ML14181A959
| ML14181A959 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 11/07/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML14181A958 | List: |
| References | |
| 50-261-97-10, NUDOCS 9711190135 | |
| Download: ML14181A959 (22) | |
See also: IR 05000261/1997010
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-261
License Nos:
Report No:
50-261/97-10
Licensee:
Carolina Power & Light (CP&L)
Facility:
H. B. Robinson Unit 2
Location:
3581 West Entrance Road
Hartsville, SC 29550
Dates:
August 31 - October 11, 1997
Inspectors:
B. Desai, Senior Resident Inspector
J. Zeiler, Resident Inspector
Approved by:
M. Shymlock, Chief, Projects Branch 4
Division of Reactor.Projects
9711190135 971107
ADOCK 05000261
0
EXECUTIVE SUMMARY
H. B. Robinson Power Plant, Unit 2
NRC Inspection Report 50-261/97-10
This integrated inspection included aspects of licensee operations,
maintenance, engineering, and plant support. The report covers a six-week
period of resident inspection.
Operations
The conduct of operations was professional and safety-conscious
(Section 01.1).
Overall, control room operator logs were appropriately maintained;
however, one instance was noted where the status of a seismic monitor
was not appropriately logged. The safety significance of this was
minimal (Section 01.2).
Licensee actions following the receipt of Loose Part Monitoring System
(LPMS) alarms on Steam Generator A were responsive, thorough, and
indicative of strong management attention. Although the source of the
LPMS noise had not been positively identified by the end of the report
period, licensee troubleshooting plans were detailed and exhaustive.
Inconsistencies were identified in the licensee's implementation of
Regulatory Guide testing commitments and vendor recommended maintenance
related to the LPMS. An Unresolved Item (URI) was identified to
complete the review of these issues (Section 01.3).
A walkdown of the electrical distribution system did not result in any
significant problems being identified. A walkdown of the Control Room
Ventilation System revealed that the system was being operated in
accordance with system lineup procedures and the description in the
Updated Final Safety Analysis Report (UFSAR). The system was being
properly maintained for system readiness to perform its safety function
and Technical Specification (TS) surveillance requirements were met
(Section 02.1 and 02.2).
The onsite review functions of the Plant Nuclear Safety Committee (PNSC)
were conducted in accordance with TSs. PNSC meetings continued to be
well coordinated and meetings topics were thoroughly discussed and
evaluated. Likewise, the Nuclear Assessment Section (NAS) continued to
provide strong oversight of licensee activities. A negative observation
was identified associated with an error in classifying the significance
level of a Condition Report involving an issue that was reported to the
NRC under 10 CFR 50.72. This resulted in the NRC reportable event not
being reviewed by the PNSC and NAS. This error was considered to be an
isolated incident and had no safety consequence (Section 07.1).
An apparent violation was identified for the licensee's failure to
implement adequate configuration controls for positioning the Emergency
Diesel Generator (EDG) output breaker control switch. Associated with
this same incident, an apparent violation was identified for the failure
to identify and correct the mispositioned B EDG output breaker control
2
switch prior to identification by the NRC. This mispositioning issue
was originally identified as an URI in NRC Inspection Report 50-261/
97-09 (Section 08.1).
Maintenance
Observed maintenance and surveillance activities were performed
satisfactorily (Section M1.1).
The licensee's process for incorporating Probabilistic Safety Assessment
and Probabilistic Risk Assessment information in the planning of online
maintenance activities was considered a strength (Section M1.2).
Engineering
A spent fuel pool anti-siphon modification was properly implemented,
including the 10 CFR 50.59 evaluation, UFSAR updates, and post
modification testing. This modification further enhances plant safety,
in that, it eliminated the potential for a siphon induced draindown of
the spent fuel pool (Section E1.1).
Licensee management asked probing questions during maintenance rule
system review meetings that were recently initiated. The reviews
sensitized appropriate managers to the problems related to the discussed
systems. The overall impact of this initiative should result in better
focus and management of problems related to plant systems (Section
E2.1).
The licensee's actions upon discovery of a Unreviewed Safety Question
(USQ) associated with certain spent fuel shipping activities were
appropriate. The failure to meet 10 CFR 50.59 requirements for
performing a change involving a USQ without prior NRC approval was
identified as an Apparent Violation of 10 CFR 50.59. As described in
the cover letter to this report, this apparent violation will be
reviewed by NRC management and addressed in a separate correspondence
(Section E2.2).
