic failure mechanism (Section 08.1).
ENCLOSURE 2
2
Maintenance
Three complex surveillances were professionally and competently
performed, providing excellent status of and critical performance
details for these important safety-related systems (Sections M1.2,
M1.3, and M1.4).
Initially addressed in Augmented Inspection Report 50
269,270,287/96-15, an apparent violation (three examples) was
identified involving the failure to provide a written evaluation
for secondary plant piping not in accordance with the code
referenced in the Updated Final Safety Analysis Report (Sections
M1.5 and E2.4).
An Unresolved Item (URI) was identified concerning certain
replacement stainless steel pipe which had not received sufficient
analysis when it was used to replace existing carbon steel
secondary pipe (Section M1.5).
Observation of secondary plant weld activities during on-going
piping replacement indicated that the welds met the requirements
of the Code, that weld appearance was adequate, and that final
inspection by Quality Control inspectors implemented for this
rep acement effort was a positive step in assuring that good weld
practices were being followed (Section M1.6).
Observation of the 1A Reactor Coolant Pump main flange weld repair.
indicated that the work was well planned and executed, that
welding and non-destructive testing were performed by well trained
individuals, that engineering and technical resources were
adequate, and that supervision of the repair was good (Section
M1.7).
Eight welds on Unit 1 Low Pressure Service Water (LPSW) piping
were not properly inspected resulting in a Violation (Section
M1.8).
A violation was identified for the failure to perform evaluations
of out-of-tolerance Measuring and Test Equipment (Section M4.1).
Engineering.
The turbine building un-reinforced 12-inch concrete floor over
pour was determined not to compromise the seismic qualification of
safety-related equipment in the building (Section E2.1).
A review of modifications and Problem Investigation Process (PIP)
backlogs identified one potential concern, which was identified as'
a URI pending additional review to determine if the wrong type
ENCLOSURE 2
3
fuses installed in the Reactor Building Cooling Units (RBCUs)
caused the RBCUs to be inoperable (Section E2.2).
Review of the steam drain modification implementation indicated
that training, procedures, and the engineering package, although
not completed, were being adequately performed (Section E2.3).
Review of Low Pressure Service Water system modifications status
indicated that engineering has completed approximately 30 percent
of the work on the packages. Work will continue into middle to
late 1997. Water hammer and overpressure issues had diverted
engineering effort (Section E8.4).
Plant Support
The licensee was conducting surveys, posting areas, and labeling
radioactive material as required by procedures (Section R1.1).
The licensee's program for Radiation Work Permit (RWP)
implementation adequately addressed radiological protection
concerns (Section R1.1).
Facility radiological conditions and housekeeping were observed to
be adequate. The licensee had initiated additional contamination
control practices to reduce personnel contamination events
(Section R1.1).
The licensee was continuing to implement program improvements to
maintain exposures As Low As Reasonably Achievable (Section R1.1).
A URI was identified concerning in situ calibrations on
containment high range radiation monitors (Section R2.1).
The licensee was adequately identifying issues of concern for
improvement in the Radiation Protection area through the use of
the Problem Investigation Process, self-assessments, and Quality
Assurance audits (Section R7).
ENCLOSURE 2
Report Details
Summary of Plant Status
Units 1 and 2 remained in cold shutdown for the entire reporting period. The
operators identified a void in the Unit 2 hot leg piping on December 10, 1996,
(Section 01.2).
Unit 3 remained defueled throughout the entire reporting
period.
Review of Updated Final Safety Analysis Report (UFSAR) Commitments
While performing inspections discussed in this report, the inspectors reviewed
the applicable portions of the UFSAR that related to the areas inspected. The
inspectors verified that the UFSAR wording was consistent with the observed
plant practices, procedures, and/or parameters. Identified discrepancies
between the UFSAR and secondary plant piping are addressed in Sections M1.5
and E2.4
I. Operations
01
Conduct of Operations
01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent
reviews of ongoing plant operations. In general, the conduct of
operations was professional and safety-conscious: specific events and
noteworthy observations are detailed in the sections below.
01.2 Void in Unit 2 Reactor Coolant System (RCS) Hot Leg Piping
a. Inspection Scope (93702)
The inspectors reviewed the licensee's actions after identification of a
void in the Unit 2 "B"
loop hot leg. The inspectors reviewed the drain
down and refill procedure (OP/A/2/1103/02, Filling and Venting the
Reactor Coolant System and control room logs. The data and actions were
also reviewed by a regional inspector (see Section 01.5).
b. Observation and Findings
The drain down of Unit 2 to midloop for resistance temperature detector
(RTD) maintenance was completed on October 17, 1996. The RCS was
partially refilled on October 18 - 19, 1996, using OP/2/A/1103/02. This
procedure contains a valve checklist to verify valves for the fill and
vent. The 2B Once Through Steam Generator (OTSG) hot leg vent valve
2RC-196 was recorded as having been verified open during the drain down
and refill with no apparent problems. Reportedly, adjacent valves were
aligned closed (per Enclosure 4.3, Raising the Loops) on approximately
October 18, 1996, during the loop fill completion.
ENCLOSURE 2
S
2
On December 1, 1996, the Pressurizer (PZR) level instruments were
recalibrated. The level instruments then indicated approximately 73
inches versus the 80 inches previously observed. The Unit 2 Operations
Manager directed the shift on December 3, 1996, to raise level to 80
inches, but not to exceed 45 psig PZR pressure, (pressure had been
maintained at 38-40 psig). After the PZR was refilled to 80 inches,
pressure increased to 43 psig. The operators reduced pressure down to
38 psig and noted an approximate 10 inch increase in PZR level.
The
cause of the level increase was attributed to a void in a RCS hot leg.
Development of new procedural guidance (Enclosure 4.15 of
OP/2/A/1103/02) for venting the RCS under the existing plant conditions
was completed on December 10, 1996. The hot legs were vented and the
void was determined to be in the 2B OTSG. A makeup of approximately
1922 gallons was required to replace the void. The inspectors
independently verified this value and concluded that the air pocket
would not have air bound the decay heat flow path. There were no
indications of voiding in other RCS locations.
2RC-196 was found closed on December 10, 1996. Investigation by the
licensee revealed that 2RC-196 had been mispositioned (closed) on or
about October 18, 1996, when the 2B OTSG was refilled after the RTD
repair. The mispositioning of 2RC-196 is a violation of Technical
Specification (TS) 6.4.1 and is identified as Example 1 of Violation
(VIO)50-270,287/96-17-06, Failure to Maintain Configuration Control.
The minimum TS required equipment was available for decay heat removal
at all times. However, the inadvertent void formation was significant
since it made the B OTSG unavailable for decay heat removal.
Plant
evolutions had been performed assuming both steam generators were
available for decay heat removal from October 18. 1996, through December
3, 1996.
During review of the operator's logs from October 18, 1996, to December
3, 1996, the inspector noted that approximately 6000 gallons of water
had been added to the RCS via the Low Pressure -Injection (LPI) system
and approximately 2000 gallons of water was accounted for in the seal
leakoff to the quench tank. The inspector questioned Control Room (CR)
personnel and Operations management about the apparent discrepancy
(approximately 4000 gallons). The licensee's followup investigation
accounted for the volume in question which represented approximately 130
- gpd makeup to the RCS. Losses of approximately 50 gpd were due to
chemistry sampling and approximately 75 gpd due to LPI system losses.
This leakage rate, which was verified by the inspectors, had existed
prior to and following the drain and refill of the RCS. The inspector
concluded that the CR logs should have been more detailed in accounting
for the loss of inventory. The inspectors also noted that the operators
did not have a questioning attitude regarding the amount of water which
was added to the RCS on a daily basis.
ENCLOSURE 2
c. Conclusions
The mispositioning of 2RC-196 was identified as an example of failing
to maintain configuration control. Operation's logging practices and
attention to plant status was identified as a weakness.
01.3 Failure of Valve 3LP-2 to Operate
a. Inspection Scope (71707)
The inspectors reviewed the events associated with the failure of Unit 3
Low Pressure Injection (LPI) Valve 3LP-2 to reposition when its control
room switch was placed in the open position.
b. Observations and Findings
During performance of OP/3/A/1104/04. LPI System Alignment, Enclosure
3.1, step 2.3.3, loop suction valve 3LP-2 failed to open from the
control room switch during unit shutdown on October 5, 1996. This
delayed shutdown to cold conditions. A low pressure interlock had to be
defeated to open the valve. This interlock was designed into the
control system to prevent the valve from opening when the RCS pressure
was above 450 psig. Emergency Operating Procedure EP/3/A/1800/01,
Section CP-601, Cooldown Following Large Loss of Coolant Accident
(LOCA), and procedure OP/3/A/1104/04, LPI System, addressed manipulation
of the 3LP-2 valve.
Sections 6.3.2.2.2 and 6.3.3.2.1 of the UFSAR describe the function of
valve 3LP-2 as a path from the reactor hot leg to the sump to prevent
boron precipitation following a large break LOCA event. The UFSAR
states that 3LP-2 will be opened within 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> into the event.
During
this unit shutdown, the licensee was able to get the valve opened within
approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> by having Instrument and Electrical Technicians
defeat the interlock by "jumpering" switch contacts per procedure
IP/0/A/0100/01, Controlling Procedure For Troubleshooting and Corrective
Maintenance, and Work Request (WR) 96041487.
On October 12, an investigation revealed that an instrument isolation
valve, located between the RCS piping and the pressure sensing device,
had been mispositioned closed. Information indicated that the isolation
valve had leaked when the RCS was at full pressure and the isolated
sensing line became pressurized. When the RCS pressure was lowered
during reactor shutdown, the closed isolation valve contained the higher
pressure in the instrument sensing line. This resulted in valve 3LP-2
eing interlocked closed. The interlock would have apparently been
maintained until the isolation valve was opened or valve leakage allowed
the pressure to leak down below 450 psig.
The failure to maintain the instrument root valve to pressure switch
3RCPS0364 in its proper configuration as required by maintenance
ENCLOSURE 2
(III
4
procedure IP/0/B/203/1G, LPI System Inaccessible Flow Instruments
Calibration. Enclosure 11.4.1, Isolation Valve Open, is a violation of
TS 6.4.1. It is identified as Example 2 of Violation 270,287/96-17-06,
Failure to Maintain Configuration Control.
c. Conclusions
The mispositioning of the 3LP-2 pressure interlock isolation valve was
identified as another example of failing to maintain configuration
control. It was determined that the two configuration control
deficiencies addressed in this Section and 01.2 did not involve a
significant operability issue.
The inspector reviewed Non-Cited
Violation (NCV) 50-269/96-13-01, and concluded that the associated
corrective actions would not have reasonably been expected to prevent
the above examples of configuration control deficiencies.
01.4 Incorrect Electrical Connection of 2LP-1. 2LP-2, 3LP-1 and 3LP-2
a. Inspection Scope (93702)
The inspectors reviewed the events and procedures associated with the
incorrect electrical connection (rolled leads) of the Decay Heat Removal
(DHR) suction valves LP-1 and LP-2 on Units 2 and 3. The motor
actuators on these valves were being replaced on Unit 3 as a part of
refueling activities.
b. Observations and Findings
On December 6, 1996, while performing functional verification of 3LP-1
and 3LP-2 actuator motor rotations, the motors were found to operate
backwards (reversed from control room switch position indication). The
technicians changed the three phase electrical power leads at the MCC to
correct the rotation problems. As part of the work package completion,
the craftsmen submitted "component malfunction"- sheet that was reviewed
by engineering. When the engineer reviewed the sheet, it was discovered
that these leads should never have needed to be rolled at the motor
operator unless the MCC leads had been mistakenly changed previously.
The engineer had the leads installed per plan at both locations.
Each time the motor operator leads were lifted during a maintenance
evolution, a function test was performed from the control room switch.
Between the MCC and the valve actuator motor are a second set of
connection points in the electrical power lead circuits. These are used
to install the Appendix R temporary power supply and control circuits,
if required under emergency conditions. The 3LP-1 and 3LP-2 valves
would work correctly from the control room switch with a double change
of leads - between the MCC and the penetration room, and then, between
the penetration room connection points and the motor. But under this
arrangement, attempting to install the Appendix R temporary power per
the plan would produce incorrect valve motion when energized from
ENCLOSURE 2
5
temporary power panel.
As indicated in Section 01.3, the 3LP-1 and 3LP
2 valves did operate correctly from the switch in the Unit 3 control
room during unit shutdown in October.
