ML15118A318
| ML15118A318 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 10/05/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15118A316 | List: |
| References | |
| 50-269-98-08, 50-269-98-8, 50-270-98-08, 50-270-98-8, 50-287-98-08, 50-287-98-8, NUDOCS 9810290275 | |
| Download: ML15118A318 (61) | |
See also: IR 05000269/1998008
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:
50-269/98-08, 50-270/98-08, 50-287/98-08
Licensee:
Duke Energy Corporation
Facility:
Oconee Nuclear Station, Units 1,
2,. and 3
Location:
7812B Rochester Highway
Seneca, SC 29672
Dates:
July 26 -September 5, 1998
Inspectors:
M. Scott. Senior Resident Inspector
D. Billings, Resident Inspector
E. Christnot, Resident Inspector
S. Freeman, Resident Inspector
K. Kennedy, Senior Resident Inspector. Region IV.
(Section M8.3)
J. Blake, Regional Inspector (Sections M3.1. M8.1.
8.2)
R. Chou, Regional Inspector (Sections E8.6, E8.7)
D. Forbes: Regional Inspector (Sections R1.1, R1.2,
R2.1. and R2.2)
F. Jape, Regional Inspector (Sections 08.2, 08.3.
08.4, 08.5. 08.6. 08.7, and E8.4)
R. Moore, Regional Inspector (Sections E1.1, E1.4.
E2.1. E7.1. E7.2. E8.1, E8.2. E8.3)
B. Schin, Regional Inspector (Sections E1.1; E1.4,
E2.1, E7.1, E7.2, E8.1, E8.2, E8.3)
M. Thomas. Regional Inspector (Sections E1.1. E1.4,
E2.1, E7.1, E7.2. E8.1, E8.2, E8.3)
Approved by:
C. Ogle, Chief, Projects Branch 1
Division of Reactor Projects
Enclosure 2
9810290275 981005
PDR ADOCK 05000269
G
EXECUTIVE SUMMARY
Oconee Nuclear Station, Units 1. 2. and 3
NRC Inspection Report 50-269/98-08.
50-270/98-08, and 50-287/98-08
This integrated inspection included aspects of licensee operations,
maintenance, engineering, and plant support. The report covers a six-week
period of resident inspection, as well as the results of announced inspections
by seven Region based inspectors. [Applicable template codes and the
assessment for items inspected are provided below.]
Operations
The Unit 1 shutdown was performed in a controlled fashion with good
command and control.
(Section 01.3, [1A. 3B - Good])
-The engineering evaluation to support the return to service of the Unit
3 auxiliary fan coolers was adequate (Recovery Plan Item DB8).
(Section
01.4, [4B, 5C - Adequate])
Pre-job briefs to support return to service of the Unit 3 auxiliary fan
coolers were good in that they contained appropriate -detail and stressed
procedure adherence (Recovery Plan Item DB8).
(Section 01.4, [1A,
3B - Good])
The evaluation and followup actions established by the licensee in
response to lack of oil in a reactor building spray pump were adequate.
(Section 01.5, [4B, SB, SC - Adequate])
The compensatory actions established in response to the licensee's
identification of another water hammer scenario identified during a
Generic Letter 96-06 review were adequate (Recovery Plan Item DB8).
(Section 01.5, [4B, SA - Adequate])
The inoperability of both trains of the essential siphon vacuum system
on Unit 2 was due to a procedure weakness that resulted in a
mispositioned valve (Recovery Plan Item DB4).
(Section 01.5,
[2B - Poor])
Once the potential inoperability of the essential siphon vacuum system
was recognized, the licensee took rapid action to return the system to
readiness and made appropriate notifications to the.NRC (Recovery Plan
Item DB4).
(Section 01.5, [5A. SB, SC - Adequate])
During the Unit 1 return to power operations, the licensee adequately
responded to a condensate air ejector radiation monitor alarm. This
showed a marked improvement over a past occurrence, which resulted in a
non-cited violation. (Section 01.6. [1B - Adequate])
The Unit 1 startup from a forced outage was performed effectively. The
operators' responses to annunciators, monitoring of parameters,
supervisor control, the use of procedures, communications, and
2
management oversight were good. (Section 01.6. [1A. 3B - Good])
Poor communications between operations and material condition personnel
resulted in tape remaining on the stem of an operable safety-related low
pressure injection valve for three days. This was considered a weakness
in communications between site organizations. (Section 04.1, [1A. 3A
Poor])
The licensee's activities involving the Technical Specification change
and administrative controls i.n place to require three high pressure
injection pumps to be operable above 350 degrees F were adequate.
(Section 08.1, [4C - Adequate])
The analysis performed to ascertain reactor building sump operability,
causes of discovery, and resolution were timely and complete. (Section
08.2. [5B. SC - Adequate])
The discovery and subsequent corrective actions for a failure to perform
a low pressure injection flow instrument surveillance were timely and
thorough.
(Section 08.3, [5B. 5C - Adequate])
Following the inspection and recognition of the significance of the
failure to install cotter pins on main steam safety valves, the licensee
took prompt and thorough corrective measures. (Section 08.4. [5B, SC
Good])
The recognition and response by the operators to a failure '
of main
feedwater while shutdown, and the resolution were considered timely and
thorough. (Section 08.5. [lA, SA, SC - Good])
The resolution and corrective action in response to an inadequate
procedure for voltage regulator adjustment were timely and thorough.
(Section 08.6, [5B, SC - Adequate])
The licensee's analysis and resolution of the issues related to the May
3, 1997. Unit 3 high pressure injection event were timely and thorough.
(Section 08.7 [5B. SC - Good])
Maintenance
The maintenance activities observed were, in general, completed
thoroughly and professionally. (Section M1.1, [3A, 3B - Adequate])
Due to potential procedural and work control problems. packing practices
on the safety-related station auxiliary service water pump showed a lack
of attention to detail.
This item was left unresolved pending
additional NRC review of pump packing procedures, material controls, and
work control requirements. (Section M1.2, [2B - URI])
The licensee's plans for inservice inspection and steam generator
examinations during the Fall 1998, Unit 3 refueling outage were
comprehensive (Recovery Plan Item SE8).
(Section M3.1, [2B - Good])
3
Engineering
The Oconee Safety-Related Designation Clarification Program was two
years behind its original completion schedule of January, 1997. The
licensee had essentially kept the program on its revised schedule during
the last 11 months of increased oversight, and overall progress on the
program during the last year was adequate (Recovery Plan Item DB3).
(Section E1.1. [4A, 5C. - Adequate])
Some of the level of detail in the partially completed Oconee Safety
Related Designation Clarification Program database of components relied
upon to mitigate accidents was good. in that related indication and
associated components were included (Recovery Plan Item DB3).
(Section
E1.1, [4C - Good])
Some equipment was notably missing from the partially completed Oconee
Safety-Related Designation Clarification Program database, such as
electrical power supplies (Recovery Plan Item DB3).
(Section E1.1, [4C
-
Poor])
The repair practice on the non-safety-related 1B1 reactor coolant pump
lower oil reservoir that had perpetuated a repetitive minor oil leak was
poor. The leak from the reservoir was the reason for the Unit 1
shutdown this period. (Section E1.2, [2A. 3A. 5B - Poor])
Engineering analysis of the current self-disclosing 1B1 reactor coolant
pump reservoir leak was good. (Section E1.2. [4B. 5B - Good])
.Engineering
analysis of the self-disclosing 1A2 reactor coolant pump
seal problem was good. (Section E1.2, [5B - Good])
The use of the problem investigation process to track to closure
corrective actions for NRC open items and commitments involvingthe
emergency power system and the quality of this process were good
(Recovery Plan Item DB7).
(Section E1.3. [5C *- Good])
The use of the failure investigation process reports, at management
direction when necessary, by engineering to address significant issues
involving the emergency power system and the quality of the failure
reports was excellent (Recovery Plan Item DB7).
(Section E1.3, [4B
Excellent])
The onsite engineering group was addressing the NRC open items and
commitments involving the emergency power system in a sound technical
manner, with appropriate resources, using approved methods, and with
management and supervisory oversight (Recovery Plan Item DB7 - Closed).
(Section E1.3, [4B, 5B, SC - Good])
A violation was identified for an inadequate 50.59 safety evaluation,
for a 1996 Final Safety Analysis Report revision, which failed to
identify an unreviewed safety question related to the net positive
suction head for the reactor building spray pumps. (Section E1.4, [4A,
4B - Poor])
4
Although the licensee failed to adequately identify the licensing basis
related to reactor building spray pump net positive suction head
assumptions; they performed .appropriate, timely analysis to assure
operability of the pumps.
(Section E1.4. [5B - Adequate])
Screening of Problem Investigation Process reports was generally good in
that the significance level was appropriately identified. Downgrading
of Problem Investigation Process reports was adequately controlled
(Recovery Plan Item SA2).
(Section E2.1, [5B - Good])
Operability evaluations of Problem Investigation Process report
identified problems were adequate (Recovery Plan Item SA2).
(Section
E2.1. [5B - Adequate])
S*
Problem Investigation Process report cause determinations and assigned
corrective actions were adequate (Recovery Plan Item SA2).
(Section
E2.1, [5B. 5C - Adequate])
The Problem Investigation Process corrective action backlog, as stated
in the Oconee Recovery Plan, provided an inaccurate and unclear
assessment of the overall Problem Investigation Process corrective
action backlog. Specifically, the recovery plan stated that there were
232 open Problem Investigation Process corrective actions greater than
six months old, while other performance indicators showed the actual
number was approximately 660 (which included 428 management exception
items) open Problem Investigation Process corrective actions (Recovery
Plan Item SA1).
(Section E2.1, [5C - Poor])
The Problem Investigation Process quality reviews performed by the
Safety Review Group were effective in identifying areas for improvement
in the Problem Investigation Process (Recovery Plan Item SA2).
(Section
E7.1. [5A.- Good])
The in-plant reviews of the Oconee Recovery Plan were being performed in
accordance with established schedules. However, programs and directives
under which the Independent Nuclear Oversight Team will function were
still in the process of being revised to reflect the Safety Review Group
organization (including the Independent Nuclear Oversight Team roles and
responsibilities) (Recovery Plan Item SA4).
(Section.E7.1, [5A
Adequate])
A non-cited violation of the maintenance rule was identified by the
inspectors for a failure to monitor the performance of manual caustic
injection valves. (Section E8.1. [3A, 2B - Poor])
The licensee promptly responded to the maintenance rule violation,
including cycling the caustic injection valves to assure that they were
capable of fulfilling their intended function and revising a procedure
to include cycling the valves annually. (Section E8.1, [5C - Good])
The inspectors identified a poor design condition for both timely access
to equipment and personnel safety in that operator access to the
5
handwheel of Unit 3 emergency feedwater flow control valve FDW-316
involved walking on a horizontal.pipe about 15 feet above the floor.
This condition had existed for many years without licensee
identification and corrective action (Recovery Plan Item DB9).
(Section
E8.1, [4A, 5A - Poor])
The recent leak sealing in the Unit 3 control room ventilation system
outside the control room was very thorough and professional. This leak
sealing resulted in a substantial improvement in the attainable pressure
in the Unit 3 control room (Recovery Plan Item NRC3).
(Section E8.2.
[4B. SC - Good])
The licensee's procedures, oversight, and performance of a surveillance
test of the Unit 2B penetration room ventilation system air flow, using
a pitot tube, were good (Recovery Plan Item NRC3).
(Section E8.3. [2B,
4B, 5C - Good])
The licensee's review of the history and causal factors associated with
an issue involving fuses in the reactor trip confirm circuit was
thorough and timely. (Section E8.4, [4A, 5B. SC - Good])
- -A non-cited violation was identified for improper design basis.
assumptions regarding the high pressure injection system injection and
crossover valves.
(Section E8.5. [4A - Poor])
The identification, analysis, and resolution of the design basis
concerns related to the failure of Valve 1HP-27 to close were adequate.
(Section E8.5, [5A, 5B. SC - Adequate])
Based on the sample reviewed, the licensee exhibited good progress in
the evaluation and resolution of the outliers for the Seismic
Qualification Utility Group program. Most outliers resolved to date
have been through analyses or documentation review. More complex
outliers remain to be resolved by repairs. modifications, or refined
analyses (Recovery Plan Item DB6 - Closed).
(Section E8.6, [4B, 5B.5C
- Good])
Inspector identified deficiencies found in the seismic mounting of the
nitrogen supply lines for all three units degraded the emergency
feedwater systems and indicated a weakness in maintaining the nitrogen
supply line supports (Recovery Plan Item DB6).
(Section E8.7, [2A,
SA - Poor])
Plant Suport
The licensee was effectively.maintaining controls for radioactive
material storage and radioactive waste processing. Work practices
observed during radioactive waste processing were good. (Section R1.1,
[1C. 3A - Good])
- .
The licensee's water chemistry control program for monitoring primary
and secondary water quality had been effectively implemented in
6
accordance With the Technical Specification requirements and the Station
Chemistry Manual for water chemistry. .The collection of the samples was
performed in accordance with the licensee's chemistry sampling
procedure. (Section R1.2, [1C, 3A - Good])
The inspectors concluded radiation and process effluent and
environmental monitors were .being maintained in an operational condition
to comply with Technical Specification requirements and Updated Final
Safety Analysis Report commitments. (Section R2.1, [2A - Adequate])
The meteorological instrumentation had been adequately maintained and
the meteorological monitoring program had been adequately implemented.
(Section R2.2, [2A, 1C - Adequate])
Report Details
Summary of Plant Status
Unit 1 began the period at 100 percent power. On August 8, 1998, the unit was
shutdown due to reactor coolant pump motor lube oil and pump seal problems.
On August 27, 1998, the unit was returned to and ended the period at 100
percent power.
Unit 2 began and ended the period at 100 percent power.
Unit 3 began the period at 100 percent power. On August 25, 1998, the unit
began an end-of-cycle power reduction and ended the period at 91 percent
power.
I. Operations
01
Conduct of Operations
01.1 General Comments (71707)
Using Inspection .Procedure (IP)
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 Operations Clearances (71707)
The inspectors reviewed the following clearances during the inspection
period:
98-2910
1MS-87 Air Actuator Preventive Maintenance
98-2816
Perform MPM Test of 1MS-84
The inspectors observed that the clearances were properly prepared and
authorized and that the tagged components were in the required positions
with the appropriate tags in place.
01.3 Unit 1 Reactor Coolant Pump (RCP) Problems and Forced Shutdown
a. Inspection Scope (71707,93702)
On August 8. 1998. Unit 1 was shutdown (SD) due to several RCP problems.
The inspectors observed pump operations, plant conditions, operator.
actions, and observed management interactions during the shutdown.
b. Observations and Findings
On August 7. 1998, at 5:00 a.m., Unit 1 received a RCP 1A2 Seal Outlet
Flow Hi/Low alarm due to number 2 shaft seal leakage above 4.0 gallons
per minut'e (gpm). In accordance with licensee procedures, if leakage
exceeded 4.5 gpm, the unit would require SD due to the inability of the
standby shutdown facility (SSF) to provide adequate emergency seal flow.
The licensee appropriately established an administrative limit on the
pump shaft seal leakage to ensure that this value would not be exceeded
and made plans for an outage on August 14. 1998.
On August 8, 1998, at 3:50 a.m., Unit 1 received a RCP Motor iB1 Oil Pot
Low Level alarm. Operators verified the leakage and noted that RCP 1BI
lower motor bearing reservoir level had dropped about 0.4 inches over a
short period. The operators also observed increasing bearing
temperatures. The oil loss had begun on August 3. 1998. but the leakage
rate had not increased until August 8. 1998, (total drop of 0.8 inches).
These oil levels are not normally trended.
At 4:30 a.m., operations began a controlled plant power reduction. At
approximately 69 percent power, the 181 pump was SD. After consultation
with management, power was further reduced to take the plant off line.
The inspectors observed the shutdown.
c. Conclusions
The SD was performed in a controlled fashion with good command and
control of the plant.