The failure to provide adequate design controls related to alterations
and repairs to the Emergency Core Cooling System recirculation sump
screens was identified as a Non-Cited Violation of 10 CFR 50, Appendix
B. Criterion III, Design Control. This issue was originally identified
as a URI in NRC Inspection Report 50-261/96-12 (Section E8.1).
Plant Support
The licensee's corrective actions for problems related to personnel
entering the Radiation Control Area without appropriate monitoring was
considered aggressive (Section R1.2).
The licensee's efforts to provide the security force with an upgraded
firing range training facility was indicative of good management support
to further enhance security personnel performance (Section S1.2).
Report Details
Summary of Plant Status
Robinson Unit 2 operated at full power for the entire report period with the
following exception. On September 6-7, power was reduced to approximately 65
percent to conduct testing of the turbine control valves.
I. Operations
01
Conduct of Operations
01.1 General Comments (71707)
The inspectors conducted frequent control room tours to verify proper
staffing, operator attentiveness and communications, and adherence to
approved procedures. The inspectors attended daily operation turnovers,
management reviews, and plan-of-the-day meetings to maintain awareness
of overall plant operations. Operator logs were reviewed to verify
operational safety and compliance with Technical Specifications (TSs).
Instrumentation, computer indications, and safety system lineups were
periodically reviewed from the Control Room to assess operability.
Frequent plant tours were conducted to observe equipment status and
housekeeping. Condition Reports (CRs) were routinely reviewed to assure
that potential safety concerns and equipment problems were reported and
resolved.
In general, the conduct of operations was professional and safety
conscious. Good plant equipment material conditions and housekeeping
continued to be observed throughout the report period.
01.2 Control Room Logging
a. Inspection Scope (71707)
The inspector reviewed control room logs, as well as other control room
documents to ascertain whether plant conditions, TS action statements,
equipment out-of-service. etc.. were appropriately documented.
b. Observations and Findings
The inspector noted that, overall, the detail and quality of control
room logs was good. However, the inspector did identify one instance
where a seismic monitor was still carried as being out-of-service when
it had actually been successfully returned to operable status, including
completion of required tests. Upon pointing this out to the operator,
the operator immediately rectified the documentation.
c. Conclusions
The inspector concluded that the overall control room logs were
appropriately maintained; however, one instance was noted where the
status of a seismic monitor was not appropriately logged. The safety
significance of this logging error was minimal.
2
01.3 -Potential Loose Part Evaluation for Steam Generator A
a. Inspection Scope (71707)
The inspector reviewed licensee activities associated with an evaluation
of a potential loose part in Steam Generator (SG) A.following alarms on
the Loose Parts Monitoring System (LPMS). The inspector reviewed the
LPMS vendor manual, operating and maintenance procedures, UFSAR Section
1.8, and Regulatory Guide (RG) 1.133, Loose Parts Detection Program for
the Primary System of Light Water Cooled Reactors.
b. Observations and Findings
On September 23, 1997, the licensee initiated an evaluation for a
potential loose part in SG A following the receipt of alarms on LPMS
channel 755. Channel 755 is associated with loose parts monitoring of
the secondary side of SG A. During normal operation, the LPMS is
configured to monitor the primary side channels for' each SG. LPMS
Channel 754 monitors noise on the primary side of SG A. Up until
September 23, channel 754 had been selected for automatic loose parts
monitoring of SG A, and although a slight increase in the number of
impact events below the alarm setpoint had been noticed, no alarms had
been received on channel 754.
Between September 23 and 25, 1997, the licensee worked with Westinghouse
Corporation in analyzing the LPMS output data from channels 755 and 754.
The results of this evaluation were documented in Westinghouse letter
dated September 25, 1997. Westinghouse determined that the source of
the impact events was not in the SG tube sheet region, and was most
likely, outside of the generator. The licensee's subsequent
troubleshooting and investigations narrowed the source of the noise to
be somewhere between the upper region of the generator to 50 feet
upstream of the feedwater inlet line from the generator. The inspector
noted that investigation efforts were well planned and exhaustive. At
the end of the report period, licensee investigations into the source of
the noise were still ongoing. The inspector determined that the
licensee had adequately evaluated the potential for a loose part in
SG A.