The licensee initiated work orders to verify the wiring on similar
Appendix R Unit 1, 2 and 3 valves; LP-1, LP-2, CF-1 and CF-2 (CF-1/2 are
Core Flood Tank Discharge valves). This review identified that 2LP-1
and 2LP-2 were also incorrectly wired. Following identification, wiring
was corrected per approved drawings for 2LP-1 and 2LP-2.
On December 19, 1996, the licensee notified the NRC per 10 CFR 50.72
that, these valves could not have performed the safety function of
achieving and maintaining safe shutdown during an Appendix R event.
Initial indications show that these valves would have operated from the
control room but would not have operated from the Safe Shutdown Facility
(SSF) temporary power valve panel if needed during an Appendix R event.
The licensee was performing a root cause investigation at the end of the
inspection period. A Licensee Event Report (LER) will be generated on
the event.
c. Conclusion
Pending further review of the safety significance and determination of
root cause, this item will remain open as URI 270,287/96-17-07, Failure
to Maintain Appendix R Valve Leads.
01.5 Operability Review of the Unit 2 Decay Heat Removal (DHR) System
a. Inspection Scope (71707)
The inspector reviewed the operability of the Unit 2 DHR system
following the discovery of noncondensible gases in the Unit's RCS "B"
loop. Additionally, the inspector performed a calculation to verify the
licensee's postulation regarding the gases' origin, amount, location and
potential safety consequences to equipment and personnel.
b. Observations and Findings
On December 13, 1996, the inspector conducted an independent review of
the licensee's problem investigation process and their effectiveness in
resolving and dispositioning noncondensible gases that were discovered
in the "B"
loop on Unit 2 on December 3, 1996. The inspector performed
a calculation using the licensee's computer data (which contained a
chronology of RCS pressures and Low Pressure Injection (LPI) pump
suction temperatures from October 18 through December 12, 1996), control
room logs. P&IDs, and reference material from the Unit's FSAR. The
inspector identified that the licensee failed to account for changes in
RCS temperature and pressure. Subsequently, the licensee's calculation
was in error by approximately 10% in the nonconservative direction.
ENCLOSURE 2
c.
Conclusions
The inspector verified by reviewing facility documents that (1)
the
noncondensible gasses did not migrate to the reactor vessel head and (2)
DHR/LPI suction was connected to the unaffected RCS loop (loop "A").
The inspector concluded, based on the material and information provided,
that a gas bubble was not generated in the reactor vessel head and LPI
operability was not challenged by this event.
02
Operational Status of Facilities and Equipment
02.1 Engineered Safety Feature System Walkdowns (71707)
The inspectors used Inspection procedure 71707 to walkdown accessible
portions of the following safety-related systems:
- Keowee Hydro Station
- Unit 2 Header Drain Systems
- Unit 3 High Pressure Injection (HPI) System
- Units 1.2, and 3 Reactor Buildings
Equipment operability, material condition, and housekeeping were
generally acceptable with some minor discrepancies that were brought to
the licensee's attention and were corrected. Other discrepancies which
were brought to the licensee's attention for resolution were: a large
paint chip and loose/broken tie wraps in the Unit 2 Reactor Building a
damaged cable and a loose Reactor Coolant Pump motor cover in the Unit 1
Reactor Building.
03
Operations Procedures and Documentation
03.1 Procedure Changes and Revisions For Unit 2 Plant Restart
a. Inspection Scope (71707)
The inspector reviewed the licensee's actions regarding Unit 2
procedures to be revised or initiated for operation of the heater drain
system which was modified following a pipe rupture incident in September
1996.
b. Observations and Findings
The inspector reviewed the status of the procedures identified by the
licensee to be revised or generated for the Unit 2 steam drain
modifications. Major modifications NSM-22901 and NSM-22941 involved the
portion of the system from Moisture Separator Reheaters to the 'A'
Feedwater (FDW) Heaters. Procedure changes were required to provide
instructions for proper operation of the modified system and to improve
operating instructions for existing equipment
ENCLOSURE 2
7
As part of the Unit 2 restart effort, the licensee reviewed other
significant water hammer issues that had been identified previously at
the plant. The issues were collected from the licensee's Event
Investigation Team report generated in response to the September 24
event review of an operator's program for compiling recollected water
hammer events, and a historical search of the Problem Identification
Program (PIP). This effort included systems other than the heater
drains, and the findings were documented in PIP reports 96-2338, 96
2339, 96-2340, 96-2341, 96-2342, 96-2347, and 96-2349. The licensee's
review was to ensure that corrective actions would be adequate to
prevent recurrence and that corrective actions were incorporated into
the new or changed operating procedures. The tracking of this
compilation was controlled by the Operations Department. The following
is a listing of those procedures which were to be reviewed for revision:
Procedure Number Procedure Title
OP/2/A/1102/01
Controlling Procedure for Unit Startup
OP/2/A/1102/02
Reactor Trip Recovery
OP/2/A/1102/04
Operation At Power
OP/2/A/1102/06
Removal and Restoration of Station Equipment
OP/2/A/1102/10
Controlling Procedure For Unit Shutdown
OP/2/A/1104/04
Low Pressure Injection System
OP/2/A/1104/12
Condenser Circulating Water System
OP/2/A/1104/37
Plant Heating
OP/2/A/1106/01
Turbine Generator
OP/2/A/1106/02
Condensate and Feedwater System
OP/2/A/1106/04
Auxiliary Boiler
OP/2/A/1106/08
Steam Generator Secondary Hot Soak, Fill, Drain, and
Layup
OP/2/A/1106/14
OP/2/A/1106/16
Condenser Vacuum System
OP/2/A/1106/22
Auxiliary Steam System
OP/2/A/1106/26
Steam Drain Valve Checklist
PT/2/A/0261/07
Emergency CCW System Flow Test
AP/2/A/1600/09
5SF Auxiliary Service Water System
AP/2/A/1700/19
Loss Of Main Feedwater
In addition to the water hammer issuest
the licensee identified areas
within the plant secondary systems with the potenti-al for being
overpressurized. Specific overpressure corrective actions had included
some modification to those systems that resulted in two procedures being
identified that required revision. These are as follows:
OP/2/A/1104/10
Low Pressure Service Water
OP/2/A/1106/02
Condensate and Feedwater System
The following Unit 2 valves have been designated by the licensee to be
administratively controlled to the listed positions to prevent
overpressure of plant systems. The valves and their associated
ENCLOSURE 2
8
procedural controls will be included in the above procedures. These
administrative controls are short-term resolutions for plant restart.
The long-term corrective actions will be implemented at a later date.
This will include additional modifications and procedure changes to
eliminate the overpressure concerns.
VALVE
POSITION
2CF-53 (Core Flood)
Open
2C-130 (Condensate)
Open
Open
Open
Open
2HD-186 (Heater Drain)
Open
Open
Open
Open
Open
Open
Open
2HV-28 (Heater Vent)
Open
Open
Open
Open
Open
Open
Open
Open
Open
2HPE-34 (High Pressure Injection)
Closed
At the close of the inspection period, the licensee had not yet
completed the necessary procedure revisions. Licensee intentions are to
complete this effort prior to Unit 2 restart.
c. Conclusions
The licensee's actions (i.e., compilations of issues, scope of changes,
and equipment review) appear adequate in identifying the procedures and
revision requirements necessary for restarting'and operating the plant
in a safe and orderly manner.
05
Operator Training and Qualification
05.1 Water Hammer Issue - Operator Training
a. Inspection Scope (71707)
The inspectors reviewed operator training on revised and new procedures
that resulted from modifications made to the plant. The modifications
ENCLOSURE 2
9
were implemented to reduce or eliminate steam/water hammers and to
prevent overpressurizing plant equipment.
b. Observations and Findings
The inspectors reviewed the operator training package for the Moisture
Separator Reheater (MSRH)/Heater Drain modifications (NSMs 22901 and
22941). The lesson plan was approved on December 12, 1996. which
described in detail the water hammer event that occurred in Unit 2 on
September 24, 1996, and the modifications that resulted. In addition,
operators were required to observe a steam/water hammer demonstration in
order to heighten their understanding of the effect.
Procedure revisions and enhancements had not been completed at the end
of the reporting period for all the systems modified or affected by
water hammers. Consequently, operator training was not completed, but
the licensee's efforts continued in this area.
c. Conclusions
The inspector determined that the licensee's operator training efforts
to date were acceptable and adequately addressed the modifications and
the water hammer incident.
05.2 Operator Requalification Program (71001)
a. Inspection Scope (71001)
During the period of December 17-20, 1996, the inspector used guidance
from Inspection-Procedure 71001 to review and evaluate'the licensee's
operator requalification program in the area of the Unit 3 Digital
Integrated Control System (ICS) modification training, malfunction
training and evaluation, and job performance measures examination
review.
b. Observations and Findings
The inspector observed approximately four days of malfunction training
on the Unit 1 simulator with the Unit 1 digital ICS model installed.
Each crew training session-observed was comprised of four operators with
one session consisting of five operators. The instructors presented
seventeen credible ICS malfunctions to the operators. The inspector
observed operators practice 9 of the 17 malfunctions during these
sessions. Eight of the 17 malfunctions could not be reasonably acted
upon to prevent a reactor trip and were not practiced. These eight
malfunctions were presented to familiarize the operators of all credible
malfunctions that could occur. The inspector questioned the operators
concerning their ability to operate the new digital ICS. The operators
unanimously responded that they did not feel it would be'a significant
ENCLOSURE 2
10
problem with switching between the new and old ICS on the different
units providing some type of "just-in-time" training was provided.
When changing between the analog and digital models on the Unit 1
simulator, certain instruments (two) and simulator software must be
changed in order for the simulator to operate with the digital ICS
model.
The inspector noted that during the first training session,
those instruments were not swapped out.
Following malfunction training, operator performance was evaluated using
a single Job Performance Measure (JPM). The inspector questioned the
Operations Training Manager concerning the validity and confidence level
gained by using a single JPM to determine the retention of knowledge
following the training presented. The inspector further discussed that
administration of an examination comprised of a singular JPM may not
provide enough data points to infer that mastery of one JPM would
provide the confidence that all tasks were mastered. Administration of
one out of a possible nine JPMs would provide only a 11 percent testing
of all material testable.
At the end of the inspection the Training
Manager decided that one JPM was not sufficient to infer mastery of all
tasks and decided to use two JPMs for the evaluation.
The inspector reviewed the results for the first two weeks of
malfunction training. Three of the thirty one operators who received
this training'and a subsequent single JPM examination failed the
evaluation for a 9.6 percent failure rate. The inspector reviewed all
administered JPMs and follow-up questions and found a generic weakness
in the area of cross-limits.
The inspector reviewed eight of the nine JPMs available for use for the
final JPM evaluation.
At the time of the inspection, eight JPMs were
developed and available for review. The ninth JPM was not scheduled to
be completed until January 20, 1997. Each JPM consisted of the task
used for evaluation and two follow-up questions asked after the JPM was
administered.
c. Conclusions
The inspector concluded that malfunction training conducted on the new
digital ICS model was satisfactory. -All instructors presented the
material in a logical manner and allowed all operators to practice on
each task presented. The training was well received by all operators as
evidenced by their willingness to participate in the training. The
inspector also concluded that operators felt confident with going from
the analog to the digital ICS, providing they receive "just-in-time"
training prior to going to a unit with a different ICS model. The
inspector concluded that care must be taken to swap from the analog to
digital ICS models on the Unit 1 simulator in order to maintain
simulator fidelity and accuracy.
ENCLOSURE 2
The inspector concluded that administration of a singular JPM for
evaluation of training was not a sufficient sample to infer all tasks
were mastered. After discussion with the Operations Training Manager,
this practice of using one JPM was changed to add an additional JPM.
The inspector concluded that the administration of two JPMs with four
follow-up questions would provide a sufficient sample size in order to
infer mastery of tasks.
The inspector concluded that the JPMs developed were satisfactory to
determine operator performance for the tasks identified. The follow-up
questions provided additional information concerning operator knowledge
about the system. The inspector noted from evaluating the followup
questions, that cross-limits knowledge was a generic weakness of those
operators who received the evaluation.