01.4 Return to Service of the Unit 3 Auxiliary Fan Coolers (AFC)
a. Inspection Scope (71707)
The inspectors followed the return to service of the Unit 3 AFCs
following engineering evaluation to resolve Generic Letter (GL) 96-06
water hammer concerns.
b. Observations and Findings
The removal of the Unit 3 AFCs was originally discussed in Inspection
Report (IR)
50-267.270.287/96-20 and Licensee Event Report (LER) 50
269/97-02. Prior to the return-to-service, the inspectors reviewed the
engineering evaluations and 10 CFR 50.59 review. The inspectors noted
that the engineering evaluations were thorough and complete.
Utilizing OP/3/A/1104/10. Revision 58. Enclosure 3.23. Filling Reactor
Building Auxiliary Fan Coolers, the licensee satisfactorily returned the
Unit 3 AFCs to service. This return to service was based on the
licensee's satisfactory completion of an evaluation which demonstrated
that despite the existence of potential water hammer concerns, the Unit
3 low pressure service water (LPSW) system would perform its safety.
function during normal and accident conditions.
3
The inspectors were present for the pre-job briefs and observed low
pressure service water (LPSW)
and reactor building (RB)
responses to the
flow changes. The pre-job briefs contained appropriate detail and
stressed proper procedure implementation. The procedure was carried out
as written and plant response was appropriate. The return-to-service
did not perturb LPSW flow to the reactor building cooling units (RBCUs).
but did reduce RB temperatures significantly. The licensee
appropriately verified, through inspection and normal sump changes, that
the AFCs did not leak.
The licensee indicated that the remaining units'.AFCs will be returned
to service as the supporting analysis is completed on each unit.
Additional NRC review of this issue will occur during the review of LER
50-269/97-02.
c. Conclusions
The engineering evaluation to support the return to service of the Unit
3 auxiliary fan coolers was adequate.
Pre-job briefs to support return
to service of the Unit 3 auxiliary fan coolers were good in that they'
contained appropriate detail and stressed procedure adherence.
01.5 Licensee 10 CFR 50.72 Notifications
a. Inspection Scope (92712, 71707)
The inspectors reviewed the following licensee notifications to the NRC:
On June 30, 1998. the licensee completed a notification for both
trains of the reactor building spray (RBS) system being out-of
service. On July 30. 1998, following completion of an engineering
evaluation, the licensee retracted the notification.
On August 13, 1998, a notification was made for a potential GL 96
06 scenario involving a water hammer in the LPSW pipe within
containment.
On August 31, 1998, the licensee completed a notification for both
trains of the essential siphon vacuum (ESV) system being out of
service.
The inspectors reviewed the notification issues and the corrective
actions taken.
b. Observations and Findings
The inspectors made the following observations:
On July 30, 1998, following completion of an engineering
evaluation, the licensee retracted the June 30, 1998, notification
- regarding a low oil reservoir level on the 1A RBS pump. The
licensee's evaluation determined that the oil remaining in the
4
pump was sufficient to lubricate its bearings. Engineering also
determined that the leak mechanism was self-limiting and therefore
could not cause the pump to.be inoperable. Based on their review
of the evaluation and discussion with the licensee, the inspectors
agree with this assessment. Duke also no longer plans to submit
an LER on this event. This issue was initially addressed in IR
50-269.270.287/98-07.
On January 24, 1997. Oconee Nuclear Station completed a GL 96-06
notification to report .that analysis performed pursuant to GL 96
06 had predicted water hammer in portions of the LPSW piping.
LER 50-269/97-02, Revision 1. submitted July 31, 1997, addressed
that analysis, and the corrective actions. On August 13. 1998,
the licensee identified another scenario that was predicted to
result in severe water hammers in the LPSW piping inside
containment. This scenario involves having LPSW isolated or
reduced below 420 gpm, when a loss of coolant accident (LOCA) or
main steam line break occurs. The analysis indicates that a water
hammer may occur that could breach the piping. All RBCUs
currently are in service with greater than 420 gpm flow. An
administrative limit of 550 gallons per minute (gpm) has been set
to ensure containment integrity is maintained.- Historically, the
RBCU outlet valves have been tested on a quarterly basis which
does decrease flow to less than 420 gpm during the test. The
licensee indicate that this will be addressed in a supplement to
LER 50-269/97-02. The inspectors verified that all nine RBCUs had
flow greater than 420 gpm and that the operators were aware of the
new minimum flow criteria (operator guidance had been issued).
On August 28, 1998, ESV train 2A was removed from service for
testing by procedure PT/2/A/0261/010. Revision 010. A 72-hour TS
3.19 LCO was entered for ESV 2A train. Testing was completed, the
ESV 2A train was placed back in service, and the LCO was exited on
August 28. 1998. On August 31, 1998, ESV 2B train was removed
from service .for testing and TS 3.19 was entered. During the
conduct of testing on the Train B equipmeht, test personnel
realized that the procedure for the Train B testing did not re
open the suction block valve for the Train B equipment. Licensee
personnel then determined that the ESV 2A suction block valve was
still closed from the previous testing. As a result of this
procedure error, ESV 2A train was inoperable while the ESV 2B
train was also inoperable for testing. This placed Unit 2 in a TS
3.0, a 12-hour LCO for having both trains of ESV inoperable. It
appears that both trains were inoperable for approximately 3
hours, from 11:00 a.m to 2:00 p.m. Following the discovery of the
mispositioned valve, the licensee reopened the ESV 2A suction
block valve, completed a procedure change to the ESV test
procedure to open the ESV 2B suction block valve prior to exiting
the LCO, initiated PIP 2-098-4153. and initiated a 10 CFR 50.72
notification to the NRC. The inspectors verified that the valves
were returned to their correct position and that the procedure had
0II
5
been corrected. This event will be followed by the NRC through
LER 50-270/98-06.
c. Conclusions
The evaluation and followup actions established by the licensee in
response to lack of oil in a reactor building spray pump were adequate.
The compensatory actions established in response to the licensee's
identification of another water hammer scenario identified during a GL
96-06 review were adequate.
The inoperability of both trains of the essential siphon vacuum system
on Unit 2 was due to a procedure weakness which resulted in a
mispositioned valve. Once the potential inoperability of the essential
siphon vacuum system was recognized, the licensee took rapid action to
return the system to.readiness and made appropriate notification to the
NRC.
01.6 Unit 1 Startup Observations
a. Inspection Scope (71707)
Unit 1 was started on August 27. 1998, after a forced outage due to RCP
problems. The inspectors observed the startup.
b. Observations and Findings
During the return to power. the condensate air ejector radiation
monitor, RIA-40. alarmed. This was an expected occurrence due to
chemistry changes which occurred in the secondary system. The
operators, health physics personnel, and chemist took appropriate action
to understand the alarm and followup through successive shifts. This
was marked improvement in RIA-40 interface performance as compared to
that indicated i.n Inspection Report 50-269,270.287/97-18, Section 01.3,
where the licensee's procedure problems were identified during a steam
generator tube leak event. The current alarm had no significance but
was important in that the licensee showed increased understanding in
this area.
.During the return to power operations, the inspectors observed the
.operators' responses to annunciators, monitoring of parameters,
sup ervisor control, communications..the use of procedures, and
management oversight. Access to the control room was restricted to
necessary personnel only. Shift turnovers were well planned and
controlled.
c. Conclusions
During the Unit 1 return to power operations, the licensee adequately
responded to a condensate air ejector radiation monitor.alarm. This
showed a marked improvement over a past occurrence which resulted in a
6
non-cited violation (NCV).
The Unit 1 startup from a forced outage was performed effectively. The
operators' responses to annunciators, monitoring of parameters,
supervisor control; communications, the use of procedures, and
management oversight were good.
02
Operational Status of Facilities and Equipment
02.1 Engineered Safety Feature (ESF) System Walkdowns (71707)
The inspectors used IP 71707 to walkdown accessible portions of the
following ESF systems:
Si.phon Seal Water (Unit 2)
Essential Siphon Vacuum (Unit 2)
Emergency Feedwater (Unit 3)
Equipment operability, material condition, and housekeeping were
acceptable in all cases. Several minor discrepancies were brought to
the licensee's attention and were corrected.
.
02.2 Containment Isolation Lineup (71707)
The inspectors reviewed the following portions of the containment
isolation lineup during the inspection period:
Unit 3 South Low Pressure Injection (LPI) Room
The inspectors observed that the lineup was in accordance with plant
operating procedures and the Updated Final Safety Analysis Report
(UFSAR).
04
Operator Knowledge and Performance
04.1 Tape Found on Stem of Valve 3LP-22
a. Inspection Scooe (71707)
On September 2. 1998. during routine tours of the Unit 3 auxiliary
building, the inspectors found masking tape on the stem and parts of the
motor operator for borated water storage tank (BWST) suction valve 3LP
22. The inspectors questioned the operability of the LPI system and
discussed the issue with the appropriate operations, maintenance, and
management personnel.
b. Observations and Findings
The inspectors determined that valve 3LP-22. which is in the line from
the BWST to the 3B LPI pump, was to be painted as part of the material
condition upgrade for all units. Material condition upgrade personnel
7
had placed the tape in preparation for painting the motor operator but
were moved to other work before actually completing the painting.
The
use of this tape was not evaluated as part of the valve configuration
nor did the painters specifically notify operations of this taping.
The
tape had been on the valve for three days before discovery by the
inspectors.
The licensee stated that the work order controlling the painting had
been signed by operations giving permission for the work to begin.
However, shift operations personnel in Unit 3 were not aware of the work
on 3LP-22 and the potential to affect its operability. Additionally,
while the valve was located in a relatively open area with moderate
traffic, no one reported the tape.
The licensee immediately removed the tape and initiated PIP 3-098-4178.
Material condition upgrade personnel were instructed to discuss their
work with operations on a daily basis. Prior to this they would only
update operations on work status weekly. Operations management also
issued a memo to shift personnel reminding them-of the importance of
moni'toring the plant. The licensee's review of past operability on
valve 3LP-22 indicated that there was enough thrust margin available for
the valveto open or close with tape on the stem. The inspectors agreed
with this analysis.
c. Conclusions
'Poor communications between operations and material condition personnel
resulted in tape remaining on the stem of an operable safety-related low
pressure injection valve for three days. This was considered a weakness
in communications between site organizations.
08
Miscellaneous Operations Issues (92901.92700)
08.1 (Closed) Inspector Followup Item (IFI) 50-269.270.287/95-03-01:
Clarification of TS 3.3.1
(Closed) LER 50-269/90-15: Unit Operation In an Unanalyzed Condition
Due to Design Deficiency, Design Oversight
This issue was originally described in IR 50-269,270.287/90-30.
3.3.1 requires only two HPI pumps to be operable below 60 percent power
and three HPI pumps to be operable above 60 percent power. The licensee
identified that under some accident scenarios below 60 percent power
with a single failure, there could be insufficient flow with only two
HPI pumps. The licensee reported this condition in LER 50-269/90-15 and
established administrative controls to require three HPI pumps to be
operable above 350 degrees F. This was left as Unresolved Item (URI)
50-269,270,287/90-30-01, Clarification of TS 3.3.1 pending completion of
a TS change to revise TS 3.3.1 to clarify HPI system operability
requirements.
8
In IR 50-269,270,287/90-34-, the URI was dispositioned as a NCV with the
URI remaining open. In IR 50-269,270.287/95-03. since the enforcement
had occurred previously, the.URI was closed and.IFI 50-269,270.287/95
03-01 was opened. A TS submittal containing the administrative details
was transmitted to NRC on March 31, 1997. Due to events involving the
failure of the HPI pumps in April of 1997. the licensee committed to
complete a reliability study for the HPI system. This study was to be
completed by December 31. 1997. The NRC has requested additiQnal
information from the licensee and these efforts are being tracked
through Technical Assignment Control (TAC) numbers: M98296, M98297. and
M98298. The inspectors reviewed the documentation cited above and
discussed the issue with NRC management.
Based on the licensee's submittal of the TS change, the tracking and.
review of the submittal by NRR. and the administrative controls in place
to require three HPI pumps to be operable above 350 degrees F. this IFI
and associated LER are closed.
The licensee's activities involving the TS change and.administrative
controls in place to require three HPI pumps to be operable above 350
degrees Fahrenheit (F)
were considered adequate.
08.2 (Closed) Violation (VIO) 50-269,270,287/97-05-02:Failure to Maintain
Configuration Control
The bolts for the RB emergency sump covers, for all three units were
found missing. The licensee's root cause analysis, discussed in PIP 0
097-0146, determined the cause to be a lack of guidance regarding the
bolts in the maintenance procedure. Also, it was determined that a lack
of all bolts did not make the screen inoperable.. Maintenance procedure.
MP10A/1800/105, Revision 08. Reactor Building Emergency Sump LPI Suction
Line Flange - Installation, Removal., and Screen Inspection, was
clarified. The procedure was changed to require at least 4 bolts to be
installed and tightened in a diagonal pattern. The analysis performed
to. ascertain operability, causes of discovery and resolution were timely
and complete.
The corrective actions presented in the licensee's response, dated
August 18. 1997, were verified by the inspectors. This violation is
closed.
08.3 (Closed) VIO 50-269,287/97-15-01: Failure to Complete Required TS
Surveillance on LPI Flow Instruments
(Closed) LER 269/97-09-00: LPI Flow Instrument TS Surveillance Interval
Exceeded Due to Deficient Work Practices
On October 10, 1997. the licensee discovered that the last time the LPI
flow instrument surveillance, required by TS Table 4.1-1 was performed,
the flow transmitters were omitted from the surveillance. The
surveillance was immediately performed which restored operability and
met the TS. The licensee issued LER 269/97-09-00 on November 11. 1997,
9
and the NRC issued VIO 50-269.287/97-15-01. on December 15. 1997.
The corrective actions presented in the licensee's response to the
violation, dated January 15. 1998, and the action described in the LER
were reviewed and verified by the inspectors. The corrective actions
included a review of 615 previously completed work orders to determine
if this type of error has been made in the past. No similar errors were
detected. The licensee also clarified the wording within the model work
order used to schedule and complete these TS required calibrations. The
discovery and subsequent corrective actions for a failure to perform a
LPI flow instrument surveillance were timely and thorough. This
violation and LER are closed.
08.4 (Closed) VIO EA 96-478-01014: Failure to Properly Install Main Steam
Safety Valve (MSSV) Spindle Nut Cotter Pins
In response to an event at another nuclear power station, the licensee
conducted an inspection of the MSSVs on all three units. Results of
these inspections were reported in NRC IR 50-269.270.287/96-16. and in
LER 50-270/96-05-01. Potential Uncontrolled Release via Main Steam
Relief Valves Due to Inadequate Work Practices.
The corrective actions presented in the licensee's response, dated
January 23. 1997. and in the LER were.verified as completed. PIP 0-096
1599 was prepared to document the inspection results and PIP 0-096-2031
was written to perform root causes of the incorrectly installed cotter
pins.
After the cotter pins were correctly installed on the MSSVs, a
modification was made to remove the fork levers, spindle nuts, and
cotter pins on all relief valves. This modification was expanded to
include the primary relief valves on the pressurizer.
The modification eliminates the possibility of a relief valve failing to
reset due to. an improperly installed cotter pin. The modification was
completed on the MSSVs for all three units and has been completed on the
Unit 1 and 2 pressurizers, and the spare pressurizer relief valves. The
work is scheduled to be completed during the next outage on Unit 3.
Following the recognition of the significance of the problem, the
licensee took prompt and thorough corrective measures.
Violation EA 96-478-01014 is closed.
08.5 (Closed) LER 50-269/97-08-00: Manual Reactor Trip Due to Equipment
Failure While Shutdown
This LER describes an event whereby the operators manually tripped the
reactor protective system while the unit was at hot shutdown and sub
critical. The manual trip was required by procedure upon failure of
main feedwater.