The inspector reviewed Operating Procedure (OP)-007, Loose Parts
Monitoring System, the Digital Metal Impact Monitoring System Vendor
Manual (CP&L Part No. 728-564-04), RG 1.133. and UFSAR Section 1.8
related to the licensee's conformance to RG 1.133. UFSAR Section 1.8
indicated that the LPMS at Robinson conformed to RG 1.133, revision 1,
dated May 1981, with the exception of sections C.1.g and C.1.h. Based
on a review of OP-007, the inspector determined that for the most part,
the licensee had implemented a loose part detection program in
accordance with RG 1.133. However, the inspector identified several
areas that did not appear to meet the RG 1.133 commitments related to
LPMS testing. Specifically, RG 1.133 Section C.3 required the
performance of a 31-day channel functional tests and 92-day background
noise and channel false signal checks. Based on review of OP-007, the
3
inspector was unable to verify whether these tests were being
accomplished. However, the LPMS vendor manual described certain tests
that the system hardware conducts automatically. At the end of the
report period, the inspector had been unable to positively confirm
whether all of the above RG 1.133 testing was included in the automatic
test features. The inspector determined that further review of the LPMS
system was necessary to conclude whether all RG 1.133 test commitments
were being conducted.
Also, the inspector noted that OP-007 only required an audible check of
the LPMS channels that were not selected for automatic monitoring.
These non-selected channels included the secondary side of the SGs,
including channel 755 for SG A. Had more than just audible checks been
performed, the licensee may have identified the change in channel 755
noise earlier.
The inspector also noted that the vendor manual recommended that the
LPMS backup battery be replaced every 6-months, however, the licensee
was replacing the battery at 18-month intervals. At the end of the
report period, the inspector was still reviewing with the licensee the
impact of the increased battery replacement schedule.
The licensee initiated a CR to review the above mentioned testing and
maintenance issues, as well as their verification of commitments
associated with RG 1.133. Pending completion of the licensee's review
of these items and subsequent review by the NRC, these issues were
identified as Unresolved Item (URI) 50-261/97-10-01: Complete Review of
LPMS Testing and Maintenance Activities.
c. Conclusions
The inspector concluded that licensee actions following the receipt of
LPMS alarms on SG A were responsive, thorough, and indicative of strong
management attention. Although the source of the LPMS noise had not
been positively identified by the end of the report period, licensee
troubleshooting plans were detailed and exhaustive. The inspector
identified weaknesses in the licensee's implementation of Regulatory
Guide LPMS testing commitments and vendor recommended LPMS maintenance.
An URI was identified to complete the review of these items.
02
Operational Status of Facilities and Equipment
02.1 Walkdown of Electrical Distribution System
a. Inspection Scope (71707)
The inspector performed a walkdown of portions of the electrical
distribution system.
4
b. Observations and Findings
The inspector verified the electrical distribution system was aligned in
accordance with OP-603, Electrical Distribution System Lineup. The as
built configuration was compared with the description of the electrical
system in Chapter 8 of the UFSAR. The inspector did not identify any
configuration or housekeeping issues. The inspector did note that the
labeling on the Motor Control Center panels for each breaker indicated
ON or OFF whereas OP-603 described breaker positions as Closed or Open.
This comment was passed on to the licensee.
c. Conclusions
The inspector did not identify any significant problems during the
walkdown of portions of the electrical distribution system..
02.2 Walkdown of Control Room Ventilation System
a. Inspection Scope (71707)
The inspector performed a walkdown of accessible, safety-related
portions of the Control Room Ventilation System (CRVS). The actual
plant configuration was compared with plant drawings, system lineup
procedures, as well as the UFSAR system description and drawings.
Additionally, completed surveillance test procedures and the status of
outstanding maintenance associated with the CRVS were reviewed.
b. Observations and Findings
The inspector verified that the actual plant configuration and operation
of the CRVS was consistent with the plant flow diagram G-190304,
Revision 5, operations lineup procedure OP-906, and the UFSAR Chapter
9.4 description and diagram. No discrepancies were identified from this
review.
The inspector verified that TS 4.15 surveillance requirements associated
with the CRVS were being performed as required via review of various
test procedures. These procedures included the following:
Operations Surveillance Test (OST)-750-1, Control Room Emergency
Ventilation System Train A (Monthly), Revision 6,
OST-750-2, Control Room Emergency Ventilation System Train B
(Monthly), Revision 6,
Engineering Surveillance Test (EST)-023, Control Room Emergency
Ventilation System (18 Month). Revision 13.