07
Quality Assurance in Operation
07.1 Process for Administratively Controlling Procedures
a. Inspection Scope (40500)
The inspectors reviewed the issue documented in Inspection Report (IR)
50-269,270,287/96-15 associated with the licensee's failure to place the
heater drain Operations Procedure on administrative hold after
deficiencies were noted.
b. Observations and Findings
During the NRC Augmented Inspection Team (AIT) inspection documented in
IR 50-269,270,287/96-15, the inspectors identified that Operations
Procedure OP/2/A/1106/14, Moisture Separator Reheater, had not been
placed on Administrative Hold after necessary changes were identified
during a controlled Unit 2 startup of the system on May 7. 1996. That
startup had identified precautions and guidance that should enhance the
above procedure to make the heater drain system more manageable and less
susceptible to water hammer events during startup. Nuclear Station
Directive (NSD 703.12) Administrative Hold of Procedures, provides
implementing directions for placing procedures on administrative hold
when changes are required. This directive requires that the applicable
procedure shall be removed from the active document control files and be
placed into a designated Administrative Hold file, and that working
copies of the affected procedure .under this hold status be destroyed.
The above procedure was not placed on hold. The intended changes were
planned to be implemented at some future time. Consequently, on
September 24, 1996. station personnel attempted to place the Unit 2
MSRHs in service using the non-enhanced OP/2/A/1106/14, which had not
been placed on Administrative Hold to signify that changes were
necessary. This failure to place OP/2/A/1106/14 on hold is identified
as Apparent Violation (EEI) 50-270/96-17-08, Failure to Use Procedure
Administrative Hold.
ENCLOSURE 2
12
Since the AIT inspection, the licensee has revised Operations Management
Procedure OMP1-9, Use Of Procedures, Section 5.4, Administrative Control
of Procedures Removal From and Restoration to Service. The revision
defines conditions when a procedure should be removed from service, how
the removal is to be accomplished, and the requirements for restoring
the procedure for use. In addition, detailed training was provided to
increase the operator's awareness of the procedure changes.
c. Conclusion
The inspector reviewed the revised procedure and determined that
sufficient instructions were included to prevent recurrence of the
violation documented above.
08
Miscellaneous Operations Issues (92901)
08.1 Undervoltage Relay Failure Analysis
Two Unit 3 relays (27SY3/1C1 and 27SY3/1C2) associated with the
Emergency Power Switching Logic (EPSL) Standby Bus 1, Phase C,
Retransfer to Startup Logic experienced separate failures on November 13
and 19. The licensee actively performed a failure analysis which
determined that the subject Cutler-Hammer relays showed no common mode
failures with generic implication to the remaining relay population. As
part of the failure analysis the licensee performed an inspection of all
energized safety-related Cutler-Hammer relays to identify any damage,
and to ensure that the relay had acceptable date codes. In a letter
from the vendor to the licensee, relays manufactured from 6/74 to 7/76
were identified as possibly .containing an undersized magnet carrier that
could increase the probability of the coil clearing contact failing to
operate properly. Relay 1C2 was the only relay manufactured within the
specified time period. The licensee's inspection effort did not
identify any other problems with date code or damage with the relays.
The inspector concluded that the licensee was aggressive in pursuing the
possibility of a generic failure mechanism on the relays.
08.2 Closed IFI 50-287/96-16-06: ICS Malfunction Training Results
As addressed in Section 05.2, malfunction training on the new digital
ICS model was satisfactory. Accordingly, this item is considered
closed.
ENCLOSURE 2
13
II.
Maintenance
M1
Conduct of Maintenance
M1.1 General Comments
a. Inspection Scope (62707, 61726, 62700)
The inspectors observed all or portions of the following maintenance
activities:
NSM 22941, Modify Heater Drain System, Unit 2
PT/3/0610/01A
EPSL Normal Source Voltage Sensing Circuit
Unit 1 Auto Voltage Regulator Switching
NSM 32989, Unit 3 ICS Upgrade
PT/0/A/0250/25
HPSW Pump And Fire Protection Flow Test
TT/2/A/610/27, Unit 2 EPSL Relay Contact
Verification
0
TT/0/A/0620/030
Keowee Hydro Load Rejection Test, 4th Quarter
1996
PT/3/A/0251/24
HPI Full Flow Test
OP/3/A/1104/04
LPI System
PT/3/A/0610/O1J
EPSL Functional Test
b. Observations and Findings
The inspectors found the work performed under these activities to be
professional and.thorough. All work observed was performed with the
work package present and in active use. Technicians were experienced
and knowledgeable of their assigned tasks. The inspectors frequently
observed supervisors and system engineers monitoring job progress.
Quality control personnel were present when required by procedure. When
applicable, appropriate radiation control measures were in place.
c. Conclusion
The inspectors concluded that the Maintenance activities listed above
were completed thoroughly and professionally.
ENCLOSURE 2
M1.2 LPI Full Flow Test
14
a. Inspection Scope
On December 21, Operations, Maintenance, and Engineering performed a
Unit 3 full LPI flow test. The inspectors observed and evaluated the
major portions of test during its performance.
b. Observation and Findings
Test procedure TT3/A/150/44, LPI Full Flow Test, was conducted on Unit 3
with the reactor vessel head removed, fuel removed, and Low Pressure
Service Water (LPSW) secured.
During the test, the 3C LPI pump flow
was increased through both trains of LPI coolers to the RCS from 3000 to
4200 gpm in 250 gpm increments. The test checked pump differential
pressure, NPSH pressures, pump motor parameters, LPI cooler suction
temperatures, flow control valve position, and pump vibration levels.
The system engineer supported the test by coordinating data collection
and evaluation of the rough data. Additionally, the licensee checked
vibration levels on the newly installed thermal relief valve
modification (between the large RCS cold leg piping and first downstream
isolation valves) to determine, in part, the acceptability of its
installation per requirements specified in ASME Code OM-3.
c. Conclusions
The test results were satisfactory. Pump performance through each train
met the vendors pump curve within 3 percent. The test was performed in
a professional and controlled manner.
M1.3 High Pressure Injection (HPI) Full Flow Test
a. Inspection Scope
On December 24, Operations and Maintenance performed a Unit 3 HPI full
flow test. The inspectors observed and evaluated the major portions of
test.
b. Observation and Findings
Test procedure PT3/A/251/24, HPI Full Flow Test, was conducted on Unit 3
with the reactor vessel head removed, no fuel in the reactor vessel, and
LPI in service. The test increased 3A and 3B HPI pump flow separately
through both trains of HPI, respectively. Additionally, individual
flows were taken in each of the two branches for each train. The test
verified the operability of the pumps, the pumps' discharge check
valves, Borated Water Storage Tank (BWST)-to-pump suction check valves,
and newly installed branch loop check valves. At several points in the
test, Operations personnel had to perform critical timed evolutions and
coordinate test actions.
ENCLOSURE 2
15
c. Conclusions
The test results were satisfactory. All components tested performed
nominally. The test was performed in a timely and controlled manner.
M1.4 Keowee Load Rejection Test
a. Inspection Scope
On November 26. the licensee performed a load rejection test on both
Keowee hydro-electric units at a new low lake level. This was done to
provide data for a new Selected Licensee Commitments curve limit for
Keowee power production to the grid. The inspectors observed the test.
b. Observation and Findings
The load rejection test was satisfactorily completed per
TT/0/A/0620/030, Keowee Load Rejection Test - 4th Quarter 1996. The
test was well controlled and both Keowee hydro-electric units operated
well.
Both units were very similar in operational characteristics and
control system performance.
During test performance, a fuse blew in the control circuits for Air
Circuit Breaker ACB-7. The breaker loss reduced the number of Keowee
auxiliary power sources. Operations tracked the condition and the test
procedure was appropriately exited. The system engineer and an
electrical maintenance supervisor supported trouble-shooting and repair
of the breaker which was administratively controlled by WO 96094606-01.
All work was well planned and implemented. The failed fuse was in
accordance with the circuit drawings. The breaker was satisfactorily
bench tested prior to returning it to service.
Once in service, the
breaker was cycled under loading prior to returning to the test
procedure.
c. Conclusions
The test met acceptance criteria. Appropriate test gear and support
personnel were available for the test. Trouble-shooting .and corrective
actions regarding the circuit breaker problem were performed with a high
level of professionalism and completeness.
M1.5 Maintenance Corrective Actions Following Water Hammer Event
a. Inspection Scope
The inspectors reviewed maintenance activities conducted as corrective
actions following a water hammer event in September 1996. (Reviews of
operational issues related to that event are described in sections 05.1.
07.1 and E2.3. Inspections of related pipe hanger and support issues
are described in sections E2.1, E2.2, and E2.5.)
ENCLOSURE 2
16
The licensees' reviews after the water hammer and subsequent reheater
steam line rupture identified that some balance of plant piping systems
at Oconee did not meet requirements of the piping code referenced in the
UFSAR. The deficiencies included failure to meet code requirements in
the following major areas:
numerous branch pipe connections were not
properly reinforced, some piping was not properly protected from
overpressure, and some piping may have been replaced with different
material without proper engineering analysis to ensure that design
strength requirements were met. The inspectors reviewed the licensee's
actions to verify adequate overall scope of the reviews after the event.
The inspectors also reviewed some specific corrective actions initiated
to address the identified problems.
b. Observations and Findings
Lack of Reinforcement on Certain Branch Pipe Connections
The licensee's walkdown of Class G heater drain piping revealed that
certain field fabricated branch connections were missing reinforcement
collars/saddles which were typically found on headers depending on
certain local pipe conditions, including pipe size, thickness, pressure,
and temperature rating. In order to investigate this apparent problem,
the licensee established a task group whose objectives were as follows:
0
Conduct engineering evaluations on all Class G branch connections
to determine the scope of field inspections.
Perform detail engineering evaluations using as-built field
measurements to determine code compliance.
Modify/repair all branch connections where calculations showed
they did not meet applicable code requirements.
The screening criteria used to determine which branch connections were
acceptable and therefore exempt from this project were as follows:
Design pressure s 100 psig. This pressure limit was based on
engineering analysis.
Pipe diameter less than 2.5 inches. This pipe size was based on
applicable code requirements and computational analysis.
Pipe wall thickness and reinforcement area. Acceptability based
on calculations specified by the code using the above mentioned
thickness measurements.
The following table depicts the status of the Branch Connection Project
at the start of this inspection.
ENCLOSURE 2
.17
U1
U2
U3
TOTAL
Identified by Engineering as
100%
100%
100%
N/A
needing evaluation (% complete)
Sent to field for inspection
215
214
232
661
Field inspection complete
1
193
1
195
Detailed Engineering evaluation
1
169
1
171
complete
Number requiring modification
0
51
0
51
Number of design packages
0
19.
0
19
to field
By review of the licensee's data generated from field inspections and
engineering calculations, the inspectors ascertained that code required
reinforcement collars were missing from branch connections in the
following systems:
System
Unit 1
Unit 2
Unit 3
Moisture Separator Reheater (MSRH)
20
23
1
Heater Vent & Heater Drain
10
17
1
High, Low Press. Extraction
2
4
0
Auxiliary Steam (AS)
0
1
0
0
0
2
Main Steam (MS)
4
2
0
5
1
0
Condensate
6
10
0
TOTAL
47
58
4
The inspectors noted that paragraph 104.3 of USAS B31.1-67 Power Piping
Code, (Code) states in part that when a pipe is penetrated by a branch
connection, the size of which weakens the pipe, additional reinforcement
must be provided. The type and amount of reinforcement to be provided
must meet the requirements of paragraph 104.3.1(d). Oconee Updated
Final Safety Analysis Report (UFSAR) Section 3.2.2.2 states, in part,
that Class G piping shall be designed, installed, and tested in
accordance with the USA standard B31.1, 1967 Edition Power Piping Code
(code), requirements. Plant piping was not installed in accordance with
requirements in the piping code referenced in the UFSAR and a written
safety evaluation was not recorded as required by 10 CFR 50.59 (b)(1).
ENCLOSURE 2
18
This is identified as Example 1 of Apparent Violation (EEI) 50
269,270,287/96-17-01. Failure To Complete A Written Safety Evaluation Of
Secondary Plant Piping Not In Accordance With The Piping Code Referenced
In The UFSAR. (Paragraph M1.6 below describes inspection of welding
activities to install the missing reinforcements.)
Overpressurization Protection Issues
As a result of the water hammer event in Unit 2 Second Stage Reheater
(SSRH) piping, the licensee performed an in depth investigation to
review the issue of overpressure protection concerns regarding Class G
piping at Oconee Nuclear Station (ONS). Similar instances of specific
overpressure protection concerns had been identified by Design
Engineering as early as 1989 for several steam systems (AS, MS and Plant
Heat). These concerns were identified as a result of a corrective
action resulting from the Emergency Feedwater (EFW) Safety System
Functional Inspection which found that relief valve MS-92 was
undersized. The licensee's investigation included review of past
concerns documented in PIRs, PIPs and Oconee Engineering Design Basis
(OEDB), and review of ONS Flow Diagrams of secondary systems to identify
other potential code discrepancies.