10
The plant systems and operators responded as expected. PIP 1-097-202
was issued on July 7. 1997, to investigate and correct the failure. The
root cause was determined to be a failure of a circuit board in the main
feedwater pump turbine control system. The recognition and response by
the operators to a failure of main feedwater while shutdown, were
considered timely and thorough. This LER is closed.
08.6 (Closed) LER 50-270/97-02-00: Grid Disturbance Results in Reactor Trip
Due to Manufacturing Deficiency
On July 6, 1997, Oconee Unit 2 was operating at 100 percent power when a
system grid disturbance initiated a generator protective relay actuation
that resulted in all four reactor coolant pump monitor channels of the
reactor protective system tripping. The .operators placed the unit in
stable, hot shutdown condition. The grid disturbance was created by a
switching problem at Jocassee Hydro Station. The voltage regulator on
Unit 2 did not respond an expected. The root causes of this event were
determined to be a manufacturing deficiency and inadequate installation
instructions. Corrective action included calibration of the voltage
regulator. The resolution and corrective action in response to an
inadequate procedure for voltage regulator adjustment were timely and
thorough. Given that the voltage regulator is not subject to Appendix
B, this will not be subject to enforcement action. This LER is closed.
08.7 (Closed) VIO EA 97-298-04014: Failure to Follow Operations Procedures
Relating to Low Temperature Overpressure Protection Requirements
(Closed) VIO EA 97-298-03014: Failure to Follow Operations Procedure
During the Unit 3 Cooldown on May 3, 1997
(Closed) VIO EA 97-298-05014: Failure to Follow Maintenance Procedures
for the Installation of Tubing
(Closed) LER 50-287/97-03-00: High Pressure Injection System Inoperable
Due to Design Deficiency and Improper Work .Practices
The licensee's corrective actions for these violations were described in
a letter dated September 25, 1997. The licensee's investigation and
initial corrective actions were previously verified to have been
satisfactorily performed during an inspection documented in IR 50
269,270,287/97-08. The LER also described the event and provided
corrective actions. During this inspection, the inspectors verified
that the corrective actions for the violations listed above and the LER
had been completed. The licensee's analysis and resolution of the
issues related to the HPI event were timely and thorough. The
violations and the LER are closed.
11
II.
Maintenance
M1
Conduct of Maintenance
M1.1 General Comments
a. Inspection Scope (62707,61726)
The inspectors observed all or portions of the following maintenance
activities:
Replace AT-7 Signal Isolator for 2NI-1
IP/O/A/0301/3A-1 NI-1 Neutron Flux Instrument Calibration
(Unit 2). Revision 21
IP/O/A/0301/3S-1 Source Range and Intermediate Range Channel Test
(Unit 2). Revision 26
TT/1/A/0110/019
Penetration Room Ventilation System 1A Pitot
Tube Flow Test. Revision 0
OP/1/A/1104/019
Reactor Building Spray System, Enclosure 3.2,
Removing Reactor Building Spray From ES Standby
Mode, Revision 4
OP/1/A/1104/004
LPI System. Enclosure 3.1. RCS Cooldown Using
LPI High Pressure Mode, Revision 80
OP/0A/1106/019
Keowee Hydro Operation From Oconee. Revision 43,
Enclosure 3.1, Automatic Startup, Enclosure 3.4
Shutdown
PT/0/A/0620/009
Keowee Hydro Operation, Revision 16
IP/0/A/0250/001C Low Pressure Service Water to RCP Motor Coolers
Low Pressure Injection Decay Heat Coolers and RB
Component Coolers. Revision 7
IP/0/A/0100/001
Controlling Procedure for Electrical and I&C
Troubleshooting and Corrective Maintenance,
Revision 14
PT/2/A/0261/010
Essential Siphon Vacuum System Test, Revision
001
PT/0/A/0251/010
Auxiliary Service Water Pump Test, Revision 42
OP/3/A/1104/10
Filling Reactor Building Auxiliary Fan Coolers,
Revision 58, Enclosure 3.23
12
PT/3/A/0152/013
Low Pressure Service Water Valve Stroke Test
Revision 5
IP/0/A/0310/07C
Engineering Safeguards System Logic Test
Channel 5 (3LPSW-565), Revision 27
PT1&2/A/0110/015 Control Room Pressurization Test, Revision 11
Check Control Rod Drive Power Supply
IP/0A/0310/08C
Engineering Safeguards System Logic Test
Channel 6 (3LPSW-565), Revision 24
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 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 whenever required by procedure.
When applicable, appropriate radiation control measures were in place.
c. Conclusion
The inspectors concluded that, in general, the maintenance activities
listed above were completed thoroughly and professionally.
M1.2 Station Auxiliary Service Water (ASW) Pump Impeller Replacement
a. Inspection Scope (62707)
On September 3, 1998. the inspectors observed portions of the impeller
replacement and subsequent testing of the station ASW Pump.
b. Observations and Findings
In June 1998. the inspectors observed, after previous maintenance, that
the packing follower nuts on the station ASW pump were not fully
engaged. In response to inspectors questions regarding this thread
engagement, the licensee decided to replace the packing follower nuts as
part of the work order for changing the impeller. This decision was
made after the work order had been issued and the work order was not
revised to include the increased scope of work. The licensee's
mechanics indicated that they believed the instruction being used
contained sufficient direction.
On September 3, 1998, before the post-maintenance test was performed,
the inspectors observed that the packing follower was slightly cocked,
the packing follower nuts did not fully span the retaining holes in the
follower, and the studs appeared to have been backed out in order to
give the proper thread engagement on the nuts. Following questions by
13
the inspectors and observed leaks during the post-maintenance test, the
licensee decided the packing follower was not completely in the stuffing
box. They stopped the pump, removed one ring of packing, installed the
packing follower farther into the stuffing box, and added washers
underneath the packing follower nuts. They then tested the pump again
and its performance was acceptable.
Removing one ring of packing resulted in the studs being fully engaged.
The licensee later explained that the packing follower was initially
installed in the stuffing box without cocking but the follower nuts only
finger tight. They stated that, due to past problems with packing
break-in, they intended to make packing adjustments during testing. The
licensee acknowledged that the packing follower was cocked but that it
was most likely caused by static pressure against the packing when the
pump was filled for testing.
The impeller and follower nuts were replaced using procedure
MP/0/A/1300/011. Pump - Ingersoll-Rand - Auxiliary Service Water
Rotating Assembly - Removal, Repair And Replacement, Revision 14. The
inspectors reviewed this procedure and found it contained one step to
install packing, packing follower, and follower nuts. The procedure
contained no guidance about packing follower alignment, the type of nuts
and washers to use, or about thread engagement. Procedure
MP/0/A/1300/010 Pump - Packing and Adjusting Packing, Revision 14.
contained some of this guidance but only as a note dealing with how the
packing should look when finished. The inspectors reviewed the pump
vendor manual and found that it also did not contain any guidance about
packing follower alignment, the type of nuts to be used. or the need for
washers. It also did not contain any instructions on the installation
of the follower studs. The licensee stated that the missing guidance
did not affect the operability of the pump and addressed the type of
material for the follower nuts and washers in PIP 0-098-4212.
Pending NRC review of the adequacy of procedures used on the station ASW
pump, the material controls for parts used on the pump, and the work
control'requirements for the change in job scope. this item will remain
unresolved. This will tracked as URI 50-269.270.287/98-08-01:
Configuration Control of the Station ASW Pump.
c. Conclusions
Due to potential procedural and work control problems, packing practices
on the safety-related station auxiliary service water pump showed a lack
of attention to detail. This .item was left unresolved pending
additional NRC review of pump packing procedures, material controls, and
work control requirements.
14
M3
Maintenance Procedures and Documentation
M3.1 Inservice Inspection (ISI) and Steam Generator Program Review (Unit 3)
a. Inspection Scope (73753)
The inspectors reviewed the licensee's program and plans for ISI and
steam generator inspections during the Fall 1998. Unit 3 refueling
outage.
b. Observations and Findings
The Fall 1998 refueling outage will be the end of fuel cycle number 17
(EOC17) for Unit 3. In the ISI schedule, this will be the first outage
in the second 40-month period of the third 10-year inspection interval.
The ISI American Society of Mechanical Engineers (ASME) Code of record
for the second interval is ASME Section XI, 1989 Edition with No
Addenda.
The inspectors reviewed the ISI program, including the incorporation of
relief requests and ASME Code Cases that had been approved by the NRC.
The inspectors found that the inspection plans for the Unit 3 EOC17
outage appeared to be complete.
The inspectors also examined the nozzle mock-up used to qualify
procedures and personnel for the ultrasonic examination (UT) of the HPI
nozzle inner radius area. The mockup was a full-scale representation of
the actual in-plant installation, with an inside-surface defect in the
nozzle inner radius. The inspectors agreed that the use of the mock-up
would provide meaningful training for UT examiners.
The inspectors reviewed the estimated work scope.for steam generator
inspections planned for the Unit 3 EOC17. The planned examinations
appeared. to be comprehensive, examining all of the critical locations of
the Once Through Steam Generators (OTSGs).
c. Conclusions
The licensee's plans for inservice inspection and steam generator
examinations during the Fall 1998, Unit 3 refueling outage were
comprehensive.
M8
Miscellaneous Maintenance Issues (92902.92700)
M8.1 (Closed) LER 50-269/97-11-00: Steam Generator Leak Results in TS Unit
Shutdown Due to Inadequate Process Control
The subject of this LER was discussed in Section M1.4 of IR
50-269,270.287/97-18. The completion of the licensee's root cause
investigation and issuance of the LER did not provide additi.onal
information over what was discussed earlier. This LERis closed.
.15
M8.2 (Closed) LER 50-270/98-01-00:
Operation With Steam Generator Tube
Indications In Excess of Limits Due to Manufacturing Error
The subject of this LER was discussed in Section M1.3 of IR
50-269,270,287/98-05. The completion of the licensee's root cause
investigation and issuance of the LER did not provide additional
information over what was discussed earlier. This LER is closed.
M8.3 (Closed) LER 50-287/97-02-00: Reactor Building Cooling Units Technically
(Closed) LER 50-287/97-02-01: Reactor Building Cooling Units Technically
Inoperable Due to a Manufacturing Deficiency
This event was discussed in IRs 50-269.270,287/97-02 and 50-269,270.
287/97-12. No new issues were revealed by the LER. This LER is closed.
III. Engineering
El
Conduct of Engineering
E1.1 Oconee Safety-Related Designation Clarification (OSRDC) Program
a. Inspection Scope (37550,40500)
The inspectors reviewed the licensee's OSRDC program and compared the
current status with the program schedule and content commitments that
had been described to the NRC in meetings and letters.
b. Observations and Findings
The licensee had described the schedule and content for the OSRDC
program to the NRC in meetings on February 6 and May 1. 1995; in a
letter dated April 12, 1995, titled "Oconee QA-1 Licensing Basis and
Generic Letter 83-28, Section 2.2.1, Subpart 1 Supplemental Response;"
and during bimonthly meetings on the Oconee Recovery Plan in 1997 and.
1998.
The OSRDC program schedule, as described in the meeting of May 1, 1995,
included completion by January 1997. However, the OSRDC program had not
been completed in 1997 and it was then included in the Oconee Recovery
Plan. The September 15, 1997, Oconee Recovery Plan schedule for OSRDC
program completion was November 1. 1998. The most recent (June 30,
1998) Oconee Recovery Plan schedule for OSRDC program completion was
January 1999.
The inspectors verified the licensee was currently on track for OSRDC
program completion by January 1999. The licensee had 12 engineers
working on the program (one onsite and 11 in Charlotte) and expressed a
determination to meet the January 1999 completion schedule. In
comparison, the licensee had about four engineers working on the OSRDC
program during 1995-1997. Also, higher priority programs and projects
16
had impacted the OSRDC program schedule during that time. During 1995
1997, the 20-month OSRDC program had fallen over 22 months behind its
original schedule. The inspectors concluded that, during 1995-1997, the
licensee had been ineffective in keeping the OSRDC program on schedule.
However, during the increased oversight in 1997-1998, the licensee had
essentially kept the OSRDC program on its revised schedule.
As described in the May 1, 1995, meeting summary, the OSRDC program was
designed to provide additional maintenance and testing to non-safety
equipment that was relied upon to mitigate design basis accidents. At
Oconee, quality assurance requirements for systems, structures, and
components (SSCs) have been addressed separately from design
requirements. The terms safety-related and quality assurance (QA)
category QA-1 were used interchangeably. QA-1 SSCs, as listed in UFSAR
Chapter 3.3.1, must-meet 10 CFR 50, Appendix B, quality assurance
requirements. The OSRDC program included identifying all SSCs relied
upon to mitigate approximately 25 design basis accidents and determining
which of those SSCs were not already designated as QA-1.
Those non-QA-1
SSCs that did not operate during normal plant operation in the same mode
that they would .function during an accident would be designated as QA-5.
QA-5 SSCs would then be given maintenance and testing of similar quality
as that given to QA-1 SSCs.
The inspectors verified that the licensee had completed the listing of
SSCs relied upon for almost all of the design basis accidents, and had
not yet determined which of those SSCs were not designated as QA-1. The
information was assembled in a computerized database with 11 columns
including:
Event, Component Identification, Drawing. Operation
(required action). Actuation Method, Notes (further describing the
required action). System Function, Related Indication, and Associated
Components. The database was capable of sorting and printing the
information in various ways. The inspectors noted that some of the
level of detail in the data was good in that-related indication and
associated components were included. However, some equipment was
notably missing such as electrical power supplies (e.g.. breakers and
relays).
Licensee engineers stated that they planned to add electrical
components to the database.
c. Conclusions
The inspectors concluded that, while the OSRDC program was two years
behind its original completion schedule of January 1997, the licensee
had essentially kept the OSRDC program on its revised schedule during
the last 11 months. Some of the level of detail in the partially
completed database of components relied upon to mitigate accidents was
good, in that related indication and associated components were
included, and some equipment was notably missing such as electrical.
power supplies. Overall progress on the OSRDC program during the last
year was adequate.
0II
17
E1.2 Unit 1 RCP Problem Resolution
a. Inspection Scope (37551)
During the period, Unit 1 developed problems with two of the RCPs which
culminated in a Unit 1 shutdown on August 8. 1998. The inspectors
followed the engineering evaluation, resolution of these problems, and
independently inspected the other RCPs.
b. Observations and Findings
IBI RCP
PIP 1-98-3836 indicated that the 1B1 RCP had an oil leak (8
drops/minute) at a slight (1/32 inch height) mis-alignment of its two
piece cover on the lower motor oil reservoir. The cover was distorted
from the mis-alignment and had 1/16 inch gouges in the gasket seating
area. A review of historical work orders (WO) revealed that a slight
oil leak had been present for some time (WOs 96099135 and 97085335), and
had not been resolved (inspectors reviewed the WOs).
Both the WOs had
been worked but the repair shop had reused the existing cover. The
existing cover contributed to the leakage in that the distorted cover
coupled with gasket seating area gouges reduced the effectiveness of the
oil sealing joint.
During the current repair, a spare aluminum cover
was used to replace the existing cover thereby eliminating this
cOntribution.
The licensee was also proceeding with the replacement of existing
aluminum covers with steel covers in an effort to reduce distortion and
leakage possible with the exi-sting aluminum covers. This effort had
been started before, but was abandoned. Visual inspections by the
licensee and the inspectors revealed no other oil leakage on the other
three .RCPs.
The inspectors concluded that the lack of effective corrective action on
the previously identified oil leak was a weakness. The pump reservoir
is non-safety .related equipment and not subject to enforcement.
1A2 RCP
The 1A2 RCP had.an increasing leakage trend on its number one seal. On
disassembly, the licensee discovered that the Teflon double seal delta
channel seal (DSCS) had begun to deteriorate. The licensee had
documented their review and evaluation under failure investigation
process (FIP) in PIP 1-98-3832. The final process report was signed off
August 26, 1998. The inspectors examined the DSCS, observed portions of
the shaft seal disassembly and inspection, reviewed the report, and.
reviewed the pump vendor information on the probable cause.