Additionally, the inspector reviewed the last completed performance of
the above procedures to verify that performance acceptance criteria were
met and the surveillances were performed at the proper frequency. No
discrepancies were identified from these reviews.
5
The inspector reviewed all open work items associated with the CRVS.
The inspector did not identify any outstanding work that could impact
the readiness of the system to properly perform its function.
c. Conclusions
The inspector concluded that the CRVS was being operated in accordance
with system lineup and system description in the UFSAR, was being tested
in accordance with TS surveillance requirements, and, was being properly
maintained for system readiness to perform its safety function.
07
Quality Assurance In Operations
07.1 Plant Nuclear Safety Committee and Nuclear Assessment Section Oversight
a. Inspection Scope (40500)
The inspector evaluated certain activities of the Plant Nuclear Safety
Committee (PNSC) and Nuclear Assessment Section (NAS) to determine
whether the onsite review functions were conducted in accordance with TS
and other regulatory requirements.
b. Observations and Findings
The inspector periodically attended PNSC meetings during the report
period. The presentations were thorough and the presenters readily
responded to all questions. The committee members asked probing
questions and were well prepared. The committee members displayed
understanding of the issues and potential risks. Further, the inspector
reviewed NAS audits and concluded that they were appropriately focused
to identify and enhance safety.
The inspector reviewed the implementation of PNSC and NAS activities
related to the requirements of TS 6.6.1.a. This TS required the PNSC to
review all NRC reportable events (i.e., 10 CFR 50.72 and 50.73) and
submit the event to the NAS Manager. The .inspector reviewed reportable
events initiated by the licensee in 1996 and 1997. With one exception,
the inspector determined that the PNSC and NAS reviews were completed as
required. The exception involved the licensee's NRC 10 CFR 50.72
notification on August 12, 1996., related to a "courtesy" offsite
notification that had been made to the South Carolina Department of
Health and Environmental Control concerning potential leakage from a
diesel fuel oil storage tank. This issue was documented by the licensee
in CR 96-1803. The CR was not reviewed by the PNSC and NAS due to the
CR evaluator classifying the CR as a Level 3, Non-Significant issue.
This CR should have been classified as Level 1, Significant. All CRs
classified as significant are automatically reviewed by the PNSC and
NAS. The licensee initiated a CR to address the error and on
October 13, 1997. the PNSC reviewed CR 96-1803 as part of a regularly
scheduled meeting. The inspector concluded that the licensee's program
for PNSC and NAS review of NRC reportable events was properly
6
implemented and the discrepancy with CR 96-1803 was an isolated.case of
an error in CR classification and had no safety consequence.
c. Conclusions
The inspector concluded that the onsite review functions of the PNSC
were conducted in accordance with TSs. The PNSC meetings attended by
the inspector were well coordinated and meetings topics were thoroughly
discussed and evaluated. NAS continued to provide strong oversight of
licensee activities. A negative observation was identified associated
with an error in classifying the significance level of a CR involving an
NRC reportable event. This resulted in the event not being reviewed by
the PNSC and NAS. This error was considered to be an isolated incident.
08
Miscellaneous Operations Issues (92901)
08.1 (Closed) URI 50-261/97-09-01, Review Licensee Evaluation of EDG Output
Breaker Control Switch Mispositioning: This URI involved the
inspector's identification of the B Emergency Diesel Generator (EDG)
output breaker control switch in the partial PULL-OUT (i.e., pull-to
lock) position rather than the NEUTRAL (i.e., normal) position on
August 20, 1997. The licensee later determined that, with the switch in
this position, the B EDG output breaker would have immediately reopened
following closure, in the event of an EDG start and undervoltage
condition on the E-2 Emergency Bus. As a result, the B EDG was
incapable of automatically energizing the E-2 Emergency Bus, and was
therefore, inoperable.
During this report period, the inspector reviewed the results of the
licensee's Event Review Team that was assembled to investigate the
circumstances related to the cause of the switch mispositioning. The
results of this investigation were documented in CR 97-01754 and
Licensee Event Report (LER) 50-261/97-10-00, dated September 12, 1997.
The licensee was unable to identify the exact time and circumstance
related to the output breaker control switch mispositioning. Several
scenarios that could have resulted in the mispositioning were examined
in detail.