The issues identified by the above reviews were incorporated into nine
PIPs, which were as follows:
PIP 96-2149 Potential Overpressure of Underrated Components
PIP 96-2150 Overpressure Due to Undersized Relief Valves or No
Relief Valves
PIP 96-2151 Steam Trap Discharge Piping Not Meeting Code
Requirements (ANSI B31.1).
PIP 96-2152 Overpressure Due to Inadvertent Valve Closure.
PIP 94-1391 Hydrogen Overpressure Issue.
PIP 96-2472 HPSW to the Filtered Water System.
PIP 96-1762 LPSW Pump Suction Piping Overpressure.
PIP 96-2486 D Flash Tank Overpressure Issue.
PIP 96-2153 OFD Design Parameter Flag Problems.
By review of selected PIPs and associated engineering assessments
generated in response to the as-built system inspections, the inspectors
noted the following:
Several existing as-built conditions where piping lines could
become overpressurized due to valve location, alignment and or
leakage were listed in PIP 96-2149. Examples of systems where
such conditions were found included: Steam Generator Blowdown
Piping, Feedwater Piping, Main Steam Bypass Pumping Trap Piping,
Low and High Pressure Service Water Piping. Examples of systems
with installed underrated valves included: Steam Trap valves in
the auxiliary steam system, Main Steam Pumping Trap check valves,
and Steam Drain valves.
ENCLOSURE 2
19
PIP 96-2150 listed several examples where the present relief
valves were too small to provide adequate overpressure protection.
These conditions were identified in the Auxiliary Steam and the
Plant Heating Systems. In several instances the licensee could
not retrieve sizing calculations to help determine the adequacy of
the present valve arrangement. Also, in a couple of instances the
system was not equipped with overpressure protection (e.g., Plant
Heating System and Auxiliary Steam, downstream of valve AS-414
where class rating changed from 125 psig to 75 psig).
PIP 96-2151 listed numerous as built examples of steam traps on
the Auxiliary Steam Header to the Radwaste Facility and on the
Steam Drain System where the change in the design pressure rating
occurred immediately after the regulating valve instead of the
last isolation valve as required by the code. Accordingly, the
above PIP listed 11 examples in the Auxiliary Steam system. Oconee
Flow Diagrams (OFD 117J-1.1 and OFD 128A-1.3) and four in the
Steam Drain system, (OFD 122A-1.5,-2.5 and-3.5) where valves and
associated piping required upgrading to meet system pressure and
temperature requirements.
PIP 96-2152 listed 16 examples of as built valve and associated
piping in several systems where an inadvertent closure of a
downstream valve could result in the overpressurization of piping.
An example of such isolation valves included: 1AS-49 on the
Auxiliary Steam system; valve CF-53 on the Core Flood system;
valves CCW-89 or CCW-416 on the Component Cooling system. Other
systems identified as vulnerable to inadvertent valve closure
included heater drain piping between "B" & "C" and, "C" & "D" FDW
Heaters; FW Heater Vents "A," "B,"
"C," and "D"; Discharge and
Suction HDP piping.
To track these findings, the licensee generated spread sheets which
identified pipe sections between valves and or -components where over
pressure protection was lacking or overpressurization could occur under
certain conditions. This tracking system was also used to identify
certain valves, which under certain conditions could see pressures
beyond code allowable ratings. Engineering calculations were being used
to compare the as-built conditions with code requirements. OFDs were
used to mark up the areas where the potential overpressure protection
problems were identified. The inspectors reviewed selected engineering
assessments, evaluations, calculations and OFDs for accuracy and
technical adequacy.
This work effort was performed for Plant Heating,
Condensate, Low and High Pressure Service Water, and Auxiliary Steam
systems.
The majority of the modifications required upgrading,
qualification, and/or replacement of piping: upgrading or replacement of
valves; and the changing of pressure boundaries on the OFDs.
From these reviews, the inspectors ascertained that a total of 71 valves
had been designated for possible overpressure protection modifications
ENCLOSURE 2
20
in the Auxiliary Steam system. Of these. 20 had undergone engineering
evaluations and had been forwarded to Work Control for disposition.
Eight of the 20 valves are shared between the three Oconee Units and
were therefore placed on the licensee's Unit 2 Restart List for early
disposition.
Regarding the OTSG Blowdown Preheat System on Unit 2, OFD 123A-1.3
engineering reviews identified that several valves were underrated.
Typically these valves were rated for 900 psi which was acceptable for
blowdown conditions; however, on a unit trip these valves could see
pressures in the range of 1050 psi, which would be above their design
rating. By document reviews and through discussions, the inspectors
ascertained that there-were approximately eight valves listed in this
category. Some of these valves were shared by two of the three Units
and were scheduled for replacement or removal from the system prior to
Unit 2 restart. At the close of this inspection, none of the work
packages had gone to Work Control for disposition.
Failure to implement design requirements with respect to operating
pressures and temperatures for normal conditions, local conditions and
transients as described in Section 102 of the Code is identified as
Example 2 of the above mentioned Apparent Violation 50-269,270,287/96
17-01.
Replacement of Carbon Steel Piping With Stainless Steel Without
Sufficient Engineering Analysis
The licensee also identified an issue involving the possible use of
unsuitable material on certain piping systems. The issue was the use of
stainless steel piping as a replacement for carbon steel material. Of
particular interest was the question whether adequate engineering
analysis had been performed to assure that design strength requirements
were not being compromised by the replacement of carbon steel piping
with stainless steel piping. This engineering -analysis was required by
Specification OS-0242.00-00-0001, Revision 17 Note 24, which stated in
part that when a choice of two different type materials were specified
by the OFD (i.e., stainless and carbon steel materials) an engineering
evaluation and approval was required prior to the change. PIP 96-2359
was revised to address this question and to assure that an engineering
evaluation was performed and approved as required-. This item was
identified as Unresolved Item 50-269.270.287/96-17-04, Engineering
Evaluation for the Replacement of Carbon with Stainless Steel Piping.
c. Conclusion
Several examples of piping code violations were identified. Numerous
secondary plant branch piping connections were not reinforced as
required by the code referenced in the UFSAR. A large number of
deficiencies associated with overpressure protection on balance of plant
systems were also identified. The inspectors concluded that the
ENCLOSURE 2
21
deficiencies were caused by failure to assure that code design
requirements were translated into appropriate instructions and/or
drawings.
The deficiencies resulted in an inadequate field inspection
and verification program to assure that design requirements were being
adequately implemented by construction.
After some problems were identified following the pipe rupture event on
September 24, 1996, the licensee was quick to respond and took
appropriate actions to identify all as built discrepancies and initiated
actions to assure that the problems were corrected. (Paragraph M1.6
describes additional review of the related welding activities.) The
licensee's response and dedication of engineering construction resources
to address these problems and bring secondary plant systems into code
compliance, was regarded as good.
An unresolved item was identified involving the adequacy of engineering
evaluations of stainless steel piping as a replacement for carbon steel
material.
M1.6 Maintenance Welding (55050)
a. Inspection Scope
This inspection was performed to observe certain aspects of Heater Drain
Pipe modifications as described in NSM-22941 and weld repairs resulting
from a water hammer event in the Unit 2 Moisture Separator Reheater
(MSRH) Drain Pipe System. For more details see IRs 96-15 and 96-16.
The inspector observed welding in progress and reviewed weld process
control records for modifications in the MSRH and the Heater Vent and
Drain piping.
b. Observation and Findings, Unit 2
Modification procedure NSM-22941, Part AM1, was used to provide
instructions and documentation for installation of drain lines,
replacement of damaged piping, reinforcement of certain branch
connections, and the installation of certain check valves to the First
and Second Stage Reheater Drain Tanks A and B. The code of reference in
Section 3.2.2.2 of the Oconee UFSAR, applicable to design and
installation activities of class G piping is the United States of
America Standard Piping Code. B31.1 1967 Edition.
At the start of this inspection period, installation commenced on
reinforcement collars for branch connections of the Heater Vent and
Drain System of Unit 2. As such, the inspector observed the welds
listed below for compliance with Field Weld Data Sheet (FWDS)
requirements, good workmanship practices, and control of filler metal
material. Welder identification numbers were noted for review of their
qualifications.
ENCLOSURE 2
22
Branch Conn.
Drawing/Location
Size
123A-2.3-022
1410F/K4
18"x18"
123A-2.3-026
1410E/G6
18"x6"
123A-2.4-027
1410A/C5
8"x8"
123A-2.4-034
1410A/G5
8"x8"
123A-2.4-037
1410E/D6
8"x8"
As required by the Oconee Welding Manual, work control including
inspections and documentation was done in accordance with procedure
MP/0/B/1810/015, Change 17, and work orders 96091370-01/96090645-01.
Based on the work observed and review of supporting documents, the
inspectors determined that welders were adequately trained to fabricate
these weldments, documentation was consistent with procedural
requirements, and control of filler metal was satisfactory at the work
area and at the issue station. Filler metal certification records were
reviewed and found to be satisfactory. Weld records showed that
completed welds were being inspected by trained Quality Control (QC)
Welding Inspectors.
To verify that field welds were being fabricated and inspected in
accordance with requirements of procedure MP/0/B/1810/015 and Code B31.1
Section 127 Welding, the inspectors selected at random a total of 51
welds of various pipe sizes ranging from about
to 18 inches in
diameter. These welds were shown in drawing numbers 2HD-107, -109.
-111, -112,-113, and -116. Within these areas, the inspectors checked
for weld reinforcement uniformity and height, undercut, arc strikes,
weld spatter, cleanliness, material and welder identification. The
inspectors identified two welds (1 and 11) on Drawing 2HD-107 that
exhibited workmanship anomalies. For example, weld #1 showed that a
short length on one side of the joint had not been adequately welded and
weld #11 showed that the weld reinforcement thickness was slightly above
the allowable. Both conditions were discussed with the cognizant
welding supervisor and the QC supervisor who verified the as found
condition and took immediate corrective action. To prevent recurrence
of this problem, the subject procedure was revised to include a table-of
allowable weld.reinforcement thicknesses for the range of materials
welded.
In addition to this review effort, the inspectors reviewed radiographs
of two welds that had been selected at random by the Maintenance Support
Manager in charge of welding Quality Control. The welds were on the
Heater Drain and the Main Steam systems. Both of these systems were
Duke Class G and were radiographed per Duke's Radiography Procedure NDE
10 Rev. 19 and the acceptance criteria of B31.1-67 Code.
ENCLOSURE 2
23
The subject welds were identified as follows:
Weld No.
Drawing No.
Size
3MS 29
122A-3.2
12"x.688
108
3"x.300
Weld and film quality for these radiographs were consistent with code
requirements.
c. Conclusion
The licensee's welding activities observed during this inspection period
met the requirements of the applicable code. In general, weld
appearance was adequate. Fina inspection of welds by QC inspectors
which was implemented for this modification was a positive step in
assuring that good welding practices were being followed in pursuit of
good weld quality. Although this inspection focused on welding
activities, engineering evaluation, calculations, and inspections
relative to Unit 2 MSRH modification, the inspector observed that the
same program applies to and was being implemented in Units 1 and 3.
M1.7 Welding Repair of Primary Coolant Components
a. Inspection Scope
The inspectors reviewed the licensee's actions regarding the
identification and repair of a leak on the 1A2 reactor coolant pump
b. Observation and findings
The 1A2 RCP has experienced leakage in the area of the seal assembly
over several years. Some of the problems included the seal piping
flange, the radial bearing thermowell, and pump main flange to
lower seal housing. During the last refueling outage (RFO), End of
Cycle (EOC) 16, the licensee performed an interim repair on the seal but
some leakage was observed during startup. The leakage worsened during
this past cycle with significant accumulation of boron crystals observed
at the pump during hot shutdown. An inspection of the suspect area
during the current Unit 1 forced outage revealed crack indications at
the pump main flange bore (face and inner diameter). The crack
indications were subsequently dye penetrant examined to determine the
extent of the defect and to assist in mapping out the exact location. A
repair procedure was developed to: (1)
excavate the defect for analysis.
(2)
grind out the minor indications and perform dye penetrant testing,
and (3)
restore the affected areas back to sound qua lity. Following the
repair, a Minor Modification ONOE-9155 was to be implemented for
machining a new 0-ring groove on the repaired main flange surface. This
ENCLOSURE 2
24
modification will represent a minor design change to the configuration
of the RCS pressure boundary, in the area of the RCP main flange to the
lower housing.