During the Unit 1 startup, the inspectors observed that all seals
behaved as expected and seal leak off values were within expected
ranges. The evaluation for the problem was good and the inspection
effort was methodical. The inspectors agree that the seal manufacturer
information and facts tend to support the licensee's theory that the
seals exhibited higher leakage rates as a result of two thermal
18
transients coupled with elevated RCS suspended solids, which occurred in
late December 1997 and May 1998.
c. Conclusions
The repair practice on the non-safety related 1B1 RCP lower oil
reservoir that had perpetuated a repetitive minor oil leak was poor.
The leak from the reservoir was the reason for the Unit 1 shutdown this
period. Engineering analysis of the current self-disclosing IBI RCP
reservoir leak was good.
Engineering analysis of the self-disclosing 1A2 RCP pump seal problem
was good.
E1.3 Emergency Power System Open Items and Commitments (Recovery Plan)
a. Inspection Scooe (37551)
The inspectors reviewed the licensee's initiative involving the
emergency power system open items and commitments with the NRC. This
licensee initiative was part of the recovery plan. The scope of the
initiative was to resolve several NRC open items and-7to close several
commitments concerning the emergency power system.
b. Observations and Findings
The initiative contained ten line items consisting of the following:
five items involving responses to violations: two items, commitments,
provided a response-to the interim Keowee report and the installation of
electrical protection for Keowee: one item, a VIO and a related LER.
documented corrective actions involving a Keowee event:.one item, an IFI
and an associated commitment, to install new ground detection equipment;
and one item, an IFI. to complete the root cause evaluation for relay
failures.
The licensee issued PIPs on the issues and performed failure
identification process of selected PIPs concerning these items.
As a result of the review of the initiative, the inspectors determined
the following: the five violations were being addressed in conjunction
with applicable PIP forms and three of the items were associated with a
FIP team report; the commitment involving the interim report was
completed on June 18, 1998, and the protection commitment is to be
implemented by Nuclear Station Modification (NSM) ON-53014; the
violation and the related LER for the Keowee event were being addressed
in conjunction with a PIP and were reviewed by the licensee using a FIP
team report: the ground detection commitment is to be implemented by NSM
ON-53004; and the IFI for the relay failures was being addressed by a
PIP and was reviewed using a FIP team report.
The PIPs and the FIP team reports were in general well written: the
problem identifications were easily understood, covered the individual
19
problem items, and listed related PIPs: the screening, operability, and
reportability reviews referenced TS. quality classifications, and
regulatory issues: the problem evaluations discussed the problem items
extensively and throughly; the FIP team results were technically sound.
and .showed good engineering judgement; and the corrective actions were
comprehensive and addressed the individual problem items. The PIP
corrective actions also contained, where applicable, the responses to
the NRC open items.
The inspectors observed that .the five violations were being prepared for
NRC closure and the PIP corrective actions associated with the
violations have been completed. The two modifications are scheduled for
INN67..a non-refueling outage'time frame, starting in November 1998.
c. Conclusions
The inspectors concluded that the use of the problem investigation
process to track to closure corrective actions for NRC open items and
commitments involving the emergency power system and the quality thereof
were good.
The inspectors concluded that, at management direction, the use of the
failure investigation process reports by engineering, when necessary, to
address significant issues involving the emergency power system and the
quality of the reports were excellent.
The inspectors concluded that the onsite engineering group was
addressing the open items and commitments involving the emergency power
system in a sound technical manner, with appropriate resources, using
approved methods, and with management and supervisory oversight.
This Recovery Plan item is closed.
E1.4 Emergency Core Cooling System (ECCS) Pumps' Net Positive Suction Head
(NPSH) and Containment Over Pressure Licensing Basis Assumption
a. Inspection Scooe (92903.37550)
The inspectors reviewed the licensee's actions associated with a 50.72
reported condition of being outside the station licensing basis that. was
identified by the NRC while reviewing the licensee's response to GL 97
04, NPSH for Emergency Core Cooling and Containment Heat Removal Pumps.
dated October 7. 1997. The licensee issued LER 50-269/98-011. Available
NPSH for RBS Pumps. Outside Design Bases Due to Incorrect Interpretation,
on September 17. 1998. to document this issue.
b. Observations and Findings
The NRC's request for additional information letter to Duke Power
Oconee, dated August 11. 1998. identified that the licensee's response
to GL 97-04. dated January 5, 1998. indicated a condition outside the
NRC reviewed and approved licensing basis. This condition was that the
20
ECCS pumps NPSH analysis reviewed and approved in the licensing basis,
as documented in .the Safety Evaluation Report dated July 6. 1973. did
not credit containment over pressure as an input in the determination of
available NPSH for ECCS pumps during a design basis accident: whereas
the revised licensee analysis in 1991 did credit containment over
pressure to assure the available NPSH was adequate for the RBS pumps
which are ECCS pumps. Containment over pressure is defined as that
pressure which is the difference between actual containment building
pressure and the vapor pressure due to containment sump water
temperature.
In 1991, the licensee identified that RB-over pressure was required to
assure RBS pumps' operability. This was documented in calculation OSC
4361, RBS Pump NPSH Analysis, dated May 31, 1991. This calculation was
performed when the licensee identified that the previous NPSH analysis
used non-conservative design inputs in that the most restrictive flow
path was not evaluated and an incorrect RBS pump NPSH requirement was
used. The calculation concluded that a minimum of 2 psig RB over
pressure was required to assure adequate NPSH for RBS pump operability.
The calculation verified that adequate RB pressure was available as
documented in calculation OSC-4240, UFSAR 15.14.5, LBLOCA Long Term
Containment Responsedated March 19. 1991. It was not identified that
this condition of crediting RB over pressure to assure RBS operability
was inconsistent with the licensing basis. UFSAR Table 6-1. NPSH
Available to ES Pumps During Recirculation, specified that adequate NPSH
was available without crediting RB over pressure.
The UFSAR was not
updated to reflect the late.st information.
In 1992. the licensee identified additional non-conservative design
inputs and again evaluated the RBS NPSH requirements with respect to RB
pressure. Calculation OCS-4467. RB Pressure Needed for RBS Pump
Operation, dated March 9. 1992. determined a slightly higher RB pressure
of 2.8 psig was required to assure RBS pump operability.
The
availability of -this RB pressure was documented in OSC-4240 as stated
above. The licensee again did not identify that credit for RB over
pressure was inconsistent with the licensing basis. The UFSAR was not
updated to reflect the latest information regarding NPSH and RB pressure
requirements. The failure to update the UFSAR was a non-compliance with
10 CFR 50.71e which requires the UFSAR to be updated to assure the UFSAR
contains the latest material developed.. This 1991 and 1992 failure to
update the UFSAR with this information does not reflect present licensee
performance. Additionally, a comprehensive program was initiated in
1997 to review the accuracy and revise the UFSAR. In accordance with
the Enforcement Policy,Section VII.B.3. a violation will not be
identified for this non-compliance with 10 CFR 50.71e.
In a 1996 UFSAR revision, the licensee revised the ECCS NPSH accident
analysis description to delete Table 6-1. All detailed reference to the
available and required LPI and RBS NPSH values were deleted.
This
included the Table 6-1 information that specified that .adequate NPSH was
available for the RBS pumps without crediting RB over pressure.
The
related 10 CFR 50.59 evaluation, dated May 22. 1996. addressed the
21
change as an editorial change dhly and did not recognize the revised
analysis was inconsistent with the licensing basis as described in the
SER, dated July 6, 1973. Subsequently, the 50.59 evaluation response to
the questions defining an unreviewed safety question (USQ) were
incorrect. Specifically, the response. should have been yes to item four
regarding the increased probability of malfunction of equipment
important to safety. The condition of crediting containment over
pressure to assure RBS pump operability was not included in the NRC
approved licensing basis, and was therefore an unreviewed safety
question. This is identified as VIO 50-269.270.287/98-08-02: Inadequate
50.59 Safety Evaluation for 1996 UFSAR Revision Related to ECCS Pumps'
NPSH Analysis.
A related issue identified by the licensee during this review was that
the containment pressure assumed in the NPSH analysis at event
initiation was not. consistent with a containment pressure value in TS,
It appeared that the negative .1
psig assumed in the analysis was less
limiting than the negative 2.45 psig referenced in TS 3.6.4.
This was
addressed in PIP 0-098-3976. . Revision 5 of Calculation OSC 4467. RB
Pressure Needed for RBS Operation revision 5. was completed on August
31. 1998. The revised analysis used negative 2.45 psig and 80 degrees F
as input to the model and determined that the initial conditions of
negative 1 psig and 160 degrees as used in the previous analysis
(revision 4) was more limiting for NPSH considerations.
This condition
was identified in the PIP as operable but degraded for the RBS pumps.
Compensatory actions were implemented to assure the assumptions in the
calculation were assured during plant operations. These actions
included establishment of periodic surveillance for reactor building
pressure and more restrictive values for boron water storage tank
temperature and lake temperature.. These were incorporated in procedure
PT/1.2.3/A/0600/01. Periodic Instrument Surveillance, dated August 21.
1998. A 50.59 safety evaluation was documented for the compensatory
actions in PIP 0-98-3976. dated August 21, 1998.
The licensee's actions to evaluate and initiate corrective actions
following NRC identification of this USQ and the related TS RB pressure
inconsistency issue were appropriate, timely, and consistent with the
requirements of GL 91-18. Revision 1, Information to Licensees Regarding
NRC Inspection Manual Section on Resolution of Degraded and
Nonconforming conditions. A 50.72 report was submitted on August 19,
1998. The operability was promptly evaluated and it was determined that
adequate containment pressure was available during a LOCA to assure pump
operability. This was documented in PIP 0-098-3889 dated August 11.
1998. and supported by Calculations OSC-6521.
Containment Response with
30 Minute Delay in LPSW Flow, revision 3 and OSC-4467.
RB Pressure
Needed for RBS Operation, revision 5. These calculations demonstrated
that containment pressure during a design base accident exceeded that
pressure required for RBS operation. A license submittal was being
developed to change the licensing basis to reflect the 1991 analyzed
condition crediting RB over pressure for RBS NPSH determination.
The
LER report 50-269/98-011 was issued on September 17, 1998. and included
22
corrective actions taken and- planned to correct the violation and
prevent recurrence.
The primary contributor to this issue regarding the licensee being
outside the licensing basis was that the licensee did not correctly
identify the licensing basis condition in their interpretation of the
SER. dated July 6. 1973. It was apparent in their January 5, 1998,
response to GL 97-04 that they interpreted the licensing condition to
include crediting containment over pressure. The ambiguity in the SER
regarding the use of "over pressure" when addressing vapor pressure and
the UFSAR Table 6-1 listing NPSH values which included containment over
pressure could lead the evaluating engineers to incorrectly conclude
that containment over pressure was an approved license condition.
The
documentation of the 1996 UFSAR revision 50.59 safety evaluation was
limited and did not reference these documents. Additionally, as
previously stated, the evaluation stated the UFSAR revision was
primarily editorial; therefore, it is indeterminate to what extent the
evaluator investigated the licensing basis.
c. Conclusions
A violation of 10 CFR 50.59 was identified for an inadequate safety
evaluation that did not identify the USQ associated with being outside
the licensing basis for LOCA accident analysis associated with RBS NPSH.
The NRC concluded that information regarding the reason for the
violation and corrective actions planned to correct and prevent
recurrence were adequately addressed on the docket in LER 98-011, dated
September 17. 1998. Although the licensee performance was poor in
identifying the licensing basis related to this design base assumption,
their performance was adequate in evaluating the operability of the RBS
pumps in the revised design base condition. The licensee's evaluation
demonstrated there was no safety concern related to this issue and no
modifications were required to assure RBS pump operability.
E2
Engineering Support of Facilities and Equipment
E2.1 Corrective Action Program
a. Inspection Scope (40500)
The inspectors reviewed the licensee's corrective action program which
was implemented by Nuclear System Directive (NSD) 208. Problem
Investigation Process. Revision 18. Aspects of the process reviewed
included significance screening. operability evaluations, cause
determination, adequacy of corrective actions, and timeliness of
corrective actions. A sample of approximately 100 PIPs were reviewed.
The majority of the sample were Level 3, less significant event (LSE)
PIPs, and a smaller number of Level 1 and Level 2. more significant
event (MSE) PIPs, initiated'in 1997 and 1998. The sample included both
completed and in-process PIPs.
23
b. Observations and Findings
(1)
Significance Screening
The criteria for determining the significance of PIPs were provided by
directive NSD 208. A multi-organizational screen team evaluated each
PIP for significance in accordance with these criteria during work week
daily meetings. Many PIPs were conservatively categorized as Level 2
MSE PIPs initially to ensure that an operability evaluation was
performed on those problems with potential operability' impact.
These
PIPs were downgraded to LSE PIPs if no operability or reportability
concerns were identified. Downgrading of PIPs was adequately controlled
by the SRG. The inspectors' sample indicated that the licensee was
effectively categorizing PIPs with respect to significance.
One
exception was noted related to a Level 3 LSE PIP (1-098-2616) which
addressed repeated RCS sample valve failures. The criteria indicated
that this PIP should have been categorized as a level two MSE PIP
because it appeared to be an adverse trend. Overall, screening
performance was generally good.
(2)
Operability Evaluations
Operability evaluations were adequate to determine the impact on
equipment and system operation. The inspectors noted that the
operability justification was routinely documented in the problem
evaluation section of the PIP rather than in the designated operability
section.
(3) Cause Determinations - Corrective Actions
Level 3 LSE PIPs received a less rigorous cause determination than MSE
PIPs and the documentation was generally less detailed. The inspectors
assessed cause determinations by the adequacy of the assigned corrective
actions for these PIPs. In the sample reviewed, the corrective actions
were appropriate to address the identified problem. Cause
determinations for the MSE PIPs reviewed were adequate and assigned
corrective actions were appropriate. The timeliness of corrective
actions was addressed in the review of the PIP backlog.
(4)
PIP Corrective Action Backlog
The inspectors reviewed the timeliness of PIP corrective actions
relative to the impact on the PIP corrective action backlog. The PIP
corrective action backlog was one of the initiatives discussed in the
Oconee Recovery Plan under the Management Focus Area of Self-Assessment.
During review of the PIP corrective action backlog, the inspectors noted
that the licensee's stated goal in the Oconee Recovery Plan was to
reduce the number of PIP corrective actions greater than six months old
from over 500 in August 1997 to less than 200 by December 31, 1998. The
licensee's performance indicators in the Oconee Recovery Plan showed
that at the end of July 1998, there were 232 PIP corrective actions
greater than six months old.
The 232 PIP corrective actions were in
24
line with the licensee's target of 240 by the end of July 1998.
During
further review of this initiative, the inspectors noted that there were
other licensee performance indicators of open PIP corrective actions
which were not discussed in the Oconee Recovery Plan.
There was also a
category of PIP corrective actions designated as management exception.
The performance indicators showed that there were 428 PIP corrective
actions in the management exception category that were greater than six
months old. The inspectors questioned why the PIP corrective actions in
the management exception category greater than six months old were not
included in the PIP corrective action backlog discussed in the Oconee
Recovery Plan. Licensee management stated that the PIP corrective
action backlog did not include management exception items because the
management exception items did not meet the licensee's definition of
what was considered to be a backlog item. The inspectors concluded that
there was a weakness in the PIP corrective action backlog discussed in
the Oconee Recovery Plan in that it was not an accurate reflection of
the overall backlog of PIP corrective actions at Oconee.
c. Conclusion
Screening of PIPs was good in that the significance was appropriately
identified. Downgrading of PIPs was adequately controlled.
Operability evaluations of the identified problems were adequate.
Cause
determinations and assigned corrective actions were adequate.
The PIP
corrective action backlog, as stated in the Oconee Recovery Plan.
provided an unclear and inaccurate assessment of the overall PIP
corrective action backlog.
Specifically, the recovery plan stated that
there were 232 open PIP corrective actions greater than six months old.
while other performance indicators .showed the actual number was
approximately 660 (which included 428 management exception items) open
PIP corrective actions.