These scenarios included the following: (1)
the switch was
over-rotated past the TRIP position when the output breaker was manually
tripped during the July 28, 1997, routine EDG surveillance test, (2)
the
switch was inadvertently manipulated, i.e.. bumped, and (3)
the switch
was intentionally mispositioned. The results of licensee's
investigations determined that, most likely. the switch was
inadvertently bumped sometime after 4:12 p.m. on August 16, 1997.
However, no specific activity could be identified that might have
resulted in the actual mispositioning.
As a result of the licensee's interviews with personnel that had
recently been in the EDG room, a Shift Superintendent of Operations
(SSO) recalled observing that the switch was in its proper position on
August 16 during a routine walkdown in the Auxiliary Building. Security
logs for that day confirmed that the individual had last exited the
Auxiliary Building at 4:12 p.m. The licensee believed that the switch
.7
was mispositioned sometime after 4:12 p.m. on August 16, 1997. Based on
this, the licensee concluded that the B EDG was potentially inoperable
from 4:12 p.m. on August 16, 1997 until the output breaker control
switch was returned to its normal position at 3:44 p.m. on August 20,
1997.
While the exact root cause of this switch mispositioning could not be
determined, the Event Review Team identified several weaknesses in the
physical and administrative barriers that could have either prevented
the switch mispositioning or alerted personnel earlier to the
mispositioning. These weaknesses included the following: 1) the proper
switch position was not being verified periodically during routine
operator rounds nor after switch manipulations following the quarterly
EDG surveillance test; 2) protective covers were not installed to
prevent the inadvertent bumping of the switch, even though a similar
mispositioning involving the EDG voltage control knobs had occurred in
1993; and, 3) the EDG control circuitry was not designed with alarms or
indications that would have alerted personnel that the switch had been
mispositioned.
The licensee's planned corrective actions included the
installation of protective covers on both EDG generator control panels
to prevent the switches from being bumped in the future. In addition,
caution tags were placed on both switches until operating lineup and
testing procedures were revised to include verifications of the proper
switch position, both periodically and after manipulation during the
quarterly EDG test.
The licensee completed a safety review that considered the B EDG
inoperable from 4:12 p.m. on August 16, 1997 until 3:44 p.m. on
August 20, 1997. During this period, several A train safety'-related
equipment/components were removed from service for maintenance. As
defined by TS 1.3, when a system, subsystem, train, component or device
is determined to be inoperable solely because its emergency power source
is inoperable, or solely because it normal power source is inoperable,
it may be considered operable provided its.emergency power source is
operable and all of its redundant systems, subsystems, trains,
components and devices are operable. Based on this definition of
operability, while the A train equipment was out of service for
maintenance, concurrent with the inoperability of the B train emergency
power, the A train equipment was considered inoperable. Therefore, this
condition resulted in both trains of equipment being inoperable due to
the equipment's opposite train emergency power source being inoperable.
The A train equipment removed from service and its associated risk
significance included the following:
A Train Engineered Safety Features Actuation System (ESFAS):
Between 7:51 p.m. and 9:17 p.m. on August 17, 1997, A train ESFAS
testing was conducted. When each individual A train ESFAS logic
function was momentarily placed in test, this resulted in both ESF
trains being inoperable since the emergency power source for. B
train was inoperable. However, both trains of ESFAS would have
still operated properly since it is powered from the A and B train
125 Volt DC vital batteries which remained operable during the
8
timeframe. Therefore, the risk significance of this condition was
minimal since there was no actual loss of ESFAS capability.
A Train Vital Battery:
For approximately six minutes, while
swapping from the A-1 Vital Emergency Battery Charger to the A
charger on August 18, 1997, both vital battery chargers were
considered inoperable. The risk significance of this condition
was minimal since both trains of vital batteries were still
operable during this short time period.
Steam Driven Auxiliary Feedwater (SDAFW) Pump:
On August 20,
1997, at 3:44 a.m., the SDAFW pump discharge flow control valve
was cycled to support scheduled surveillance testing. During this
short period (i.e., two minutes), the SDAFW pump was inoperable,
concurrent with the inoperability of the B Motor Driven AFW
(MDAFW) pump due to its emergency power supply being unavailable.
The licensee determined that the inoperability of the SDAFW and
one MDAFW resulted in the highest increase in instantaneous core
damage frequency (i.e., from 2E-4 to 1E-3). However, the A train
MDAFW pump remained operable during this period. The risk
significance of this condition was still considered minimal since
one MDAFW pump can supply sufficient feedwater for decay heat
removal during design basis accident conditions.