Weld Repair
The 1A2 RCP is a Westinghouse Model 93AS, with a main flange made of a
SA351, Grade CF8 18-8 stainless steel casting. The pump was
manufactured to the ASME Code Section III Class A. 1965 Edition, with
addenda through 1967. The repair was being performed to the ASME Code
Sections III and XI, 1989 Edition requirements. The welding was being
performed by qualified welders who had been given adequate training on a
mockup, by simulating field conditions. The repairs were made with a
Duke qualified weld procedure utilizing the shielded metal arc process
and a stringer bead technique to minimize heat built up and residual
welding stresses. Weld build up was accomplished using E 308 stainless
steel filler metal.
This material has greater strength and sufficient
amounts of delta ferrite to suppress the potential for microcracking
during welding. Component configuration, thickness size, and space
restrictions precluded doing radiography on the repair. In lieu of
radiography, the licensee performed liquid penetrant examination on the
root pass, at each 1/2 inch interval of weld deposit and on the final
pass. At the close of this inspection, Duke was preparing a request to
the NRC for relief from the radiography requirements, since it was not a
viable option due to configuration and location.
In an effort to identify the root cause for these defects, the licensee
removed a boat sample and forwarded it to Westinghouse for analysis. In
addition, the licensee contracted a vendor to perform a fracture
analysis to determine the suitability of the repaired component for
continued service. Also, in reference to the root cause for the
cracking, Duke took field measurements for residual delta ferrite around
the crack and at the immediate area. Results of this investigation
revealed no evidence of measurable ferrite in the immediate area of the
crack but appeared to be within the normal range in the surrounding
area.
Preliminary results from the metallurgical investigation and the ferrite
checks suggest that the crack indications may have been due to a lack of
-adequate amounts of ferrite to prevent cracking during casting
solidification. A copy of the final report will be provided for review
on a future inspection.
c. Conclusion
Evaluation of the RCP main flange crack defects and the subsequent
repairs were well planned and executed. Welding and nondestructive
testing examinations were performed by well trained individuals using
approved procedures that met code requirements. Engineering and
ENCLOSURE 2
25
technical resources were adequate and supervision of the'repair was
good.
M1.8 Modification to Low Pressure Service Water (LPSW) "B"
Line Header
a. Inspection Scope
The inspectors reviewed PIP 96-2059 and evaluated the adequacy of NDE
examinations performed as required by ASME Code Section XI. Code Case N
416-1.
b. Observation and Findings
This item involved a modification on the Unit 1 LPSW where a 24 inch
diameter branch conn iection was attached to the LPSW "B"
Line Header.
The modification was performed on a portion of this system designated as
ISI Class "C"
which corresponds to ASME Code Class 3. As such, the
licensee opted to use ASME Section XI Code Case N-416-1 in lieu of the
required hydrostatic test following pipe installation/construction. The
NRC authorized the licensee to use this Code Case by letter dated March
27, 1996, as Relief Request No.95-GO-001. This Code Case requires that
Non-Destructive Examination (NDE) be performed (on new or weld repairs)
in accordance with methods and acceptance criteria of the applicable
subsection of the 1992 Edition of ASME Code Section III.
As required by
the licensee's applicable procedure QAL-5, ASME Code Section XI, Class 3
welds tested under Code Case N-416-1 must undergo magnetic particle or
liquid penetrant examinations on both root and final weld pass. In
addition, following completion of these NDE requirements, the new line
must undergo a VT-2 pressure test at normal operating pressure and
temperature.
By review and through discussions with cognizant personnel, the
inspectors ascertained that NDE examinations on eight welds on isometric
drawing 1LP474 in Unit 1 did not comply with the requirements of this
Code Case. The Weld Process Control Sheets (WPCS) were filled out
correctly in that they included the NDE requirements of Code Case N-416
1. However, because of an apparent miscommunication, Quality Assurance
(QA) deleted the applicable NDE requirements, meaning that the eight
completed welds received a final visual and a surface examination on the
final pass-which is the typical NDE for Code Class 3 welds. Six of the
eight welds were hydrostatically tested, but not to code requirements.
Upon discovering the problem the licensee issued PIP 96-2059 and took
corrective action. The above mentioned PIP characterized the problem as
a missed surveillance per TS 4.2.1 and Section lB of Appendix A of NSD
203. As such, the licensee declared that the LPSW system was capable of
performing its intended design functions but did not meet the applicable
code requirements. An operability limit was established which required
that the affected Units 1 & 2 remain below 2500 F and declared the
system operable, but degraded. The compensatory measure was that both
ENCLOSURE 2
26
units would remain below 2500 F until the subject welds met all Code
Case N-416-1 requirements or a code relief was granted by the NRC.
Following a review of the aforementioned PIP and discussion with
cognizant licensee personnel, the inspectors concluded that the problem
was not an issue of a missed TS surveillance. Moreover, the inspectors
concluded that the missed NDE was intended to satisfy construction code
and code case requirements. The latter was implemented as an alternate
for the code required hydrostatic test which had to be done before the
line could be turned over to operations.
This failure to implement code and procedural requirements is a
violation of 10 CFR 50 Appendix B Criterion V. This violation was
identified as 50-269/96-17-09: LPSW Modification Did Not Meet ASME Code
NDE Requirements.
c. Conclusion
The licensee did not meet the Code Case requirements or alternate Code
requirements for the subject welds. A violation was identified.
M4
Maintenance Staff Knowledge and Performance
M4.1 Control of Measuring and Test Equipment (MT&E) (37550)
a. Inspection Scope
The inspectors reviewed the licensee's control of M&TE related to
evaluation of out of tolerance (OOT) equipment usage. Applicable
regulatory requirements included 10 CFR 50, Appendix B and the
licensee's approved Quality Assurance (QA) program. The OOT reports and
evaluation activity was reviewed for Maintenance Instrumentation and
Electrical (IAE) tool issue, mechanical tool issue, and Commodities
receipt inspection M&TE.
b. Observations and Findings
Licensee procedures required the evaluation of the measuring and test
activity performed prior to the identification of 00T or lost M&TE.
Maintenance Directive 4.4.1, M&TE Control, dated May 30, 1994, required
evaluations to be performed within 14 working days following the
discovery of OOT or lost M&TE. Procurement procedure. TIP-701.
Instructions for Control of M&TE, dated March 28. 1996, required the
evaluations to be performed in seven working days following discovery of
OOT or lost M&TE. The inspectors reviewed approximately 25 open OOT
reports in the IAE tool issue. Approximately 20 of these were overdue
without approved extensions. The following examples illustrate the age
and equipment types:
ENCLOSURE 2
Instr.#
1227
Date Discovered
Due Date
(includes
extensions)
30933
digital thermometer
10/2/96
11/4/96
31620
digital thermometer
10/3/96
10/25/96
31515
megohm meter
10/10/96
11/5/96
31102
C-clamp calibrator
3/19/96
4/23/96
30824
temp. calibrator
12/6/95
5/2/96
31644
crimping tool
4/17/96
5/14/96
30755
micro-ohm meter
8/2/95
11/9/95
27163
pressure test gage
4/18/95
10/26/95
27104
pressure test gage
6/25/95
7/17/95
Although the 00T reports were appropriately initiated, there appeared to
be inadequate followup to verify the evaluations were performed.
The mechanical tool issue timeliness for OCT evaluations was good in
that there were no open OOT reports. The inspectors reviewed two
completed reports to assess the quality of the evaluations. The OOT
report on micrometer OCMNT-27790, dated February 5, 1996, listed 17
previous use work orders for the device. The evaluation stated that the
previous use was acceptable based on performance of post maintenance
testing (PMT) performed on the work orders. There was no indication of
how the PMT enveloped the measuring or test activity accomplished by the
micrometer. The OT report of lost torque wrench OCMNT-26778, dated
April 1, 1996, also referenced the performance of PMT as the basis for
accepting previous use of the lost wrench. No torque verification was
performed. The inspector discussed the weak evaluation basis with the
licensee and was provided PIP 0-095-1226, dated September 27, 1995,
which provided guidance to maintenance staff for OCT evaluations. This
guidance indicated that PMT was acceptable justification for accepting
previous use of OT or lost M&TE. The inspector concluded that the
evaluations, using the PMT for justification of previous use, did not
adequately assess the previous use of the OT M&TE.
A multi-amp breaker tester in the Commodities receipt inspection area
was discovered OT on September 5, 1996. PIP 4-096-1931 was initiated
on October 7, 1996, and corrective actions for the evaluation of impact
on past usage was required on November 6. 1996. As of November 21,
1996, no evaluations had been performed. This example demonstrated that
the PIP process was not an effective mechanism to assure evaluations
were performed within the applicable procedure time constraints of seven
working days.
The examples identified by the inspector were identified as Violation
50-269.270,287/96-17-02, Failure to Perform Evaluations of Out of
Tolerance M&TE.
0
ENCLOSURE 2
28
c. Conclusion
The licensee did not meet their QA program requirements for M&TE.
Several examples were identified in which timely and adequate
evaluations of out-of-tolerance M&TE were not performed.
M8
Miscellaneous Maintenance Issues (92902)
M8.1
(Closed) Inspector Followup Item 50-269.270.287/95-12-01: Apparent
Ultrasonic Testing (UT) Examiner and UT Procedure Weakness
This item was written to address certain concerns relative to the
adequacy of Ultrasonic Procedure NDE-600 and its use during field
examinations. In addition, the inspector had determined that although
the subject procedure had been endorsed by Electric Power Research
Institute (EPRI), it was not identical to the EPRI procedure with
respect to the methodology used to determine the presence of geometric
flaws. Accordingly, on July 11, 1995, the inspector attended a
procedure demonstration at the EPRI facility in Charlotte, NC. Since
this demonstration, the following corrective actions have been
implemented:
UT data from Oconee's main coolant piping, inspected using
Procedure NDE-600.- has been reviewed and evaluated by Duke's Level
III UT Examiner and have been found to be correct.
Procedure NDE-600 has been revised to clarify the applicable
attributes for circumferential and axial scans and to clarify that
only two applicable attributes need to be met to call an item a
flaw.
'Appropriate training has been performed to improve understanding
of procedural requirements and applicable revisions.
Based on a review of these completed actions, this IFI is closed.
III. Engineering
E2
Engineering Support of Facilities and Equipment
E2.1 Water Hammer Issue -
Turbine Building (TB) Floor Overpour
a. Inspection Scope (37550. 37551)
The inspectors reviewed the equipment anchorage of TB safety-related
equipment to determine if the non-reinforced 12-inch overpour impacted
the anchorage requirements. Nonsafety-related piping anchored in this
floor had experienced pull-out during a previous water hammer event.
Applicable regulatory requirements were provided by 10 CFR 50, Appendix
B, and the UFSAR.
ENCLOSURE 2
29
b. Observations and Findings
The LPSW and EFW systems are the safety-related systems with equipment
anchored to the TB floor. The anchorage drawings for the LPSW and EFW
pumps indicated that the anchor rods extended below the overpour to the
rebar reinforced portion of the floor. Safety-related pipe supports for
these systems were anchored to the floor with expansion bolts which did
not extend to the reinforced portion. The inspector reviewed the
licensee's civil engineering evaluations of the potential uplift force
which determined the worst case seismic load to be a 6000 pound uplift
force on one support anchor plate. This indicated that the safety
related anchors were adequately supported for seismic loads.
This force
was considerably less than the estimated 26,000 pound pull force
experienced in the moisture reheater water hammer which pulled out an
existing anchor plate.
The LPSW and EFW systems had no history of water
hammer occurrences: therefore, the excessive uplift forces resulting
from water hammer were not a concern.
c. Conclusions
The non-reinforced overpour on the TB floor provided no apparent
limitation on the seismic anchorage of safety-related equipment in this
building. There was no history of water hammer on these systems;
therefore, the anchorage for the safety related equipment was adequate
for the anticipated loading.
E2.2 Water Hammer Issue - Potential Issues in Modification and PIP Backlog
a. Inspection Scope
The inspectors reviewed the backlog of PIPs and modifications to
determine if these contained significant equipment or safety issues. A
list of approximately 1000 open PIPs were reviewed to identify trends or
specific equipment problems. Modifications were a subset of PIPs as
these were developed to resolve PIPs. A more detailed review was
accomplished on 30 PIPs selected from the list. The applicable
regulatory requirements were provided by 10 CFR 50, Appendix B.
b. Observations and Findings
With one exception, no significant equipment or safety issues were
apparent in the backlogs which were not being appropriately addressed.