E7
Quality Assurance in Engineering Activities
E7.1 Self-Assessment Activities
a. Inspection Scope (40500)
The inspectors reviewed selected licensee initiatives in the Oconee
Recovery Plan under the management focus area of self-assessment.
These
initiatives included Corrective Action PIP Backlog (discussed in Section
E2.1 of this inspection report). PIP Quality, Manager Observation/Group
Ass-essment Effectiveness and Benchmarking, and Enhance SRG Self
Assessment Processes.
b. Observations and Findings
(1)
PIP Quality
The purpose of this initiative was to raise the level of PIP quality by
having the SRG review closed PIP activities for compliance with
Directive NSD 208 and reopen those PIP reports where improvements were
25
needed. The inspectors reviewed several SRG assessment reports and
noted that the SRG has been identifying areas for improvement in the PIP
process.
The SRG has been providing the results of their reviews and
feedback to the responsible organizations and to plant management. The
SRG also updated the Oconee PIP data base to provide additional guidance
to PIP report preparers for those areas identified in the assessments as
needing improvements. These efforts by the SRG have contributed to the
reduction in the percentage of PIPs being rejected from approximately 24
percent in August 1997, to approximately 9 percent in July 1998.
The inspectors concluded that the PIP quality reviews performed by the
Safety Review Group were effective in identifying areas for improvement
in the PIP process.
(2)
Enhance SRG Self-Assessment Processes
The purpose of this initiative was to improve the structure of the
Independent Nuclear Oversight Team (INOT) based on the Safety Assurance
strategic study. The INOT included SRG members for each of the NRC
systematic assessment of licensee performance (SALP) functional areas.
The INOT was performing in-plant reviews of activities based on the NRC
SALP functional areas. The inspectors revi.ewed some--of the milestones
established in the Oconee Recovery Plan for this initiative.
All INOT
members were transferred to the SRG by the established date of June 1,
1998.
However, the operations SALP area SRG member returned to
operations. Actions to replace the operations area SRG member were in
progress at the conclusion of this inspection. The inspectors reviewed
the Oconee 1998 assessment schedule (which included SRG in-plant
reviews) and noted that SRG in-plant reviews were being performed in
accordance with established schedules. The inspectors also noted that
the programs and directives under which the INOT will function
(including INOT roles and responsibilities) were being revised and/or
developed to reflect the current SRG organization.
The inspectors concluded that in-plant reviews were being performed in
accordance with established schedules. However, programs and directives
under which the INOT will function were still in the process of being
revised to reflect the SRG organization (including the INOT roles and
responsibilities).
E7.2 Licensee Safety System Engineering Audit (SSEA) of Emergency Feedwater
(EFW)
a. Inspection Scope (37550,40500)
The inspectors reviewed the licensee's SSEA of EFW to assess the
inspection scope and findings.
b. Observations and 'Findings
The inspectors found that the licensee's.SSEA of EFW had an appropriate
scope, which was similar to the scope of an NRC Safety System
26
Engineering Inspection. The SSEA. final report included some good
findings (e.g. , numerous calculation deficiencies and drawing errors
which the licensee evaluated as having no impact on the calculation
conclusions or on system operability). Also. the inspectors verified
that the.SSEA findings and recommendations were appropriately entered
into the licensee's corrective action system for resolution.
All of the
SSEA findings were appropriately assessed by the licensee as less
significant issues, for which no operability evaluation was needed.
However, the inspectors noted that the SSEA may have missed some
significant issues.
(See Section E8.1 of this report for potential EFW
design issues raised by the -inspectors.)
The SSEA also failed to
identify an incorrect statement in the UFSAR that stated that once
started, the EFW pumps would continue to run until stopped by an
operator. The UFSAR statement overlooked an automatic trip of the
turbine-driven EFW Pump at a low OTSG pressure of 500 psig.
The
inspector noted that the licensee's -UFSAR review project had also missed
the EFW design issues and UFSAR error. Therefore, the overall inspector
assessment of the licensee's SSEA of'EFW will not be completed until the
significance of these inspector-identified potential design issues is
.resolved.
c. Conclusions
The licensee's EFW SSEA had an appropriate scope and included some good
findings (e.g., calculation deficiencies), but both the SSEA and the
UFSAR review project missed some significant issues.
The overall
inspector assessment of the EFW SSEA will not be completed until the
significance of inspector-identified potential design issues is
resolved.
E8
Miscellaneous Engineering Issues (92903)
E8.1
(0oen) URI 50-269.270.287/98-03-09:
Licensing Basis Issues With Single
Failure and QA For Non-Safety Equipment Required To Mitigate An Accident
a. Insoection Scooe (92903.37550)
This URI was opened for further NRC review of licensing basis issues
with single failure vulnerabilities and quality assurance for non-safety
equipment that was relied upon to mitigate a design basis accident.
The
inspectors reviewed the OSRDC Program and its treatment .of quality
.assurance .and single failure.
b. Observations and Findinas
The inspectors found that the licensee's OSRDC Program was identifying
non-safety equipment that was relied upon to mitigate a design basis
accident and addressing quality assurance treatment of that equipment
(in the form of maintenance and testing).
The OSRDC Program was not
looking for or in any way addressing single failure vulnerabilities.
27
The inspectors also found that the equipment that was designated QA-1
(which meant that 10 CFR 50. Appendix B was applicable) was not
necessarily the same equipment that was included in various programs to
improve safety; such as single failure, seismic, environmental
qualification (EQ).
GL 89-10 motor-operated valve (MOV)
testing.
Regulatory Guide (RG)
1.97 instrument qualification, in-service testing
(IST).
preventive maintenance (PM),
TS. or probabilistic risk.assessment
(PRA). To better understand the application of *design standards and
programs at Oconee, the inspectors selected 31 components that were
relied upon to mitigate design basis accidents and then.reviewed whether
they had been included in these programs.
In selecting the 31 components for review. the inspectors tried to
include some that should have been classified as QA-1 and some that
likely were not QA (10 CFR 50. Appendix B did not apply).
The
inspectors also included several components that were in the EFW system.
to gain some knowledge of that system to use in part as a basis for
evaluating the licensee's current EFW SSEA. After further review. the
inspectors found that approximately half (16) of the 31 components
selected were QA-1 and approximately half (15) were not fully QA.
This
supported the previous licensee and NRC assessments that many .components
that were relied upon to mitigate design basis accidents were not in a
QA program.
The 31 components and their QA status were as follows:
Comoonent
OA Status
1) Turbine-Driven Emergency Feedwater
Not Fully QA
(FDW PU-003)
(Lubricating Pump Oil
System Not QA)
2) Motor-Driven EFW Pump (FDW PU-004)
QA-1
3) EFW Flow Control Valve (FDW VA-315)
Not Fully QA (Air
Operator and Air Supply
Not QA)
4) FDW VA-315 Manual Loader (FDW ML-0046)
Not QA
(for manual operation from the control
room)
5) EFW Minimum Flow Bypass Valve
QA-1
(FDW VA-370)
6) Main Feedwater Pump Hydraulic Oil
QA-1
Pressure (FDW PS-0382) (used to
autostart EFW)
7) Motor-Driven EFW Pump From Upper Surge
QA-1
Tank (UST) Suction Isolation Valve
(C VA-573)
28
8) Turbine-Driven EFW Pump From Hotwell
QA-1
Suction Isolation Valve (C
VA-391)
9) EFW Cross-Tie Valve (FDW VA-0313)
QA-1
(to get EFW from other units)
10) Condenser Hotwell Emergency Makeup
QA-1
Valve (C VA-0187) (dumps UST.to hotwell)
11) Main Condenser Vacuum Breaker Valve
Not QA
(V VA-186)
12) UST Level Transmitter (C LT-0015A)
QA-1
13) UST Level Indicator (C P-0081)
QA-1
14) Condenser Hotwel.l Level Transmitter
Not QA
(C LT-0019A)
15) Control Room Ventilation System (CRVS)
Not QA
Outside Air Damper CD-10A
16) CRVS Booster Fan AH-26
Not QA
17) CRVS Radiation Monitor (RIA RT-0039)
Not QA
18) Letdown Storage Tank Level Transmitter
Not QA. but
(HPI LT-0033)
Modi fication Scheduled
to Upgrade to QA-1
19) Caustic Pump (CA PU-004)
Not QA
20) Caustic System Valve (CA VA-0039)
Not QA
21) Main'Turbine Stop Valve (MS VA-0102)
QA-1
22) Main Turbine Stop Valve Trip Solenoid
QA-1
Valve Not (EHC SV-1083)
23) Main Feedwater Flow Control Valve
Not.Fully QA (Air
(FDW VA-0032)
Operator and Air Supply
Not QA)
24) Main Feedwater Block Valve (FDW VA-0031)
Not QA
25) Main Steam Pressure Transmitter
QA-1
(MS PT-0277)
26) Steam Generator A Level Transmitter
QA-1
(FDW LT-0080)
29
27) Steam Generator Shell Temperature
Not QA
Indication (FDW IOA-0972)
28) Steam Generator Level Control System
QA-1
(SGLCS)
29) Main Steam Isolation Logic Manual Switch
QA-1
(S-1016)
30) Steam Generator Atmospheric Dump Valve
Not QA
(MS VA-0162)
31) Block Valve for Steam Generator
QA-1
Atmospheric Dump Valve (MS VA-0153)
The inspectors found that the licensee's basis for designating
components as QA-1 was not based on safety function, but instead was
based on being designated as QA-1 equipment in Chapter 3 of the UFSAR.
The inspectors further reviewed components that were not QA and that
were either: 1) relied on in a system that was described in the UFSAR as
safety-related and QA-1 or 2) vulnerable to single failure.
The
inspectors assessed components as vulnerable to singTe failure if the
single active failure of a component would challenge the system design
basis or the accident mitigation strategy. Those non-QA components that
were further reviewed are discussed under Single Failure below:
Sinale Failure
The inspectors assessed that 11 of the 31 components were vulnerable to
single failure. Two of the 11 were also in a system that was described
in the UFSAR as safety-related and QA-1.
Those 11 components included:
- 1)
An air-operated 12-inch valve in a 20-inch line that dumped UST
water to the main .condenser hotwell. C-187.
Since the UST was the
suction source for all EFW pumps, the inspectors noted that a
failure open of C-187 could result in a rapid loss of all UST
water and a consequent loss of EFW. Each Oconee unit had a
hotwell level transmitter that, on a low hotwell level, would
automatically open valve C-187 to dump water from the UST to the
hotwell.
However, at a UST level of seven feet. the hotwell level
signal would be overridden by a UST level signal and C-187-would
go closed to protect sufficient UST water to supply the EFW pumps.
C-187 would also fail closed on a loss of instrument air. Valve
C-187 was QA-1 and seismic, was not in a harsh environment (EQ was
not applicable), was in the IST program, was in a PM program, was
not in TS or selected licensee commitments'(SLC).
and was in the
PRA. The potential untimely dumping of the UST to the hotwell,
due to the failure open of C-187 during a main feedwater line
break, was identified in the PRA as a significant contributor to
the probability of a loss of all EFW.
30
The UFSAR stated that the EFW system could.withstand a single
failure coincident with a secondary pipe break and a loss of
offsite power. However, the PRA apparently contradicted the UFSAR
when it stated that a single failure of C-187 coincident with a
main feedwater line break would cause a loss of all EFW. . Also.
the inspectors found that a 1973 licensee report to the NRC on
high energy line breaks outside containment stated that a main
feedwater line break in the turbine building would cause a loss of
all main feedwater, a loss of all EFW.
and also may cause a loss
of 4160-volt switchgear 1TC. 1TD., and 1TE.
These 4160-volt
switchgear were the three trains of safety-related power to the
motor-driven EFW pumps and also to engineered safeguards equipment
including high pressure injection pumps, low pressure injection
pumps, building spray pumps. and low pressure service water pumps.
The inspectors noted that, in addition to apparently contradicting
the UFSAR. this information did not seem to be reflected in the
PRA. The 1973 report was still the analysis of record for main
feedwater line break and was currently referenced in the FSAR.
(Note: Main feedwater line break was not a licensed design basis
event and was not discussed in the.accident analysis chapter of
the UFSAR.)
In response to concerns about the potential inability of the EFW
system to withstand a main feedwater line break or a single
failure coincident with a secondary pipe break, the licensee
initiated a PIP to review.the issue.
The inspectors plan to
follow up on this issue.
2&3) An. air-operated EFW flow control valve, FDW-315. and the manual
loader for control room operation of that valve. Each Oconee unit
had two EFW flow control valves, one in the discharge piping from
each motor-driven EFW pump. During certain events, including a .
main steam line break, operators were to immediately throttle EFW
flow to prevent damage to the EFW pumps.
As. a result of low pump
discharge pressure that could result from a main steam or feed
line break, two of the three EFW pumps could have insufficient
NPSH:
the safety-related motor-driven pump that supplied water to
the affected OTSG and the non-safety related turbine-driven pump.
which supplied water to both OTSGs.
The EFW system design basis
included.the ability to respond to a design basis event (e.g.,
main steam line break) coincident with a single failure and a loss
of offsite power. If two EFW pumps could be damaged due to the
event, the EFW system would not be able to then withstand a single
failure of the remaining EFW pump.
- For a main steam line break
inside containment, operators were also relied-upon to manually
stop EFW flow to affected OTSG within 10 minutes to prevent
overpressurizing the containment.
There was a motor-operated
valve in the discharge piping from each motor-operated EFW pump
that the operators could close from the control room to stop EFW
flow.
However, the inspectors considered the operator action to
throttle EFW a type of single failure vulnerability because one
31
operator could be relied upon to correctly perform all of the
required manual actions.
The EFW system was described in the UFSAR as safety-related and
QA-1. The EFW flow control valve bodies were QA-1 and seismic.
The air operators were not QA-1 but were seismic.
The manual
loaders and instrument air supply to the valve operators were not
QA-1 or seismic. A two-hour supply of nitrogen, to assure the
ability to operate the valves from the control room, was not QA-1
and was not seismic. However, the licensee had committed to the
NRC in 1987 to walk down the nitrogen supply lines and verify that
they would withstand a seismic event. The valves were EQ. were in
the IST program, were in a PM program, were in the TS. and were in
the PRA. The manual loaders were not QA or seismic, but were
included in the licensee's Seismic Qualification Users' Group
(SQUG) program. (See Seismic below for a description of the SQUG
program.) An inspectors' walkdown reviewing the seismic
ruggedness of the nitrogen supply lines to the EFW flow control
valves is documented in Section E8.7 of this report.
The loaders
were not in a harsh environment, were in a PM program, were in the
TS. and were in the PRA.
The PRA described the operator action to
immediately throttle EFW flow (using the EFW flow control valves
and manual loaders) as a significant contributor to the
probability for the loss of all EFW.
During a walkdown of portions of the EFW system, the inspectors
observed that operator access to the handwheel of Unit 3 EFW flow
control valve FDW-316 during an event would involve the operator
climbing off a platform, over a handrail. and walking about 6 feet
on a horizontal pipe that was about 15 feet above the floor.
(The
platform did not go to the valve and there was no room to use a
ladder.)
The air operator for FDW-316 was non-safety related, and
the licensee had documented to the NRC that operators could
readily operate the valve by handwheel during an event.
An
operator and the Operations Superintendent stated that, during an
event, plant safety would take priority over personal safety and
the operator would walk on the pipe to access the handwheel.
The
inspectors noted that this design condition, that placed operators
in the position of jeopardizing personal safety to support plant
safety during a design basis event, had existed.in the plant for
many years without the licensee identifying it.
In response to
this inspectors concern, the licensee initiated a PIP on this
issue. The inspectors plan to follow up on the licensee's
resolution of operator access to FDW-316.