A Train ECCS Pump Room Cooler:
On August 20, 1997, at 5:30 a.m.,
the A train Safety Injection (SI) and Containment.Spray (CS) pumps
were declared inoperable by the licensee due to scheduled
maintenance on HVH-6A, the A train SI pump room air cooler. This
maintenance involved replacement of two service water supply
valves to HVH-6A. Since the B train emergency power supply source
was inoperable due to the output breaker control switch
mispositioning, the B train ECCS room cooler, HVH-6B, was also
technically inoperable. This resulted in both trains of SI and CS
being inoperable. On August 20, 1997, at 6:39 p.m., work was
completed on HVH-6A and it was returned to service. The actual
risk significance of this condition while both room coolers were
inoperable was considered to be minimal.
The licensee had
previously calculated that all safety-related equipment, including
the SI and CS pumps in the ECCS pump room, could still perform
their design function without HVH-6A and HVH-6B in operation. In
addition, work on HVH-6A could have been expedited to return it to
service sooner if this had been necessary.
The inspector determined that between 5:30 a.m. and 3:44 p.m. on
August 20, 1997, the plant had been in the action requirement of TS 3.0
as a result of having both the A and B train SI and CS pumps inoperable.
TS 3.0 required that the plant be placed in Hot Shutdown within eight
hours. This required the licensee to have placed the plant in Hot
Shutdown by 1:30 p.m. on August 20, 1997. Since the B EDG was not
returned to service until 3:44 p.m., the allowable TS 3.0 time to Hot
Shutdown was exceeded.
9
10 CFR 50, Appendix B, Criterion II, "Quality Assurance Program,"
requires., in part, that the quality assurance program shall provide
control over activities affecting the quality of systems and components,
to an extent consistent with their importance to safety.
The licensee's quality assurance program did not provide controls over
activities affecting the quality of systems and components, to an extent
consistent with their importance to safety. Specifically, the licensee
failed to assure adequate configuration control of the position of the B
EDG output breaker control switch. This resulted in the inoperability
of the EDG from potentially August 16 until August 20, 1997, due to the
inadvertent mispositioning of the switch. Controls for ensuring that
the switch could not be inadvertently "bumped" were not implemented,
e.g., switch protection covers, etc. Existing procedures did not
require verifications that the switch was in its correct position
following switch manipulations for quarterly EDG testing, nor
periodically during routine operator walkdowns. Additionally, the EDG
control system was not designed with positive controls, e.g., alarms, to
indicate that the switch was not in its correct position.
This issue is identified as an apparent violation of 10 CFR 50, Appendix
B, Criterion II. This issue is identified as Escalated Enforcement Item
(EEI) 50-261/97-10-02: Apparent Violation of 10 CFR 50, Appendix B,
Criterion II,
for Mispositioned EDG Switch.
In addition, 10 CFR 50, Appendix B, Criterion XVI, "Corrective Action,"
requires, in part, that measures shall be established to assure that
conditions adverse to quality, such as failures, malfunctions,
deficiencies, deviations, defective material and equipment, and
nonconformances are promptly identified and corrected.
As of August 20, 1997, the licensee did not establish measures to assure
that conditions adverse to quality were promptly identified and
corrected. Specifically, the licensee failed to identify and correct
that the B EDG output breaker control switch was mispositioned from
potentially August 16, 1997, when the switch was last observed by an SSO
to be in its correct position, until August 20, 1997, when the switch
was found mispositioned by the inspector. The licensee's failure to
identify and correct the mispositioned switch prior to identification by
the NRC, is considered to be an Apparent Violation of 10 CFR 50,
Appendix B, Criterion XVI, Corrective Actions. This issue is identified
- as EEI 50-261/97-10-03: Apparent Violation of 10 CFR 50, Appendix B,
Criterion XVI, for Mispositioned EDG Switch.
10
II.
Maintenance
M1
Conduct of Maintenance
M1.1 General Comments
a. Inspection Scope (61726 and 62707) (92902)
The inspector reviewed/observed all or portions of the following
maintenance related work requests/job orders (WRs/J~s) and surveillances
and reviewed the associated documentation:
WR/JO AHGX-002
Perform Capacity Test of Station Battery A-i
WR/JO AARL-002
Motor Driven Auxiliary Feedwater System (MDAFW)
Pump Oil Cooler Maintenance
WR/JO 97-AEJUl
HVH-6B Repairs
OST 201-A
MDAFW Component Test - Train A
OST 251-1 and 2 Residual Heat Removal Pump A Component Test
OST 401-2
EDG B Slow Speed Start
OST 402-2
EDG B Diesel Fuel Oil System Flow Test
b. Observations and Findings
The inspector observed that these activities were performed by personnel
who were experienced and knowledgeable of their assigned tasks.