There were several PIPs since 1990 which identified wrong fuse size or
type installed in equipment circuits.
Discussions with the licensee
indicated that frequently the fuses were oversized which was
conservative with respect to equipment operability. Drawings had been
developed to list the correct fuse size and type for plant equipment
which indicated that the issue was being addressed.
ENCLOSURE 2
30
The inspector noted a potential safety-related equipment problem related
to the Reactor Building Cooling Units (RBCUs). PIP 0-095-0267, dated
February 27. 1995, identified four blown fuse occurrences which resulted
in inoperable RBCUs. These occurred during testing in 1991, 1992, and
1994. The PIP identified that the wrong type fuse was installed in all
RBCUs. Fast acting fuses were installed where time delay fuses were
applicable. Approved controls directed that the fast acting fuses were
to be installed. The fuses were blown as the result of the motor in
rush current on starting the equipment. The Unit 1 fuses were replaced
with time delay fuses on July 23, 1996. Unit 3 fuses were replaced on
June 21, 1995. Unit 2 fuses had not been replaced at the end of the
report period.
The PIP did not identify or address the potential common mode failure of
the RBCUs due to the wrong fuse type. No comparison was made of tested
conditions against expected accident conditions. The information
available was insufficient to determine if an RBCU operability concern
resulted from the fast acting fuses. Pending further review, this item
is identified as URI 50-269,270,287/96-17-03, RBCU Operability Concerns
Due to Wrong Type Fuse in Control Circuit. This item remains open
pending the licensee's evaluation of the RBCU tested conditions versus
accident conditions to assess equipment operability impact.
c. Conclusions
With one exception. no apparent significant equipment or safety issues
were identified in the PIP and modifications backlogs. A URI was
identified to determine if the wrong type fuse in the RBCUs was an
equipment operability concern.
E2.3 Unit 2 Steam Drain Modifications
a. Inspection Scope
The inspectors reviewed modifications NSM ON-22901 and NSM ON-22941 to
the Unit 2 Steam Drain System. The modifications were generated to
reduce water hammers in the steam drains from the Moisture Separator
Reheaters. The inspectors observed day to day implementation of the
modifications in all three plants, particularly Unit 2. These
inspections were performed in addition to the inspections addressed in
Sections M1.5 and M1.6.
b. Observations and Findings
In 1991 and 1993, the licensee had placed a "hold" on modifications NSM
ON-22901 and NSM ON-22941, respectively, due to priority of other
modifications, pre-empting secondary changes. Therefore, the design had
not been completed at the time of the September 24, 1996, pipe rupture
event in Unit 2. After the incident, the licensee procured the services
ENCLOSURE 2
31
of several outside consultants to help better understand water hammers
prior to completing the design on the modifications.
One of the consultants provided general water hammer training to
licensee staff at large. On November 13, 1996, the inspectors witnessed
a steam/water hammer demonstration at the ONS training facility. The
demonstration had evolved from steam/water hammer problems experienced
at another facility that had consequences similar to those experienced
at ONS. The exhibition was shown to all Operations personnel and many
other site personnel. The display was a small scale piping model that
consisted of clear glass piping, valves, colored water, and a heat
source. It closely modeled the portion of the Unit 2 steam drain system
associated with the pipe rupture event. It clearly demonstrated the
reaction of steam and water in low areas of piping that form a loop-seal
and the effects that could be expected. It further dispelled the belief
that water hammers would be eliminated by reducing the rate of steam
flow into a system partially filled with cooler water. This exhibition
and input from vendors resulted in revision changes planned for
operations procedure OP/1,2,3/A/1106/14, Moisture Separator Reheater,
and changes to major NSMs (NSM-22901 and NSM-22941) that are being
implemented during this shutdown period.
The major areas addressed by each modification and inspector activities
are as follows:
Nuclear Station Modification 22941
The inspectors reviewed work activities in progress on an almost
daily basis during the implementation of NSM 22941, Secondary
Systems Control .and Valve Upgrade. The welding activities were
closely monitored by-the inspectors. Major areas of the
modification consisted of the following:
-
.Replacement
of 2MS-112.& 173 main steam valves and
associated control systems that supply steam to the second
stage reheaters in the MSRHs.
-
Installation of check valves for the Second Stage Reheater
Drain Tanks. 2A and 2B.
-
Installation of check valves for the First Stage Reheater
Drain Tanks, 2A and 2B.
-
Relocation and/or replacement of heater drain pressure,
temperature, and level control systems.
-
Installation of low point drains to eliminate condensate in
headers when steam is induced.
ENCLOSURE 2
32
-
Replacement and modification of piping/fittings and hangers
to upgrade system to code requirements and eliminate
potential water/steam hammers.
Nuclear Station Modification 22901
This modification interfaced with NSM 22941 and was performed in
parallel. The inspectors were able to review both modifications
during regular inspections of that plant area. The primary
equipment involved in this modification were:
-
Perform a stress analysis on the Second Stage Reheater Drain
Tank and pipe supports to evaluate hangers and tank nozzle
loadings.
-
Replace heater drain valves, 2HD-25, 26, 29, and 30 to
prevent leakage, steam/water hammer problems, and improve
control of system.
Both NSM 22901 and 22941 were implemented in a methodical and careful
manner. Pipe fitter foreman, QC personnel, overseeing engineers, and
management were routinely seen in the work areas. Cleanliness and fitup
requirements were observed to be met. Welders and pipe fitters were
knowledgeable of the jobs they were performing. Management in charge of
the project were aware of all job aspects and were fully supported by
the design engineers.
Planners were providing good packages to the
workmen.
c. Conclusions
The inspector determined that the licensee's on-going implementation of
the modifications was adequate. Although the licensee has not completed
the modifications and final testing of the modified equipment can not be
completed until system restart, there have been-no deficiencies
identified that should prohibit plant restart.
E2.4 Current Pipe Specification Allows Installation of Piping Material
Unsuitable for Design Pressures
a. Inspection Scope
As described in other sections of this report, the licensee performed
detailed reviews of secondary plant piping issues after a reheater line
ruptured in September 1996. The review indicated that current pipe
specifications were not adequate to ensure that proper material was
used. The inspector reviewed this issue,
ENCLOSURE 2
_
_
_
_
_33
b. Observations and Findings
At the time of this inspection the licensee identified that Pipe
Installation Specification OS-0234.00-00-0001,(300.4), allowed the use
of American Petroleum Institute (API), API-5L carbon steel welded pipe
material for pipe sizes greater than 24 inches. The Power Piping
Quality Assurance (PPQA) Manual that was used during plant construction
specified A-155KC-70 Class material for pipe 26 inches and larger in the
Condensate System. The allowable stress for API-5L material was only
about 70 percent of allowable for A-155KC-70 Class 1. The licensee's
analysis on pipe branch connections within this system indicated the
API-5L material was unsuitable for the applicable design pressures. On
November 12, 1996, the licensee issued PIP 96-2359 and began an in-depth
review of engineering documents to determine if API-5L material was used
on Oconee's Balance of Plant high energy lines. Through telephone
discussions with the cognizant licensee engineer on December 11, 1996.
the inspectors ascertained that a review and evaluation of the original
PPQA, the Oconee Piping Summary (OPS) Manual and the Oconee Flow
Diagrams (OFDs), revealed the following. The only system where A-155KC
70 material was originally specified or installed and could have been
replaced with API-5L, under the OPS Manual and OS-243.00-00-001 in
effect since December 1. 1982, was a section of 30 inch diameter pipe on
the Condensate System. The OPS Manual was subsequently superseded on
May 8, 1984, with OFD series 121A which included material specification
requirements for applicable pipe systems.
Within these areas, the inspectors noted that the error in specifying
API-5L material on large diameter piping was.not identified or corrected
when pipe specifications were updated. This error allowed the material
in question to remain in the pipe specification as an acceptable
replacement material in high energy line applications. This failure to
review material selection for suitability of application on piping
design documents/specifications was identified as Example 3 of Apparent
Violation 50-269,270,287/96-17-01.
During the above mentioned telephone discussion, the licensee's
cognizant engineer indicated that, a review of applicable drawings
disclosed the Condensate System had not been changed or modified since
the original construction where A-155KC-70 was used. A portion of the
"C"
Bleed System with 30 inch diameter piping -was the only other system
where API-5L material could have been used. However, Duke indicated
that this material was acceptable for this application. In conclusion,
the licensee's evaluation and review revealed no instances where API-5L
was misapplied.
ENCLOSURE 2
34
E2.5 Balance of Plant Piping Supports
a. Inspection Scope
The inspectors reviewed engineering involvement in repairs to
balance of plant piping system supports following a water hammer
event on September 24, 1996. which resulted in rupture of the Unit
2 heater drain line and injuries to seven personnel working in the
turbine building.
b. Observations and Findings
Following the September 24, 1996, water hammer event, the licensee
developed a recovery plan to inspect high energy Class G piping
systems to identify deficiencies in the installation of the piping
and pipe supports. The piping systems included the following:
condensate, extraction, main steam, main feedwater, heater drain,
auxiliary steam, and plant heating. These systems were originally
constructed using normal accepted commercial practices but do not
fall under the requirements of 10 CFR 50, Appendix B. The design
parameters for these piping systems were deadweight, thermal, and
internal pressure loads. Seismic loads were not considered in
design of Class G piping per UFSAR Table 3-1.
The inspectors reviewed Oconee procedure titled, "Class G Piping
Support Walkdowns," which was developed to walkdown the high
energy balance of plant piping systems and verify the structural
functionality of each support on the systems. These walkdowns
were not intended to provide as-built verification of existing
support configuration. The procedure provided walkdown
instructions, instructions for examining supports for degraded
conditions, walkdown checklists and summaries, and guidance on
maximum pipe span criteria. The inspectors concluded that the
procedure was adequate to perform the inspections. More than 4000
supports on BOP piping systems were inspected on all three units
utilizing this procedure.
The inspectors reviewed the walkdown packages for the Unit 2
extraction and feedwater systems. There were no isometric piping
drawings available to use for the walkdowns. Instead.licensee
engineers utilized flow diagrams (P&IDs) and plant layout drawings
showing plan and section views of the piping. Review of the
walkdown packages disclosed that pipe support drawings were not
available for approximately one-third of the pipe supports on
these systems. Discussions with licensee engineers disclosed that
the BOP non-safety.related pipe supports were constructed in
accordance with "typical" pipe support drawings. This is a normal
construction practice for these supports. There are no NRC
requirements for the licensee to maintain the pipe support
drawings to demonstrate they comply with Section 121 of B31.1
ENCLOSURE 2
35
regarding design of non-safety related BOP pipe supports.
As a
result of the walkdown inspections, defects were identified by
licensee engineers on several supports. The majority of these.
were minor deficiencies such as bent hanger rods, missing or loose
locknuts, interferences with other structures/components, or
incorrect spring can settings. The pipe support deficiencies were
corrected using maintenance work requests or via minor
modifications.
The original BOP piping design was performed using a computer code
current at the time of the original piping design. A rigorous
stress analysis was performed using a current updated proprietary
program, SUPERPIPE. to qualify the piping and supports on the
heater drain system. As a result of the rigorous analysis,
modifications were implemented for approximately 60 pipe supports.
The modifications involved either removal of some existing
supports, reinforcement of some existing supports. or installation
of new supports. In addition, spring settings were readjusted on
approximately 40 supports. The inspectors reviewed Nuclear
Station Modification (NSM) 22941, Parts AM1 and AS1, which
implemented the support modifications. Since the modification
involved non-safety related piping it was properly designated by
the licensee as non-Q. The inspectors walked down a portion of
the heater drain system and performed a cursory inspection of
eight supports which had been modified under NSM 22941. No
deficiencies were identified with the support modifications.
Since the modifications involved non-safety (non-Q) systems, the
work was not performed under the quality assurance program, and
the modifications were not independently inspected by quality
control personnel. The work was instead inspected by craft
personnel or their supervision. This complies with NRC
requirements.
A rigorous stress analysis was not performed on the piping on the
other six Class G systems listed above. After the walkdowns were
completed a walkdown summary was performed to identify any
potential negative system trends. This was designated as a
flexibility review and was intended to determine if the piping
systems were restrained from thermal expansion at normal operating
temperatures.
c. Conclusions
The licensee's program for followup on the water hammer event
complied with NRC requirements. The licensee was proactive in
following up on the event.