The inspectors found that a licensee analysis concluded that the
EFW pumps, that were feeding an OTSG affected by a steam line
break, could experience insufficient NPSH or pump runout in less
that one minute as a result of rapid depressurization of the OTSG
to less than about 500 psig. Licensee personnel stated that,
based on training simulator drills, they had concluded that
operators could be relied on to throttle EFW within three minutes
32.
during a main steam line break event. Licensee personnel also
stated that they had no valid test or other data to support their
contention that the EFW pumps could operate for several minutes
with insufficient NPSH without suffering -damage.
The inspectors
noted that the-NRC typically has not approved reliance on simple
operator actions (e.g. , turning a switch in response to an alarm)
in less than 10 minutes or reliance on complex operator actions
(e.g., throttling flow to a specified value a.s read on a meter) in
less than 20 minutes, to mitigate design basis events. The NRC
also has not typically .approved reliance on operating multiple
stage pumps (like the EFW pumps) with insufficient NPSH, to
mitigate design basis events.
The inspectors found that the reliance on operating the EFW pumps
with insufficient NPSH had been identified as the most important
finding of a 1987 NRC Safety System Functional Inspection (SSFI)
of EFW. The issue had been cited as a Severity Level III design
control violation with a civil penalty. However, the violation
had subsequently.been with*drawn by the NRC because the licensee's
original design requirements did not include pump runout concerns.
The violation withdrawal stated that further enforcement action
was not warranted because the licensee planned:to eliminate the
NPSH problem by installing flow limiting ventiris.
However, the
licensee had subsequently decided not to install the flow limiting
venturis and had withdrawn the related commitment.
In response to the current inspectors' concerns with the reliance
on operators performing complex actions within three minutes and
the reliance'on EFW pumps operating with inadequate NPSH for about
two minutes. the licensee initiated a PIP. performed an
operability evaluation, and discussed this issue with the NRC.
The licensee stated that, as part of their operability evaluation,
they discussed the issue with the EFW pump vendor and received a
document from the vendor stating that the EFW pumps could operate
for at least five minutes with insufficient NPSH without being
damaged. The inspectors noted that the licensee had installed a
main steam line break protection circuitry in about 1996 that
.automatically stopped main feedwater and also automatically
stopped the turbine-driven EFW pump on a low OTSG pressure of 500
psig.
This circuitry could potentially protect the turbine-driven
pump from running with insufficient NPSH.
However, the licensee
did not want to rely on this circuitry, as part of their licensed
EFW design basis, to protect the turbine-driven EFW pump from
operating with insufficient NPSH. Instead, the licensee's
operability evaluation concluded that the EFW system was operable
based on a 1981 NRC SER that had approved the EFW system design
with reliance on operator action, and the fact that the SER did
not place time constraints on the operator action.
The NRC will continue to review the following potential design
vulnerabilities: 1) the reliance on.operator action to
immediately throttle EFW flow while using non-safety related
33
equipment and while the EFW pumps operate with insufficient NPSH:
2) poor operator access to the handwheel of Unit 3 EFW flow
control valve FDW-316; and 3) the licensee's plans for modifying
the EFW system to eliminate the reliance on immediate operator
action, using -non-QA equipment, and pump operation in runout.
4&5)
A caustic pump and a caustic valve. Each Oconee unit had one
caustic pump and several handwheel-operated caustic valves,
located in the auxiliary building, that must be manually operated
during a loss of coolant accident.
Operators would use this
equipment to add sodium hydroxide to the containment sump for pH
and iodine control.
(At newer plants, this function was typically
included in the automatic safety-related ECCS systems.)
The
caustic pump and valve were not QA (10 CFR 50. Appendix B did not
apply). were not seismic, were not in a harsh environment (EQ was
not applicable), were not in the IST program, and were not .in
the
TS or another administrative control program. The pump was in a
periodic testing program but the valve was not.
(See Preventive
Maintenance below.)
The pump and valve were not in the PRA. since
the lack of caustic addition would not have any impact on core
damage probability and would have little effect on releases to
atmosphere within the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of an acc.tdent.
(Note: The
PRA only considers the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of an accident.)
The inspectors found that the licensee had recognized the single
failure vulnerability of the caustic addition system and engineers
were informally investigating an alternate backup method for
caustic addition. In response to inspectors' questions, the
licensee opened a PIP to develop and write a procedure for an
alternate method of caustic addition.
6) A main feedwater flow control valve.
Each Oconee unit had two
main feedwater flow control valves, one for each steam generator.
These were air operated valves that received an automatic signal
to close following a main steam line rupture.
Each was designed
to close fast enough to prevent overpressurizing the containment
building.
The valve bodies were QA-1 but the air operators were
not QA and the air supply was not QA.
On a loss of air pressure,
the valves did not move - they failed 'as is. ' The main feedwater
flow control valve bodies were seismic but the air supply and .
operators were not: the valves were not in a harsh environment (EQ
was not applicable), were in the IST program, and were in a PM
program.
The valves were not in TS but were in the SLC program
which was an administrative control program similar to TS.
The
valves were not in the PRA because the core damage probability of
the steam line rupture event was less than the PRA truncation
level of 10 E-8.
The inspectors found that the NRC was currently reviewing the
licensee's design for mitigating a main steam line break inside
containment, including the design of the main feedwater flow
control valves, pursuant to NRC Bulletin 80-04 and a related
34
license amendment request. The inspectors provided comments on
this issue to the assigned NRC reviewers.
7&8) A main turbine stop valve and a main turbine stop valve trip
Each Oconee unit had four main turbine stop
valves (two valves in parallel from each steam generator) located
at the main turbine and two main turbine stop valve'trip solenoid
valves (in series) that tripped the four turbine stop valves.
Each hydraulically operated main turbine stop valve must
automatically close on a reactor trip to prevent RCS overcooling.
(Note: There were no separate main steam stop valves.)
The main
turbine stop valve was QA-1 and seismic, as were the main steam
lines from the steam generator to the main turbine stop valves.
However, the trip solenoid valve was not QA and was not seismic.
The stop valve and solenoid valve Were not in a harsh environment
(EQ was not applicable). were in the IST program, were in a PM
program, and were in the TS. They were not in the PRA because
their failure was bounded by a stuck open main steam relief valve.
The turbine control valves also closed when the stop valve trip
solenoid valves tripped and provided some backup for the turbine
stop valves. Also. the turbine mechanical trip valve and
immediate operator action to manually trip the-turbine from the
control room provided some backup for the stop valve trip solenoid
valves. In response to a 1993 Unit 1 transient (documented in PIP
1-093-0950) caused by a stop valve trip solenoid valve failure
(due to sticking). and also in response to 1993 requirements from
their insurance company. the licensee had instituted a PM to
periodically replace the turbine stop valve trip solenoid valves.
The inspectors found that the NRC had approved the licensee's
turbine trip design, including the fact that the main turbine stop
valve trip solenoid valves were not QA-1, in an NRC SER regarding
GL 83-23. Required Actions Based on Generic Applications of the
Salem Anticipated Transient Without Scram (ATWS)
Event, dated
August 3, 1995. The NRC.had also addressed this issue in a letter
- dated October 6, 1995, which withdrew Deviation 50-269.270.287/95
09; Solenoid Valves Associated With Main Steam Stop Valves Are Not
Safety-Related.
9&10) A control room ventilation system (CRVS) booster fan and a CRVS
outside air damper. Each Oconee control room (one for.Units 1 and
2 and one for Unit 3) had two outside air dampers and two 50%
capacity booster fans. To provide 1/8-inch water gauge pressure
in the control room for habitability during certain accidents,
both outside air dampers and both booster fans must operate.
The
CRVS booster fan and damper were not QA. were not seismic, were
not in a harsh environment (EQ was not applicable), were not in
the IST program but were periodically tested by a performance'test
(PT).
and were in the TS.
The booster fan was in a PM program but
the damper was not.
The-fan and damper were not in the PRA
because their failure did not directly affect core damage
probability or.releases to the atmosphere. The inspectors
35
verified that. the licensee's emergency operating procedures (EOPs)
did not direct the operators to abandon the control room in the
event of high radiation levels in the CRVS or in the control room.
The licensee recognized that the CRVS was vulnerable to a single
failure of a booster fan or a damper. In response-to related NRC
concerns documented in IR 50-269.270.287/98-03. the licensee was
working to better seal the control rooms toward removing this
single failure vulnerability. The licensee's sealing efforts
included sealing leaks in ventilation ducts, repairing weak damper
actuators, and repairing leaking dampers.
The licensee contended
that the NRC had not required that the CRVS be able to withstand a
single failure when post-TMI action item III.D.3.4, Control Room
Habitability, was applied to Oconee.
The licensee's position, that the CRVS was not required to be able
to withstand a single failure, was currently under review.by the
NRC as part of URI 50-269.270,287/98-03-08.
11)
A steam generator shell temperature computer point.
Information
from this computer point was relied on by operators to control the
plant cooldown rate and ensure that it was not excessive.
This
temperature indication was not QA. was not seismic, was not in a
harsh environment (EQ was not applicable), was not in the RG 1.97
program, was not in a PM program, was not in TS. and was not in
the PRA. The inspectors found that the purpose of the operator
use of this indication was to minimize temperature stresses in the
Faster cooldown was not expected to immediately damage the
OTSGs. but could increase the probability of future OTSG damage.
Also, the operators had other indications to rely on for
controlling the overall RCS cooldown rate.
The inspectors
concluded that, due to the low safety significance of a failure of
this instrument, this item did not warrant further review.
Almost all (nine of eleven) of these examples of components that were
vulnerable to single failure were not fully QA.
None were major
contributors to the PRA core damage probability. but two of the examples
were significant contributors to the PRA probability of EFW system
failure. Also, a main feedwater line break analysis that described a
consequential loss of all EFW and all three trains of safety-related
4160 volt switchgear was apparently not addressed by the PRA.
The
inspectors plan to follow up on the following potential design
vulnerabilities: 1) a single active failure in the open pbsition of
valve C-187 coincident with a main feedwater line break causing a loss
of EFW: 2) a main feedwater line break in the turbine building causing
consequential failures of the EFW system and all three trains of safety
related 4160 volt electrical switchgear 3) the reliance on operator
action to throttle EFW flow within three minutes while using non-safety
related equipment and while the EFW pumps operate with insufficient
NPSH: and 4) poor operator access to the handwheel of Unit 3 EFW flow
control valve FDW-316.
36
Seismic
Thirteen of the 30 components were not seismically designed.
Each of
the components that was not seismically designed was not QA. Six of the
thirteen were included in the SQUG Program. Under the SQUG Program,
each non-seismic component needed to safely shut down the plant during
normal (non-accident) conditions should be inspected by individuals
experienced with seismic design.
They should judge whether the
installed components look like they would withstand an earthquake or
whether modifications would be needed.
The licensee would then install
modifications as needed. The licensee's SQUG Program was included in
the Oconee Recovery Plan.
Seven of the thirteen were not included in the SQUG Program:
a hotwell
level transmitter, caustic pump. caustic valve, steam generator shell
temperature indication, control room ventilation radiation monitor, main
feedwater block valve, and main steam stop valve trip solenoid valve.
The inspectors verified that UFSAR Section 3.2.2 described the seismic
design requirements and it did not require any of these components to be
seismically designed. The main steam stop valve trip solenoid valve is
discussed further under Single Failure above. The inspectors noted that
thePRA identified a seismic event as the largest contributor to the
potential for core damage.
Environmental Qualification
Five of the 30 components were in a potentially harsh environment. All
five were QA-1 and were also EQ.
Three of the 30 components were MOVs. One was QA-1 and -was also in the
GL 89-10 Program.
Two were not QA and were not in the GL 89-10 Program.
Those two, a main feedwater block valve and a main condenser vacuum
breaker, were not vulnerable to single failure.
While the main
feedwater block valve was automatically closed on a main steam line
rupture and provided some backup to the main feedwater flow control
valve in mitigating a main steam line break, the licensee did not take
credit for the valve closing ih their accident analysis. Operators
would have to open the main condenser vacuum breaker valve to use the
water in the condenser hotwell as a backup source of water for the EFW
pumps.
However, the licensee did not take credit for the motor operator
of.the main condenser vacuum breaker but instead relied on handwheel
operation of the valve. The inspectors verified that the licensee had
satisfactorily tested the ability of operators to open the vacuum.
breaker valve to break condenser vacuum by using the handwheel.
RG 1.97 Program
Nine of the 30 components were instruments that provided indication on
which operators would rely to perform emergency procedures.
Six were in
the RG 1.97 Program and also were QA-1. Three were not in the RG 1.97
37
Program and also were not QA. Those three were:
Hotwell level indication, which would indicate to operators the
availability of TS-required water in the condenser hotwell. for
use as a backup source of water for the EFW pumps, as directed by
EOPs. The licensee stated that the operators did not need to know
the hotwell level 3s the EOPs contained no operator actions based
on hotwell level.
Steam generator shell temperature, which would be relied on by
operators to control the plant cooldown rate. The licensee stated
that operators could safely cool down the plant without reliance
on steam generator shell temperature indication (see Single
Failure above).
Control room ventilation radiation monitor alarm. which had been
relied on.by operators as the signal to start the control room
booster fans. Recently, the licensee revised emergency operating
procedures to require operators to start the control room booster
fans without relying on this alarm.
In-Service Testing
Eighteen of the 30 components were the type for which IST or other
testing would be appropriate. Nine were in the IST Program, four were
in the licensee's Appendix B Program (a periodic testing program similar
to IST).
and four were periodically tested under a Performance Test (PT)
Program. One was not in any periodic testing program and also was not
QA. The component, a caustic valve, is discussed above under Single
Failure and is also discussed below under Preventive Maintenance.
The
licensee's OSRDC Program was designed to identify the lack of periodic
testing for components like these and to add periodic testing.
Preventive Maintenance
Seven of the 30 components were not in a routine PM or calibration
program. However, six of those seven components were in a periodic
testing program - the one exception was a manual caustic valve that was
not QA.
The inspectors verified that EOPs required that the manual
caustic valves be opened following a LOCA, to add sodium hydroxide to
the containment sump during recirculation.
The inspectors found that
the licensee had an annual Caustic Injection System Pump Test.
(PT/1&2/A/0203/009. Revision 13. for Units 1 and 2 and PT /3/A/0203/009.
Revision 11. for Unit 3) that tested the caustic pump and all but one of
the caustic valves for each unit. The one valve per unit that was not
tested was a manual caustic injection valve. (1CA-62,
2CA-63, and 3CA
62).
The inspectors found that the licensee's maintenance rule program had
addressed these caustic injection valves in closed PIP 0-090-3488, dated
July 9. 1998. The PIP stated that an acceptable'performance criteria
for the chemical addition system function to "provide caustic addition
38
to sump" has not been identified. The PIP response. from the system
engineer, stated that the annual performance test. PT/1&2/A/203/09 and
PT/3/A/203/09. that recirculates the caustic to a bin, was the
performance test for this function. The PIP response had overlooked the
fact that the annual performance test did not test the manual caustic
injection valves. A review of maintenance records found that valve 1CA
62 had last been stroked (the valve was replaced) in 1991: yalve 2CA-63
had last been stroked (the valve was repacked) in 1994: and valve 3-CA
62 had last been stroked (a body to bonnet leak was repaired) in 1981.
Since one of these valves had.apparently not been operated in 17 years,
the inspectors asked the licensee how they could assure that the valves
were currently capable of fulfilling their intended function (being
manually opened). In response, the licensee promptly revised the annual
Caustic Injection System Pump Test procedures to include opening and
reclosing the three manual caustic injection valves.
Also, the licensee
promptly opened and closed each valve and verified that they were
capable of performing their intended function.
10 CFR 50.65 requires that the licensee monitor the performance of
components, that are used in plant EOPs, in a manner sufficient to
provide reasonable assurance that the components are capable of
fulfilling their intended functions. Contrary to that requirement, the
licensee had not monitored the performance of caustic injection valves
Also, while 10 CFR 50. Appendix B. did not
apply to these non-safety related valves, the licensee's corrective
action for PIP 0-098-3488, dated July 9. 1998. had been poor in that it
overlooked these caustic injection valves. After this issue was
identified by the inspectors, the licensee took prompt corrective
action. Also, the licensee's OSRDC Program had already included the
caustic valves in a list of components relied on to mitigate accidents.
and would have identified and corrected the lack of caustic valve
testing within the next year. Further, the licensee stated that the
OSRDC Program will coordinate any lack of testing and maintenance that
it identifies with the Maintenance Rule Program.. This non-repetitive,
licensee-corrected violation that the licensee's established OSROC
Program would have soon identified is being treated as a Non-Cited.