Procedures were present at the work location and being followed.
Procedures provided sufficient detail and guidance for the intended
activities. Activities were properly authorized and coordinated with
operations prior to starting. Test and maintenance equipment in use was
calibrated, procedure prerequisites were met, and system restoration was
completed. The inspector verified that the surveillance tests were
performed within their required frequencies, associated documentation
was found satisfactory, and test results met acceptance criteria
contained in the procedure.
c. Conclusions
The inspector concluded that maintenance and surveillance activities
were performed satisfactorily.
M1.2
Maintenance Planning
a. Inspection Scope (62707)
The inspector reviewed the licensee's process forutilizing
Probabilistic Safety Assessment (PSA) and Probabilistic Risk Assessment
(PRA) information in the scheduling of maintenance activities.
b. Observations and Findings
The inspector reviewed the licensee's process for incorporating PSA/PRA
information into the scheduling of planned, as well as unplanned
activities, including on-line maintenance activities. Plant procedure
(PLP)-056, Work Control Process, implements licensee expectations to
assess the impact on overall plant safety when plant equipment or
combinations of equipment are removed from service for on-line
maintenance. This procedure identifies the risk impact of various
combinations of equipment safety functions that are planned to be
unavailable and provides a risk matrix that recommends what activities
can or cannot be performed from a risk stand point.
Additionally, the inspector reviewed a new initiative by the licensee
that identifies the increase in risk from the base core damage frequency
for planned maintenance in the upcoming two weeks. This information is
presented in a user friendly way and is prominently displayed at various
locations.
c. Conclusions
The inspector concluded that the licensee's process for incorporating
PSA/PRA information in the planning of online maintenance activities was
considered a strength.
III. Engineering
El
Conduct of Engineering
E1.1
Spent Fuel Anti-Siphon Modification
a. Inspection Scope (37551)
The inspector reviewed modification package Engineering Service Request
(ESR) 9700018, Spent Fuel Pool Cooling System (SFPCS) Anti-Siphon
Modification, as well as the field installation of the modification.
b. Observations and Findings
ESR 9700018 was initiated by the licensee to address a concern related
to the existence of a drain line at Robinson that extends to near the
bottom of the SFP, without any passive engineered anti-siphon device.
Two locked closed manual isolation valves provided protection against an
inadvertent draindown. However, in the absence of an engineered
anti-siphon protection, the NRC had expressed concern to the licensee,
including the potential of considering Backfit (NRC to CP&L letter dated
October, 10, 1996). While Robinson was in compliance with its licensing
basis, the lack of an engineered anti-siphon protection did not conform
to current standards.
12
The anti-siphon modification included the installation of a spectacle
flange on the four-inch line between the two closed isolation valves.
The licensee opted for this solution since the majority of the drain
line was embedded in concrete, thus disallowing the installation for a
siphon-breaking vent hole on the drain line. In addition to the flange,
the licensee plans to continue to maintain the two isolation valves in
the closed position.
c. Conclusions
The inspector concluded that the modification was appropriately
accomplished, including the 10 CFR 50.59 evaluation, UFSAR updates, and
post modification testing. The installation of this modification
further enhanced plant safety by eliminating the potential for a siphon
induced spent fuel pool draindown..
E2
Engineering Support of Facilities and Equipment
E2.1 Maintenance Rule Plant System Reviews
a. Inspection Scope (37551)
The inspector attended several system review meetings that were held.
This was a new licensee initiative, partly in preparation for the
upcoming maintenance rule.team inspection.
b. Observations and Findings
The system review meetings discuss outstanding WR/JOs, ESRs, pending
modifications, maintenance rule status, functional failures,
unavailability, and any other items of interest related to the system.