ENCLOSURE 2
~@
36
E2.6 Low Pressure Service Water System Vibration
a. Inspection Scope
The inspectors followed up the licensee's review of flow induced
cavitation in the low pressure service water (LPSW) piping
downstream of the LPI coolers.
b. Observations and Findings
On November 20, 1995, the licensee initiated Problem Investigation
Process (PIP) 0-095-1491 which identified an adverse trend
associated with flow induced cavitation in the LPSW piping
downstream of the LPI coolers. This PIP summarized 12 other PIPs
which had been initiated since 1992 concerning numerous flow
induced problems with the LPSW piping in the proximity of LPSW
flow control valves 251 and 252. Corrective action to address the
adverse trend (PIP 0-095-1491) was to perform vibration testing at
varying flow rates on the LPSW piping downstream of the LPI
coolers. The inspectors reviewed completed test Procedures
TT/1/A/0251/57 and TT/2/A/0251/59, LPSW Vibration Tests, for Units
1 and 2 respectively. The inspectors verified the procedures
contained adequate instructions, precautions, and limitations for
performance of the tests, and that an evaluation was performed in
accordance with 10 CFR 50.59. The results of the testing showed
that peak accelerations (vibrations) occur at system flow rates of
approximately 3000 gallons per minute, which is the design
accident flowrate. The licensee has concluded that the long term
solution to this problem will be replacement of the LPSW 251, 252
flow control valves with new valves of a different design. This
work is scheduled for the next outage on each unit when the new
valves become available.
c. Conclusions
The inspectors concluded that the licensee actions to identify the
adverse trend and implement long term corrective actions to
resolve the problem were appropriate.
E8
Miscellaneous Engineering Issues (92903, 92700)
E8.1 (Closed) Deviation 50-269,270,287/94-19-01: Improper Code Classification
This item addressed a deviation (DEV) from UFSAR requirements which
stated that portions of the Engineered Safeguards. (ES)
System which
could contain recirculated reactor.building sump water following a LOCA
were required to be Class II (Duke Class B).
Portions of the Unit 1 and
3 LPI system piping were classified as Class III (Duke Class C) even
though this piping could contain recirculated reactor building water
ENCLOSURE 2
37
following a LOCA. The licensee's resolution specified in the deviation
response, dated August 25. 1994, was to perform inspections to upgrade
the piping to Class II requirements and perform an Engineering review to
identify other improperly classified piping subject to containing
recirculated reactor building sump water.
The resolution to this issue was documented in PIP 0-94-0678. The
inspectors verified the completion of the corrective actions specified
in the PIP and deviation response. The identified piping was inspected
and upgraded on November 30, 1995. The piping classification review
identified several improperly classified piping runs and resolved these
as documented in the PIP. The 1995 UFSAR update revised the applicable
statement to clarify that the subject piping within containment was not
required to be Class II; however, this piping outside of containment was
required to be Class II. This item is closed.
E8.2 (Closed) Deviation 50-269,270,287/94-19-02: Failure to Meet UFSAR
Requirements Related to System Class Boundary Weld Inspection
This item addressed the UFSAR requirement that piping welds joining two
different piping classes were to be inspected in accordance with the
requirements of the higher classification. Examples were identified in
which welds as piping class breaks were inspected to the requirement of
the lower classification. The licensee's response, dated August 25,
1994, stated that the cause was that UFSAR section 3.2.2.1 was not clear
regarding class break application at piping welds. In particular, the
licensee interpreted that the class break occurred at the valve seat
where a valve was installed at the class break: therefore, there were no
welds joining different piping classes. The response stated that all
examples involved valve welded class breaks. A request for additional
information response dated September 20. 1994, clarified this
classification as applied to one inch piping or less and demonstrated
that adequate weld inspection was specified by the UFSAR. Clarification
of the UFSAR interpretation resolved the deviation.
E8.3 (Closed) Deviation 50-269,270,287/94-24-05: Improper Code Classification
This item addressed an example of improperly classified piping in the
High Pressure Injection system (i.e.. Class II piping classified as
Class III). The concern was the different weld inspection requirements.
The licensee's response to the deviation, dated October 19. 1994, and
December 19, 1994, specified corrective actions to include
reclassification of the subject piping to Class II and a relief request
submittal regarding weld inspection of the installed piping. Request
for Relief No. 95-01 was submitted to the NRC on February 9, 1995, and
accepted by NRC Safety Evaluation Report, dated August 14, 1995.
PIP-094-1685 tracked the revision of the applicable drawings to reflect
the piping class upgrade. Minor modifications OE-8024, 8027, and 8028
revised the drawings and were completed on June 13, 1995.
ENCLOSURE 2
38
E8.4 (Oen) Inspector Followup Item 50-269.270.287/96-13-03: Low Pressure
Service Water Modifications and Testing Issues
This item was opened to track the low pressure service water
modifications which were being implemented to correct several
deficiencies identified during the Service Water Operational Performance
Assessment (SWOPA). The purpose of this inspection was to update the
status of the modifications and review completed work. The scope of the
Oconee Service Water (OSW) Project consists of five major modifications
broken down into 79 Implementation Parts and 6 Minor Modifications. The
major modifications and their parts are listed below.
X2932 - Design and install a new QA-1 seal/cooling water supply
(SSW) to the Condenser Circulating Water (CCW) and Essential
Siphon Vacuum (ESV) pumps and motors from the LPSW system.
52932 Part Al - Install buried headers out to the intake
52932 Part A2 - Install non-buried headers out to the intake
52932 Part A3 - Install headers in Ul and U2 TB
32932 Part A - Install U3 tie ins to the CCW pumps
12932 Part A - Install Ul tie ins to the CCW pumps
22932 Part A - Install U2 tie ins to the CCW pumps
52932 Part B - Remove HPSW tie ins
X3000 -Design and install a new QA-1 ESV system to increase the
reliability and duration of the Emergency Condenser Circulating
Water (ECCW) siphon supply to LPSW.
53000 Part A
Construct a trench across the dike
43000 Part B1
Construction of ESV pad
43000 Part B2 -,Construction of the ESV building
43000 Part B3 - Install ESV building appurtenances
53000 Part C1 - Install cable trench
53000 Part C2 - Install conduit bank and buried piping
53000 Part C3 - Install vacuum pumps and piping
53000 Part C4 - Install vacuum pump power/heat
Trace/instruments
33000 Part C - Tie in to U3 CCW/level switch/ESV pump
controls
13000 Part C - Tie in Ul CCW/Level Switch/ESV pump controls
23000 Part'C
- Tiein to U2 CCW/level switch/ESV pump
controls
33000 Part D - Load removal from 3X51,2,3
13000 Part D - Load removal from 1XSl,2,3
23000'Part D - Load removal from 2 sX1,23
X3001
LPSW system changes to ensue adequate NPSHA
Part A Providing minimum flow protection for the LPSW pumps.
ENCLOSURE 2
39
33001 Part A - Install U3 recirc piping and controls
13001 Part A - Install Ul recirc piping and controls
Part B - Providing an alternate supply to the control room
chillers from the CCW crossover
53001 Part A - Chiller piping
Part C - Providing the capability to isolate the non essential
headers from either Units 1 or 2
33001 Part C - Move control switch for 3LPSW 45 and renumber
to 3LPSW139
13001 Part C - Move control switch for 1LPSW 139
23001 Part C - Provide local flow rate indication
Part D - Removal of LPSW 4 and 5 from ES
33001 Part D - Remove ES from 3LPSW 4 and 5
13001 Part D - Remove ES from 1LPSW 4 and 5
23001 Part D - remove ES from 2LPSW 4 and 5
X3002 - LPSW pump impeller changes
13062 Part A - Changeout 1A LPSW pump impeller
13002 Part B - Changeout 1C LPSW pump impeller
13002 Part C - Changeout 1B LPSW pump impeller
33002 Part A - Changeout 3A LPSW pump impeller
33002 Part B - Changeout 3B LPSW pump impeller
X3003 - Reclassify existing systems and components required to
maintain the ECCW siphon to LPSW to QA-1
Part A - Modify the CCW pump discharge valve controls to prevent
closure following a Loss of Offsite Power (LOOP)
33003 Part A - Upgrade U3 CCW discharge valve controls
13003 Part A - Upgrade Ul CCW discharge valve controls
23003 Part A - Upgrade U2 CCW discharge valve controls
Part B - Reclassify and Upgrade the design of the siphon pressure
boundary
53003 Part B Innage related ECCW reclassification
The inspector reviewed the following documents
Initial Scope Documents for Siphon Seal Water System - Rev 1
ENCLOSURE 2
40
-
Initial Scope Documents for the first siphon pressure boundary
reclassification upgrade - Rev 2
-
Final Scope Document for Buried pipe portion of the siphon seal
water system
-
Final Scope Document for the ESV pad /foundation - Rev 2
-
Final Scope Document for the Intake Pipe Trench - Rev 0
-
Final Scope Document for the ESV System. (buried portions only)
Rev I
-
Final Scope Document for U3 LPSW Pump Minimum Flow Lines - Rev 1
-
Final Scope Document for the removal of the ES signal from valves
3LPSW 4 and 5 - Rev 0
-
Oconee Service Water Project Schedule dated 12-02-96
OSW Project General Project Layout and Modification Parts
Revised 11/18/96
-
OSW Project Team Structure
The inspector attended a project meeting on December 5, 1996, to discuss
the current status and schedule of the OSW project. The schedule was
impacted by the heater piping rupture and is currently delayed pending
the completion of that work. The inspector encouraged the licensee to
develop a new schedule and inform Region II management of their new
completion milestones.
The Unit 3 Modification 33001, installation of the minimum flow
recirculation lines on the LPSW pumps has been completed as well and the
removal of the ES signal from valves 3LPSW 4 and 5. Work is progressing
on the intake dike with an expected completion date of March 31, 1991.
Engineering has completed approximately 30 percent of the work on the
modifications. However, the heater drain piping rupture has stopped all
this work and a new schedule for completion has not been developed as of
the time of this inspection.
This item will remain open pending completion of the modifications and
testing.
ENCLOSURE 2
41
IV.
Plant Support Areas:
R1
Radiological Protection and Chemistry (RP&C) Controls (71750)
R1.1 Tour of Unit 1 and Other Radiologically Protected Areas
a. Inspection Scope (83750)
The inspectors toured work areas to evaluate radiological controls and
conditions of facilities and to evaluate personnel radiation exposure
controls during the ongoing Unit 3 RFO and Units 1 and 2 ongoing
maintenance outages.
b. Observations and Findings
During tours of the facility, the inspectors observed contamination and
radiation surveys being performed and reviewed selected records of
routine and special radiation and contamination surveys performed. Also
during tours of the plant, the inspector independently verified
radiation levels in portions of the Auxiliary Building. The inspectors
reviewed radiological survey maps posted outside rooms/spaces in the
plant used to enhance Radiation Work Permit (RWP) information.
The inspectors reviewed selected routine and special RWPs for adequacy
of the radiation protection requirements based on work scope, location,
and conditions. For the RWPs reviewed, the inspector noted that
appropriate protective clothing, respiratory protection, and dosimetry
were required. During tours of the plant, the inspector observed the
adherence of plant workers to the RWP requirements and discussed the RWP
requirements with selected plant workers and Radiation Protection (RP)
personnel. The licensee had color coded RWPs to enhance the reference of
an RWP for a specific Unit and located the RWPs in areas convenient for
worker review.
The inspectors noted that the licensee's posting and control policies
for radiation areas, high radiation areas, locked high radiation areas,
contamination areas, and radioactive material storage areas were
appropriate. An inventory conducted by the inspectors of the licensee's
key box for controlling keys to locked high radiation areas determined
the keys for those areas were accounted for. At the time of the
inspection, the licensee had appropriately labeled radioactive material
observed consistent with the requirements of 10 CFR 20.1904 and
radiological housekeeping was observed to be adequate. Records reviewed
determined contaminated square footage was averaging approximately 3.0
percent of the total Radiological Controlled Area (RCA) of 126,311
square feet. In 1996, the licensee was averaging approximately 1.5
percent of the total RCA as contaminated during non-outage periods.