Violation, consistent.with Section VII.B.1 of the NRC Enforcement
Policy. This is identified as NCV 50-269.270.287/98-08-03:
Failure to
Monitor the Performance of Manual Caustic Injection Valves.
TS and SLC
Fourteen of the 30 components were in TS and five were in SLC.
Eleven
of the 30 components were not included in either the TS or SLC
administrative control programs.
Those eleven included:
atmospheric
dump valve, block valve for atmospheric dump valve, condenser vacuum
breaker valve, motor-driven EFW pump UST suction isolation valve,
turbine-driven EFW pump hotwell suction valve, caustic pump, caustic
valve, UST level indication, condenser hotwell level transmitter, steam
generator shell.temperature indication, and control room ventilation
radiation monitor.
The inspectors found that six of these components
were included in a licensee maintenance rule administrative control
39
program. The five components that were not in any administrative
control program were:
steam generator shell temperature indication,
caustic pump, caustic valve, condenser vacuum breaker, and control room
ventilation radiation monitor. Based on the low safety importance of
these five components not being in an administrative control program,
the inspectors did not pursue this issue any further.
Thirteen of the 30 components were not in the PRA. Eight are discussed
above under Single Failure..'The other five included:
Letdown storage tank level indication. The licensee.planned to
include this in the next revision to the PRA as a result of the
recent High Pressure Injection Study.
Main steam pressure indication and main feedwater block valve.
These components are involved in main steam line rupture event and
are not in the PRA for the same reason as for the main feedwater
flow control valve (see Single Failure above):
Control room ventilation radiation monitor.
This component was
not in the PRA for the same reason as for the CRVS booster fan and
damper (see Single Failure above).
Manual valve for isolating the motor-driven- EFW pump suction from
the UST. Based on the inspectors questions. the licensee
initiated a PIP to review why this valve was not included in the
PRA.
c. Conclusions
The inspectors found that many components that were relied upon to
mitigate design basis accidents were not in a QA program.
Almost half
(15 of 31) of the components reviewed were not fully QA. In addition,
many of those same components (11 of 31) were vulnerable to single
failure. URI 50-269,270,287/98-03-09 remains open pending further NRC
review of the licensee's OSRDC program.
A non-cited violation of the maintenance rule was identified by the
inspectors for a failure to monitor the performance of manual caustic
injection valves. The licensee promptly responded to this issue,
including cycling the caustic injection valves to assure that they were
capable of fulfilling their intended function and revising a procedure
to include cycling the valves annually.
The inspectors also identified a poor design condition for both timely
access to equipment and personnel safety. in that operator access to the
handwheel of Unit 3 EFW flow control valve FDW-316 involved walking on a
horizontal pipe about 15 feet above the floor. This condition had
existed for many years without licensee identification and corrective
action.
40
Inspector Followup Item (IFI) 50-269,270.287/98-08-05. EFW Potential
Design Basis Issues, will be identified for further NRC review of the
following potential design vulnerabilities: 1) a single active failure
in the open position of valve C-187 coincident with a main feedwater
line break causing a loss of EFW; 2Y a main feedwater line break in the
turbine building causing consequential failures of the EFW system and
all three trains of safety-related 4160 volt electrical switchgear; 3)
the reliance on operator action to throttle EFW flow within three
minutes while using non-safety related equipment and while the EFW pumps
operate with insufficient NPSH: and 4) poor operator access to the
handwheel of Unit 3 EFW flow control valve FDW-316.
E8.2 (Ooen) VIO 50-269.270.287/98-03-07: Incorrect and Nonconservative
Assumptions in Control Room Operator Dose Calculations
a. Insoection Scooe (92903.37550)
In response to this violation, the licensee committed to perform CRVS
tracer gas testing to determine the amount of unfiltered inleakage into
the control room while the booster fans were operating.
The inspectors
observed portions of this testing.
b. Observations and Findings
The inspectors observed the pre-evolution briefing and the tracer gas
testing of the Unit 3 CRVS. conducted during evening off-hours.
The
inspectors observed that the sealing of leaks in the Unit 3 CRVS
ventilation ducting. that was located outside the control room in the
auxiliary building. looked very thorough and professional.
Also. the
sealing resulted in a substantial improvement in the attainable pressure
in the Unit 3 control room. with two outside air-booster fans running,
from less that 0.125 inches water gauge (w.g.) early in 1998 to 0.4
inches w:g. during this inspection. The test prerequisites were
appropriately met, tracer gas was injected, and some samples were taken:
however, the observed test was voided because of problems with the
laboratory equipment that was located in a nearby office building.
The
office building air conditioning had automatically turned off at night,
causing the temperature*-sensitive laboratory equipment to begin to
overheat and potentially become less accurate.
The test was rerun
another night after reprogramming the air conditioner controls. The
inspectors noted that preliminary test results, for tracer gas tests of
both control rooms, were well within the licensee's test acceptance
criteria.
The inspectors plan to review the official test report after
it is completed.
c. Conclusions
The inspectors observed that the sealing of leaks in the Unit 3 CRVS
ventilation ducting, that was located outside the control room in the
auxiliary building, looked very thorough and professional.
Also, the
sealing resulted in a substantial improvement in the.attainable pressure
in the Unit 3 control room, with two outside air booster fans running:
from less that 0-125 inches w.g. early in 1998 to 0.4 inches w.g. during
this inspection.
.
41
E8.3
(ODen) VIO 50-269.270.287/98-03-02: Failure to Perform Penetration Room
Ventilation System (PRVS)
Surveillance in Accordance with TS
a. Insoection Scooe (92903.37550)
In response to.this violation, the licensee committed to perform PRVS
Surveillance testing for air flow by using a pitot tube, as required by
TS 4.5.4.1.b.1. The inspectors observed portions of this testing.
b. Observations and Findings
The inspectors observed the testing of the Unit 2 Train B PRVS system,
per procedure TT/2/A/0110/202. Penetration Room Ventilation System 2B
Pitot Tube Flow Test, Rev. 0, Change A, dated August 4. 1998.
The
inspectors verified that the procedure implemented the requirements of
the TS and that licensee personnel followed the procedure using
appropriate test instruments. The straight run of pipe in the flowpath
upstream of the pitot tube testing location was 15 pipe diameters (15
feet of 12-inch pipe), which exceeded the seven pipe diameters usually
needed for good flow measurement accuracy.
The pitot tube was held by
hand during the flow measurements by a licensee contractor who was
experienced in performing such flow measurements.
At the inspector's
request, the licensee verified and the inspectors observed that angular
movement of the pitot tube by as much as about 20 degrees did not affect
the flow measurement.
The initial test result indicated a flowrate of 1156 cfm. which exceeded
the TS allowable flowrate of 1000 cfm +/- 10 percent.
The licensee
appropriately adjusted the flowrate and ran the test again, with an
acceptable result of 989 cfm. and then properly. re-blocked the position
of the 2B.PRVS flow control valve.
The licensee then tested the Unit 2
penetration room pressure: with the 2B PRVS fan running. and verified
that the penetration room pressure was still negative with respect to
all adjacent rooms (as required for PRVS operability).
That
satisfactorily completed the 2B PRVS testing.
The licensee
appropriately kept the Unit 2 PRVS in the required TS action statement
throughout the testing. Licensee test procedures. oversight, and
performance were good.
c. Conclusions
The inspectors concluded that the licensee's procedures, oversight. and
performance of the surveillance testing of the Unit 2B PRVS air flow.
using a pitot tube, were good.
E8.4 (Closed) IFI 50-269.270/97-01-01: Reactor Trip Confirm Circuit Fuse
Inspection
On or about March 3. 1997, the licensee identified that fuses'installed
in the redundant trip confirm circuity were of the wrong size.
For
example, the vendor's drawing for Unit 3 showed several fuses as 0.5 amp
and others as 5.0 amps. In addition some fuses were shown as 0.25 amp
42
and 10 amp. Units 1 and 2 exhibited similar discrepancies.
The correct fuses were determined and installed in all three units.
The
instrument and electrical (I&E)
procedure for breaker testing.
(IP/01A/0305/014-1: RPS Control Rod Drive Breaker Trip and Events
Recorded Timing Test) that led to the discovery of improper size fuses,
was revised to include a visual inspection for blown fuses prior to
beginning breaker testing. This was apparently the cause of the Unit 3
reactor trip on March 3, 1997. It was determined that a reactor trip
may occur if a blown fuse existed in the circuit when performing
IP/01A/0305/014-1.
The licensee issued PIP 0-097-1014 on March 3. 1997. to resolve the fuse
size discrepancies found while troubleshooting the root causes of the
Unit 3 reactor trip.
The licensee's review of the history and causal factors with an issue
involving fuses in the reactor trip confirm circuit was thorough and
timely. The vendor drawings have been revised and the correct fuses
have been installed. This IFI is closed.
E8.5 (Closed). URI 50-269/98-02-09: Failure of Valve 1HP-27 to Close
(Closed) LER 50-269/98-05-01: Valve Fails to Close Requiring Unit
Shutdown Due to Inadequate Procedure
(Closed) LER 50-269/98-05-00:
Valve Fails to Close Requiring Unit
Shutdown
This URI and LER involved the failure of Valve 1HP-27 to close during
engineered safeguards (ES) testing on February 14. 1998.
At that time
the licensee determined that the design basis should have assumed the
worst case static pressure acting under the seat instead of worst case
differential pressure across the valve. This item has remained
unresolved pending NRC review of the past operability evaluation.
The licensee determined that even though Valve 1HP-27 would not throttle
. closed under some conditions, the HPI system would have performed its
safety functions. In addition, the licensee reworked and tested valve
1HP-27 and revised the design basis calculations for all HPI injection
and crossover valves to include the higher static pressure.
The
licensee also planned to replace the motor operators for all HPI
injection and crossover valves with larger ones.
This has already been
completed on Unit 2 and has been scheduled for Units 1 and 3 during
upcoming outages.
The inspectors reviewed the past operability evaluation and determined
it was acceptable.
However, the use of differential pressure instead of
static pressure acting under the seat in the design basis constituted a
violation of 10 CFR 50 Appendix B, Criterion III. This non-repetitive.
licensee-identified and corrected violation is being treated as a NCV,
consistent with Section VII.B.1 of the NRC Enforcement Policy. This is
43
identified as NCV 50-287/98-08-04: Improper Design Basis Assumptions for
HPI Valves. These items are closed.
A non-cited violation was identified for improper design basis
assumptions regarding the high pressure injection system injection and
crossover valves.
The identification, analysis, and resolution of the design basis
concerns related to the failure of Valve 1HP-27 to close were adequate.
E8.6 Seismic Qualification Utilitv Grouo (SOUG)
Program Imblementation
a. InsDection Scooe (92903)
The inspectors reviewed the SQUG program implementation. outlier
resolutions, and modifications to determine the adequacy of the SQUG
program.
b. Observations and Findings
The inspectors discussed the SQUG program and.its implementation with
engineering personnel. The licensee had completed the selection and
walkdowns of the safe shutdown equipment.
The forms used for the
walkdown screening or evaluation were called "Screening Evaluation Work
Sheets (SEWS)"
which were provided by the General Implementation
Procedure (GIP) for more than 20 types of equipment or devices.
If
equipment or devices were outside those lists, they would be identified
as outliers.
The licensee completed 1692 walkdowns and generated 466
outliers for equipment. The licensee also evaluated 6135 devices for
chatter contact and generated 730 outliers.
The licensee resolved about 630 outliers.
The remaining outliers will
be repaired, replaced, modified, or require further analyses.
The
licensee recently completed modifications in the Keowee hydro station.
The inspectors randomly selected a portion of the Emergency Feed Water
(EFW)
line for walkdowns to verify that the equipment or devices for.the
safe shutdown alongthis line had been walked down and documented by the
licensee. The portion of the line selected was from Upper Surge Tank 3A
at the turbine building deck to valve 3CVA0391 in the turbine building
basement, approximately 120 feet.
The equipment included one upper
surge tank, three air operated valves, one motor-driven emergency feed
water pump, .one isolation valve, one motor-operated valve, two pressure
switches, four oil pressure switches, two level transmitters, two water
level indicators, and associated relays, cabinets, and other control
switches.
The inspectors reviewed the SEWS and other information
provide by the engineers for equipment and the devices identified along
the line and found that they were adequately documented and evaluated.
The upper surge tank required outliers for the evaluation of the.saddle
spacing, anchorage type, and the support legs. Modifications were
required to resolve the outliers.
44
The inspectors randomly selected five repairs or modifications completed
in the Keowee hydro station to determine if the resolution of the
outliers was adequate.
The following five repairs or modifications
stated in PIP 0-096-2783 were walked down by the inspectors and are
listed below:
ComDonent
DescriDtion of Work
SYDC-1 and 2
Increased weld size for anchorage
SYTC cabinets
Added padding between cabinets and columns for
interaction
Battery Racks
Replaced multiple compressible styrofoam with
rigid plexiglass at each end of the racks
HVAC AHU003
Added a horizontal restraint to prevent it from
hitting the cabinets
Cabinet ILCI
Added padding between cableway and 1LCI to
reduce the seismic impact on essential relays
The inspectors measured the weld size. length, anchor bolt diameters,
end attachments. steel wire, and examined the padding and plexiglass.
All the repairs or modifications met the drawing requirements.
The inspectors reviewed.the SEWS and associated outliers related to the
equipment and devices in the EFW line walkdown.
The outliers were
stated in the comments of the SEWS and the reasons for the further
evaluations or reviews were stated.
The inspectors also reviewed five
resolved outliers for the High Pressure Injection (HPI)
and Emergency
Feed Water (EFW)
Systems.
They involved remote starter enclosures 3RSC
3HP-409 and -410 for HPI: nitrogen supply bottles for feedwater valves
315 and 316: main steam valves 87. 126. and 129; and
EFW pump turbine
oil tanks ITDTKOOD2 and 3TOTKO02.
The licensee adequately resolved the.
outliers reviewed.
c. Conclusions
Based on-the sample-.reviewed. the licensee exhibited good progress in
the evaluation and resolution of the outliers for the SQUG program.
Most outliers resolved to date have been through
analyses or
documentation review. More complex outliers remain to be resolved by
repairs, -modifications, or refined analyses.
This Recovery Plan Item is closed.
45
E8.7
Walkdown of Nitrogen Supoly System for EFW Line
a. Insoection .Scooe (92903)
The inspectors walkeddown the nitrogen supply system to determine if
the system met seismic qualified requirements.
b. Observations and Findings
This nitrogen supply system was required to be seismically qualified per
the NRC letter from John F. Stolz, Director. PWR Project Directorate
Number 6. to Hal B. Tucker, Vice President - Nuclear Operations, dated
January 14. 1987. subject. "Seismic Qualification of the Emergency
Feedwater System."
This letter stated that the licensee has committed
to assure that the automatic bottled nitrogen system, including power to
the solenoid valves, will withstand an MHE.
The MHE is defined as
Maximum Hypothetical Earthquake or Safe Shutdown Earthquake (SSE).
The inspectors walked down non-safety-related nitrogen lines from the.
nitrogen supply bottles to valves FDW 315 and 316 for all three units
with the licensee's engineers and instrument operators.
These lines are
required for safe shutdown. The inspectors identified minor
discrepancies which were provided to the licensee for resolution.
The licensee issued PIP 0-098-4187. Revisions 0 and 1 to record the
deficiencies found by the inspectors and to evaluate the root cause and
their resolution. The PIP stated that the deficiencies found in the
nitrogen supply systems degraded the systems and did not meet the
standards for seismic mounting.