Records reviewed also determined the licensee was tracking and trending
personnel contamination events (PCEs) and that approximately 405 PCEs
had occurred in 1996, of which, approximately 94 had occurred during the
ENCLOSURE 2
42
ongoing Unit 3 outage. Although no adverse trends in personnel
contamination controls were noted during the inspection, the inspectors
discussed licensee challenges in minimizing personnel contaminations,
particularly those which may have occurred within the RCA in areas not
posted as contaminated. Records reviewed determined approximately 134
PCEs had occurred in areas not posted as contaminated. The licensee had
initiated some additional contamination controls to address these
challenges, which included: detailed tracking and trending of PCE root
causes, increased RCA boundary surveys, installing small item equipment
monitors at exits to the RCA, increased area mopping of designated
areas, reduced number of egress points from the RCA, and practical
factor training for management personnel who oversee workers exiting the
RCA.
The inspectors reviewed the As Low As Reasonably Achievable (ALARA)
program implementation and results. The inspectors interviewed selected
ALARA staff members and.discussed ALARA planning initiatives for the
work performed during 1995 and 1996. Some of the recent ALARA initiates
discussed included:
Plant shutdown crud burst activities to reduce source term
radioactivity.
A hot spot reduction program primarily accomplished through system
flushes and chemistry boron/lithium controls to reduce corrosion
product transportation.
Source term reduction methods by using increased filtration of the
Reactor Coolant System letdown and replacement of approximately 25
primary valves with stellite free valves.
A modification to normal sump piping to reduce hotspots and
improve sock filter installation which was estimated to save 0.35
Rem per outage.
A ladder installation to improve access to the B1 reactor coolant
pump area to save an estimated 0.4 Rem per outage.
A canal drain line replacement over the emergency sump to save an
estimated 0.5 Rem per outage.
A discussion with licensee representatives and a review of pertinent
records determined the licensee had established an annual site exposure
goal for 1996 of-approximately 339 person-rem. The licensee's 1996
annual site exposure goal was based on operational exposure and one Unit
3 Refueling Outage (RFO). Site exposure accrued in 1996 as of November
18, was approximately 232 person-rem. At the time of the inspection,
the inspectors determined the licensee was continuing to implement
program improvements to .maintain exposures ALARA.
ENCLOSURE 2
43
c. Conclusions
Based on observations during facility tours, procedure reviews,
documentation reviewed, and discussions with licensee personnel, the
inspectors determined the following:
The licensee was conducting surveys, posting areas and labeling
radioactive material as required by procedures.
The licensee's program for RWP implementation adequately addressed
radiological protection concerns and provided for proper control
measures.
Facility radiological conditions and housekeeping were observed to
be adequate. The licensee had initiated additional contamination
control practices to reduce personnel contamination events.
The licensee was continuing to implement program improvements to
maintain exposures ALARA.
R2
Status of Radiation Protection and Control (RP&C) Facilities and
Equipment
R2.1 Process and Effluent Radiation Monitors
a. Inspection Scope (84750)
The inspectors reviewed selected licensee Technical Specifications
(TSs), Duke system procedures, site procedures, and records for required
surveillances on the containment high range radiation area monitors and
portable survey instrumentation to evaluate licensee compliance for
maintaining specific instrumentation as required.
b. Observations and Findings
Selected records reviewed indicated that performance of channel checks,
source checks, channel calibrations, and channel operational tests for
the containment high range radiation monitors were current and that the
containment high range radiation monitors had been calibrated to meet
the frequency specified by licensee TSs 4.0 Table 4.1-1. The inspectors
also observed Licensee TS 4.0 Table 4.1-1 referenced NUREG 0737 II.F.1.3
for the calibration of containment high range radiation monitors 57 and
58. NUREG 0737, Table II.F.1.3 stated containment high range radiation
monitors are to be calibrated in situ and that laboratory calibration is
not acceptable due to the possible differences after in situ
installation. The inspectors determined that the licensee was removing
the detectors from the containment and calibrating the monitors while
the detectors were located in the reactor building penetration room.
The inspectors informed the licensee that this method of calibration did
ENCLOSURE 2
44
not appear to meet the intent of in situ calibration. At the time of
the inspection, the licensee was researching this issue to determine if
existing background information was available to support not calibrating
the monitors in situ. The inspector informed the licensee that until
further information was obtained, this issue would be identified and
tracked as Unresolved Item (URI) 50-259.260,287/96-17-05, In Situ
Calibration of Containment High Range Monitors, pending additional
information from the licensee.
During tours, the inspectors also observed that an adequate number of
portable survey instruments were available for use within the RCA during
the ongoing outages and that the instruments were operable and currently
calibrated in accordance with frequencies specified by licensee
procedures. In addition, the inspectors verified the licensee's whole
body standup and chair counters used for internal monitoring of
radioactivity were currently calibrated.
c. Conclusions
Based on the above reviews, it was concluded that containment high range
radiation monitors and portable survey instruments in use were being
source checked and calibrated on frequencies required by licensee
procedures. However, until further information is obtained, one URI was
identified concerning in situ calibrations on containment high range
radiation monitors pending additional licensee evaluation.
R7
Quality Assurance in Radiation Protection and Chemistry Activities
a. Inspection Scope (83750)
The inspectors reviewed and discussed the licensee's process for
tracking identified radiological issues for the purpose of assessing
followup and corrective actions.
b. Observations and Findings
There had not been any licensee formal audits completed since Audit
SA-96-39(ON)(RA) dated August 27, 1996. which was previously addressed
in NRC Inspection Report 96-16. The licensee's method of tracking
radiological issues was in the PIP program. The inspectors reviewed a
number of PIPs and discussed the significance of several of the PIPs
with the RP PIP coordinator. The inspectors toured a decontamination
facility with a supervisor and discussed supervisory observations and
assessments, and corrective actions. The inspectors determined the
licensee was identifying issues of substance in the area of RP through
the PIP process, supervisory assessments, and QA audits, and was
initiating appropriate corrective action in a timely manner.
ENCLOSURE 2
45
c.
Conclusions
Based on the above reviews, it was concluded that the licensee was
identifying issues of substance for improvement in the RP area and
initiating appropriate corrective action in a timely manner.
V. Management Meetings
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee
management at the conclusion of the inspection on December 31, 1996.
Additional information regarding the two apparent violations was
provided in a phone call with licensee management on January 23, 1997.
The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during
the inspection should be considered proprietary. No proprietary
information was identified.
X3
Management Meeting Summary
Significant Meeting (61701)
On December 12, 1996. the licensee, several Region II inspectors, and
NRR personnel (via telecommunications) conducted a meeting onsite to
discuss the upcoming Emergency Power and Engineered Safeguards
Functional Test. The discussions focused on the unapproved procedure's
purpose, acceptance criteria, and contingencies.
Partial List of Persons Contacted
Licensee
E. Burchfield, Regulatory Compliance Manager
T. Coutu, Operations Support Manager
D. Coyle, Systems Engineering Manager
T. Curtis, Operations Superintendent
J. Davis-, Engineering Manager
W. Foster, Safety Assurance Manager
J. Ham pton, Vice President, Oconee Site
D. Hubbard, Maintenance Superintendent
C. Little, Electrical Systems/Equipment Manager
B. Peele, Station Manager
J. Smith. Regulatory Compliance
NRC
D. LaBarge, Project Manager
ENCLOSURE 2
46
Inspection Procedures Used
IP 71750:
Plant Support Activities
IP 71707:
Plant Operations
IP 61726:
Surveillance Observations
IP 62707:
Maintenance Observations
IP 37550:
Engineering
IP 37551:
Onsite Engineering
IP 61701:
Complex Surveillance
IP 83750:
Occupational Exposure
IP 84750:
Radioactive Waste Treatment, AND Effluent AND Environmental
Monitoring
IP 92700:
Onsite Followup of Written Event Reports
IP 93702:
Prompt Onsite Response to Events
IP 71001:
Licensed Operator Requalification Program Evaluation
IP 92901:
Followup - Operations
IP 62700:
Maintenance Program Implementation
IP 55050:
Nuclear Welding Inspection
IP 92902:
Followup - Maintenance
IP 92903:
Followup - Engineering
IP 40500:
Effectiveness of Controls in Identifying and Resolving Problems
Items Opened, Closed, and Discussed
O
Opened
50-270.287/96-17-06
Failure to Maintain Configuration
Control - Two Examples (Sections 01.2 and
01.3)
50-270,287/96-17-07
Failure to MaintainxAppendix R Valve Leads
(Section 01.4)
50-269.270,287/96-17-05
In Situ Calibration of Containment High
Range Radiation Monitors (Section R2.1)
50-269,270,287/96-17-02
Failure to Perform Evaluations of Out-of
Tolerance M&TE (Section M4.1)
50-270/96-17-08
Failure to Use Procedure Administrative
Hold (Section 07.1)
50-269.270.287/96-17-03
RBCU Operability Concerns Due to Wrong
Type Fuse in Control Circuit (Section
E2.2)
50-269.270.287/96-17-01
Failure To Complete A Written Safety
Evaluation Of Secondary Plant Piping Not
In Accordance With The Piping Code
Referenced In The UFSAR - Three Examples
(Sections M1.5 and E2.4)
ENCLOSURE 2
47
50-269/96-17-09
LPSW Modification did not Meet ASME
Code NDE Requirements (Section M1.8)
50-269,270,287/96-17-04
Engineering Evaluation for the
Replacement of Carbon with Stainless Steel
Piping (Section M1.5)
Discussed
50-269,270,287/96-13-03
IFI
LPSW Modifications and Testing (Section
E8.4)
Closed
50-269.270,287/94-19-01
DEV
Improper Code Classification (Section
E8.1)
50-269,270,287/94-19-02
DEV
Failure to Meet UFSAR Requirements Related
to System Class Boundary Weld Inspection
(Section E8.2)
50-269,270,287/94-24-05
DEV
Improper Code Classification (Section
E8.3)
50-269,-270,287/95-12-01
IFI
Apparent UT Examiner and UT Procedure
Weakness (Section M8.1)
50-287/96-16-06
IFI
ICS Malfunction Training Results (Section
08.2)
List of Acronyms
ACB
Air Circuit Breaker
As Low As Reasonably Achievable
ANSI
American Nuclear Society Institute
American Petroleum Institute
Auxiliary Steam
BWST
Borated Water Storage Tank
CFR
Code of Federal Regulations
Condenser Circulating Water
Core Flood
CR
Control Room
ECCW
Emergency Condenser Circulating Water
Apparent Violation
Emergency Feedwater
EPSL
Emergency Power Switching Logic
End Of Cycle
Electric Power Research Institute
ENCLOSURE 2
48
Engineered Safeguards
ESV
Essential Siphon Vacuum
FDW
FWDS
Field Weld Data Sheets
GL
Generic Letter
gpd
gallons per day
gpm
Gallons Per Minute
HD
Heater Drain
HDP
Heater Drain Pump
High Pressure Injection
High Pressure Service Water
IAE
Instrumentation and Electrical
In Accordance With
Integrated Control System
IFI
Inspector Followup Item
IR
Inspection Report
Inservice Inspection
Large Break LOCA
LER
Licensee Event Report
Loss of Coolant Accident
Low Pressure Injection
Low Pressure Service Water
-MCC
Motor Control Center
Motor Operated Valve
Maintenance Procedure
MS
MSRH
Measuring and Test Equipment
Non-Cited Violation
Net Positive Suction Head
NPSHA
Net Positive Suction Head Absolute
NRC
Nuclear Regulatory Commission
Nuclear Reactor Regulation
NSM
Nuclear Station Modification
NSD
Nuclear System Directive
OE-
Office of Engineering
OEDB
Oconee Engineering Design Basis
OFD
Oconee Flow Diagram
Oconee Nuclear Station
00T
Out-of-Tolerance
Operations
Once Through Steam Generator
OSW
Oconee Service Water
Personnel Contamination Events
PH
Plant Heat
Piping & Instrumentation Drawing
ENCLOSURE 2
I.
49
Problem Investigation Process
Problem Identification Report
PPQA
Power Piping Quality Assurance
PZR
Pressurizer
Pounds Per Square Inch Gauge
Quality Assurance
Quality Control
RBCU
Reactor Building Cooling Unit
Reactor Coolant Pumps
Radiological Controlled Area
RC
Refueling Outage
Radiation Protection
Resistance Temperature Detector
Radiation Work Permit
Scientific Apparatus Manufacturers Association
SDQA
Software and Data Quality Assurance
SSF
Safe Shutdown Facility
SSRH
Second Stage Reheater
SWSOPA
Service Water System Operational Performance Assessment
Turbine Building
TS
Technical Specification
Updated Final Safety Analysis Report
United States American Standard
Unresolved Safety Question
Violation
Validation and Verification
Work Order
Work Request
ENCLOSURE 2