The nitrogen supply lines were not
safety-related and remained operable. The inspectors agreed with the
licensee's operability evaluation for the systems.
In.1996 the SQUG program personnel did perform the walkdowns for valves
FDW 315 and 316 and nitrogen bottles and no equipment deficiencies were
identified.
These walkdowns did not include the nitrogen supply lines
where the inspectors identified the deficiencies.
c. Conclusions
The deficiencies found in the seismic mounting of the nitrogen supply
lines for all three units degraded the EFW systems and indicated a
weakness in maintaining the nitrogen supply line supports.
IV.
Plant Support Areas
R1
Radiological Protection and Chemistry Controls
R1.1 Tour of Radiological Protected Areas
a. Inspection Scooe (86750)
The inspectors reviewed implementation of selected elements of the
46
licensee's radiation protection program as required by 10 CFR Parts
20.1902, and 1904. The review included observation of radiological
protection activities for control of radioactive material, including
postings and labeling, and radioactive waste processing.
b. Observations and Findings
The inspectors reviewed survey data of radioactive material storage
areas. Observations and independent radiation and contamination survey
results determined the licensee was effectively controlling and storing
radioactive material and all material observed was appropriately labeled
as required by 10 CFR Part 20.1904. All areas observed were
appropriately posted to specify the radiological conditions.
The inspectors determined the licensee was processing radioactive waste
to maintain exposures As Low As Reasonably Achievable (ALARA)
and to
minimize quantities of radioactive waste stored on site.
During the
inspection, the inspectors observed a liquid radioactive waste discharge
of 28.000 gallons and determined licensee personnel were following the
discharge procedure CP/O/B/5200/48. "Resin Recovery System Operation",
Revision 58. The inspectors also determined licensee personnel involved
with the discharge were knowledgeable about release criteria, alarm
limits, and discharge pathways. The licensee was trending liquid
radioactive waste to meet licensee established goals.
As of August 26,
1998. the licensee had released approximately 0.236 curies which was
below the year to date goal of 0.380 curies.
Work.practices observed
during radioactive waste processing were good.
c. Conclusions
The inspectors determined the licensee was effectively maintaining
controls for radioactive material storage and radioactive waste
processing. Work practices observed during radioactive waste processing
were good.
R1.2 Water Chemistry Controls
a. Inspection Scooe (84750)
The inspectors reviewed implementation of selected elements of the
licensee's water chemistry control program for monitoring primary and
secondary water quality as described in the TS limits, the Station
Chemistry Manual,
and the UFSAR.
The review included examination of
program guidance and implementing procedures and analytical results for
selected chemistry parameters, and observation of chemistry technicians
collecting water samples.
b. Observations and Findings
The inspectors toured the primary and secondary chemistry laboratories
and observed work in progress.
The inspectors observed a survey of the
primary laboratory and observed personnel frisking with laboratory coats
47
worn.
Personnel observed were using good radiological work practices.
The inspectors reviewed selected analytical results recorded for Unit 1
reactor coolant taken-between the period April 15. 1998, and August 26.
1998. and secondary samples taken between the periods May 25. 1998. and
August 3. 1998.
The selected parameters reviewed for primary chemistry
included dissolved oxygen, chloride, pH. and fluoride.
The selected
parameters reviewed for secondary chemistry included hydrazine, iron,
copper, sodium. dissolved oxygen, and chloride.
Those primary
parameters reviewed were maintained within the relevant TS limits for
power operations.
Those secondary parameters reviewed were maintained
within the limits of the Station Chemistry Manual.
The inspectors observed a boron sample collection from Unit 1 primary
system during startup. The inspectors verified that the sample
collection was performed as required by licensee chemistry sampling
procedure CP/1/A/2002/001. "Unit 1 Primary Sampling System". Revision
34.
The sample was analyzed as required by licensee procedure LM-0
P003A. "Determination of Boron Using the Mettler DL40GP". Revision 4.
Chemistry personnel performing the sampling and analysis followed the
procedures and appeared well trained to perform the task.
The inspectors observed a test of the Unit 2 post-accident liquid
sampling system (PALS).
The individuals observed followed the
established procedure CP/2/A/2002/004D.
- Test Procedure for the Post
Accident Liquid Sampling System". Revision 23.
However, the PALS test
was secured due to system leakage.
The system was removed from service
for maintenance.
c. Conclusions
The inspectors concluded that the licensee's water chemistry control
program for monitoring primary and secondary water quality had been
effectively implemented in accordance with the TS requirements and the
Station Chemistry Manual for water chemistry.
The inspectors also
concluded that the collection of the samples was performed in eccordance
with the licensee's chemistry sampling procedure.
R2
Status of RP&C Facilities and Equipment
R2.1 Process and Effluent Radiation Monitors
a. Insoection Scooe (84750)
The inspectors reviewed selected licensee procedures and records.for
required surveillance on process and effluent radiation monitors and for
radiation monitor. availability as required by TS, and Chapter 16 of the
48
Observations and Findings
During tours of the auxiliary building, turbine building, and radwaste
building, the inspectors-observed the physical operation of process
radiation effluent monitors in service.
The inspectors also toured the
control rooms and observed the status of radiation.monitoring equipment.
The inspectors reviewed radiation and process monitor surveillance
procedures and records for performance of channel checks. source checks,
channel calibratiohs. and channel operational tests. for four monitors.
The inspectors also observed control room personnel perform.alarm set
points for four monitors as required by licensee procedure
PT/O/A/0230/001, "Radiation Monitor Check". Revision 112.
The
inspectors determined the licensee was performing checks described in
the TSs and Chapter 16 of the UFSAR.and in accordance with license
procedures.
The inspectors reviewed the licensee's 1997 Annual Environmental Report
issued in May 1998. No equipment or sampling deviations for liquid
samplers, environmental air samplers, or environmental thermoluminescent
dosimetry (TLD) were identified during 1997.
The licensee had moved one
control location air sampler due to the construction of a school.
The inspectors also performed independent environmental surface
contamination surveys of selected areas near the licensee's visitors
center and confirmed survey results to be background as consistent with
licensee survey results reviewed.
c. Conclusions
The inspectors concluded radiation and process effluent and
environmental monitors were being maintained in an operational condition
to comply with TS requirements and UFSAR commitments.
R2.2 Meteorological Monitoring Eauipment
a..
Inspection Scope (84750)
The inspectors reviewed licensee procedures to verify licensee
compliance with the UFSAR which described the operational and
surveillance requirements for the meteorological monitoring
instrumentation.
b. Observations and Findings
The inspectors toured the control room and determi-ned the meteorological
instrumentation was operable and that data for wind speed, wind
direction, air temperature, and precipitation were being collected as
described in the UFSAR.
Based on review of records, the licensee was
tracking operability for meteorology equipment during 1998.
Based on
licensee operation records reviewed for wind speed, wind direction, and
precipitation, the inspectors determined the licensee was adequately
maintaining meteorological monitoring equipment and that the
49
meteorological monitoring program had been adequately implemented.
c. Conclusions
Based on the above reviews and observations, it was concluded that the
meteorological instrumentation had been adequately maintained and that
the meteorological monitoring program had been adequately implemented.
P2
Status of EP Facilities, Equipment and Resources
P2.1 Resident Insoector Tour of the Public Document Room (PDR) (71750)
The inspectors toured the PDR located at the Oconee County Public
Library. 501 W. South Broad Street, Walhalla. S.C., 29691. Required
equipment and files were in good working order.
The inspectors verified
the condition of the equipment and files (on microfiche) by viewing and
printing pages from inspection reports and correspondence.
V. Management Meetings
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee
management on August 20 and September 4, 1998, and at the conclusion of
the inspection on September 10. 1998.
The licensee acknowledged the
findings.presented. No proprietary information was identified to the
inspectors.
Partial-List of Persons Contacted
Licensee
L. Azzerello. Mechanical Systems/Equipment Engineering Manager
E. Burchfield, Regulatory Compliance Manager
T. Coutu, Nuclear Support Section Manager
T. Curtis. Superintendent of Operations
G. Davenport, Operations Support Manager
B. Dobson, Engineering Work Control Manager
J. Forbes, Station Manager
W. Foster, Safety Assurance Manager
T. Hartis, Strategic Business Consultant
D. Hubbard, Engineering Modifications Manager
C. Little, Electrical System/Equipment Engineering Manager
W. McCollum, Site Vice.President. Oconee Nuclear Station
B. Medlin, Superintendent of Maintenance
M. Nazar, Manager of Engineering
J. Smith. Regulatory Compliance
J. Twiggs. Radiation Protection Manager
Other licensee employees contacted during the inspection included engineers,
operators, technicians, maintenance personnel, and administrative personnel.
50
NRC
D. LaBarge, Project Manager
Inspection Procedures Used
Engineering
Onsite Engineering
Effectiveness of Licensee Controls In Identifying and Preventing
Problems
Surveillance Observationis
Maintenance Observations
Plant Operations.
Plant Support Activities
Inservice Inspection
Radioactive Waste Treatment, and Effluent and Environmental
Monitoring
Solid radioactive Waste Management and Transportation of
Radioactive Materials
In-Office Review of Written Reports of Nonroutine Events at Power
Reactor Facilities
Onsite Followup of Written Event Reports
Followup - Plant Operations
Followup - Maintenance
Followup - Engineering
Items Opened, Closed, and Discussed
Oened
50-269.270,287/98-08-01
Configuration Control of the Station
ASW Pump (Section M1.2)
50-269.270.287/98-08-02
Inadequate 50.59 Safety Evaluation
for 1996 UFSAR Revision Related to
ECCS Pumps" NPSH Analysis (Section
E1.4)
50-269.270.287/98-08-03
Failure to Monitor the Performance
of Manual Caustic Injection Valves
(Secti-on E8.1)
50-269,270.287/98-08-04
Improper Design Basis Assumptions
for HPI Valves (Section E8.5)
50-269.270,287/98-08-05
IFI
EFW Potential Design Basis Issues
(Section E8.1)
Closed
50-269.270,287/95-03-01
IFI
Clarification of TS 3.3.1 (Section
W
08.1)
50-269/90-15
LER
Unit Operation In an Unanalyzed
Condition Due to Design Deficiency.
Design Oversight (Section 08.1)
50-269.270,287/97-05-02
Failure to Maintain Configuration
Control (Section 08.2)
50-269.287/97-15-01
Failure to Complete Required TS
-
Surveillance on .LPI Flow Instruments
.
(Section 08.3)
50-269/97-09-00
LER
LPI Flow Instrument TS Surveillance
Interval Exceeded Due to Deficient
Work Practices (Section 08.3)
EA 96-478-01014
Failure to Properly Install MSSV
Spindle Nut Cotter Pins (Section
08.4)
50-269/97-08-00
LER
Manual Reactor Trip Due to .Equipment
Failure While Shutdown (Section
08.5)
50-270/97-02-00
LER
Grid Disturbance Results in Reactor
Trip Due to Manufacturing Deficiency
(Section 08.6)
EA 97-298-04014
Failure to Follow Operations
Procedures Relating to Low
Temperature Overpressure Protection
Requirements (Section 08.7)
EA 97-298-03014
Failure to Follow Operations
Procedure During the Unit 3 Cooldown
on May 3. 1997 (Section 08.7)
EA 97-298-05014
Failure to Follow Maintenance
Procedures for the Installation of
Tubing (Section 08.7)
50-287/97-03-00
LER
HPI System Inoperable Due to Design
Deficiency and Improper Work
Practices (Section 08.7)
50-269/97-11-00
LER
Steam Generator Leak Results in TS
Unit Shutdown Due to Inadequate
Process. Control (Section M8.1)
50-270/98-01-00
LER
Operation with Steam Generator Tube
Indications in Excess of Limits Due
to Manufacturing Error (Section
M8.2)
52
50-287/97-02-00
LER
Reactor Building Cooling Units
Technically Inoperable (Section.
M8.3)
50-287/97-02-01
LER
Reactor Building Cooling Units
Technically Inoperable Due to a
Manufacturing Deficiency (Section
M8.3)
50-269.270/97-01-01
IFI
Reactor Trip Confirm Circuit Fuse
(Section E8.4)
50-269/98-02-09
Failure of Valve 1HP-27 to Close
(Section E8.5)
.50-269/98-05-01
LER
Valve Fails to Close Requiring Unit
Shutdown Due to Inadequate Procedure
(Section E8.5)
50-269/98-05-00
LER
Valve Fails to Close Requiring Unit
Shutdown (SectiorrE8.5)
Discussed
50-269.270.287/98-03-09
Licensing Basis Issues With Single
Failure and QA for Non-Safety
Equipment Required to Mitigate an
Accident (Section E8.1)
50-269.270.287/98-03-07
Incorrect and Nonconservative
Assumptions in Control Room Operator
Dose Calculations (Section E8.2)
50-269.270.287/98-03-02
Failure to Perform PRVS Surveillance
in Accordance With TS (Section E8.3)
50-269/98-01
LER
Available NPSH for RBS Pumps Outside
Design Basis Due to Incorrect
Interpretation (Section E1.4)
50-269/97-02
LER
Reactor Building Cooling Units
Technically Inoperable Due to Design
Deficiency (Section 01.4)
50-269/97-02-01
LER
Reactor Building Cooling Units
Technically Inoperable Due to Design
Deficiency (Section 01.5)
50-270/98-06-00
LER
ESV (2 Trains) Inoperable (Section
01.5)
53
50-269/98-11-00
LER
Available NPSH for RBS Pumps Outside
Design Basis Due to Incorrect
Interpretation (Section E1.4)
List of Acronyms
AFC
Auxiliary Fan Coolers
As Low As Reasonably Achievable
American Society of Mechanical Engineers
ASW
Auxiliary Service Water
Anticipated TransientWithout Scram
BWST
Borated Water Storage Tank
Cubic Feet Per Minute
CFR
Code of Federal Regulations
Control Room Ventilation System
DEA
Decontamination Emergency Area
DSCS
Double Seal Delta Channel Seal
Emergency Core Cooling Systems
Emergency Feedwater.
End-of-Cycle
Emergency Operating Procedure
Environmental Qualification
Engineered Safeguards
Engineered Safety Feature
ESV
Essential Siphon Vacuum
F
Fahrenheit
Failure Identification Process
GL
Generic Letter
GPM
Gallons Per Minute
High Pressure Injection
I&E
Instrument & Electrical
IFI
Inspector Followup Item
INOT
Independent Nuclear Oversight Team
IP
Inspection Procedure
IR
Inspection Report
Inservice Inspection
In-Service Testing
LER
Licensee Event Report
LCO
Limiting Condition for Operation
Loss of Coolant Accident
Low Pressure Injection
Low Pressure Service Water
LSE
Less Significant Event
Motor Operated Valve
MSE
More Significant Event
Non-Cited Violation
Net Positive Suction Head
NRC
Nuclear Regulatory Commission
NSD
Nuclear System Directive
NSM
Nuclear Station Modification
Once Through Steam Generator
54
OSRDC
Oconee Safety-Related Designation Clarification Program
PALS
Post Accident Liquid Sampling System
Public Document Room
Problem Investigation Process
Preventive Maintenance
ppb
Parts per Billion
Probablistic Risk Assessment
PRVS
Penetration Room Ventilation System
psig
Pounds Per Square Inch Gauge
Performance Test
Quality Assurance
Reactor Building
RBCU
Reactor Building Cooling Unit
Reactor Building Spray
Reactor Coolant Pump
Regulatory Guide
Systematic Assessment of Licensee Performance
Shutdown
Selected Licensee Commitments
SRG
Safety Review Group
Seismic Qualification Utility Group
Systems. Structures. and Components
SSEA
Safety System Engineering Audit
SSF
Standby Shutdown Facility
Safety System Functional Inspection
Technical Assignment Control
Thermoluminescent Dosimetry
TS
Technical Specification
Updated Final Safety Analysis Report
-
Unresolved Item
Unreviewed Safety Question
UST
Upper Storage Tank
Ultrasonic Examination.
Violation
w.g.
Water Gauge
Work Order