The system engineer is primarily the source of the information and the
meeting is typically attended by the Plant Manager, Engineering Manager,
Operations Manager, and Maintenance Manager. The current licensee focus
is on maintenance rule a(1) systems. The licensee plans to continue
this effort and not limit the review to just a(1) systems.
c. Conclusions
The inspector noted that licensee management asked appropriate questions
during the reviews. Further, the reviews sensitized appropriate
managers to the problems related to the discussed systems. The
inspector concluded that the overall impact of this initiative will
result in better focus and management of problems related to plant
systems.
13
E2.2 Unreviewed Safety Question Associated with Spent Fuel Shipping Cask
a. Inspection Scope (37551)
The inspector reviewed licensee investigation and actions related to an
Unreviewed Safety Question (USQ) that was identified by the licensee as
a result of NRC Bulletin 96-02, Movement of Heavy Loads Over Spent Fuel.
b. Observations and Findings
On December 24, 1996, the NRC requested additional information from the
licensee regarding NRC Bulletin 96-02, Movement of Heavy Loads Over
Spent Fuel, Over Fuel in the Reactor Core, or Over Safety-Related
Equipment. During CP&L's review of this request, the licensee
determined that certain spent fuel shipping cask handling activities had
been conducted outside design and licensing bases of the plant.
Specifically, at Robinson, the IF-300 spent fuel shipping cask was
configured for fuel loading by removing the cask valve box covers as
governed by procedure SFS-001, IF-300 Shipping Cask Operation. The cask
was then lifted with a non-single failure proof crane from the cask
decontamination facility to the cask rail car, where the cask valve box
covers were installed. Lifting the cask with the non-single failure
proof crane with the valve box covers removed is not covered by the
shipping configuration drop analysis. The drop analysis was applicable
for a cask drop accident from 30 feet and in a fully secured, ready for
shipment configuration.
The licensee concluded that a cask drop with the valve box covers
removed could lead to an off-site release that exceeds the "no-release"
result of a cask drop accident that is in the current licensing basis.
Specifically, an estimation of the off-site dose resulting from a cask
drop without the valve covers installed concluded that the whole body
dose would be 0.0072 rem and for the thyroid would be 0.1233 rem. This
represented a small fraction of the 10 CFR 100 limits and the acceptable
limits in the Standard Review Plan.
Consequently. CP&L stopped any further cask movement, restricted use of
procedure SFS-001, reported the condition to the NRC (10 CFR 50.72
report and LER 50-261/97-05), and, submitted the condition to the NRC on
August 28, 1997 for review after concluding the issue involved an USQ.
10 CFR 50.59 allows licensees to make changes in the facility and
governing procedures as described in the safety analysis report without
NRC approval, unless it involves an unreviewed safety question. In
addition, it requires that licensee maintain records of changes in the
facility and that these records must indicate a written safety
evaluation which provides the bases for the determination that the
change does not involve an unreviewed safety question.
Section 15.7.5, Spent Fuel Cask Drop Accidents, of the Robinson UFSAR,
states that a potential cask drop could occur while the cask is being
lifted with the non-redundant yoke between the decontamination facility
14
and the shipping railcar. The UFSAR did not discuss movement of the
cask with the valve box covers removed. Thus, movement of the cask
without the valve box covers constituted a change to the facility. The
change had not been adequately evaluated in any safety evaluation
pursuant to 10 CFR 50.59, including that associated with procedure SFS
001 prior to the NRC Bulletin 96-02 request for additional information.
Movement of the cask without the valve covers installed had occurred a
number of times at Robinson. This condition is considered an Apparent
Violation of 10 CFR 50.59 for performing a change involving an
unreviewed safety question without prior NRC approval. This issue is
identified as EEI 50-261/97-10-04: Failure to Meet 10 CFR 50.59
Requirements for USQ Related to Spent Fuel Cask Movement.
c. Conclusions
The inspector concluded that the licensee's actions upon discovery of a
USQ associated with certain spent fuel shipping activities were
appropriate. The failure to meet 10 CFR 50.59 requirements for
performing a change involving a USQ without prior NRC approval was
identified as an Apparent Violation of 10 CFR 50.59. As described in
the cover letter to this report, this apparent violation will be
reviewed by NRC management and addressed in a separate correspondence.
NRC inspection followup of your corrective actions will be tracked
during our review of LER 50-261/97-05.
E7
Quality Assurance in
Engineering Activities
E7.1 Special UFSAR Review (37551)
A recent discovery of a licensee operating their facility in a manner
contrary to the UFSAR description highlighted the need for a special
focused review that compares plant practices, procedures and/or
parameters to the UFSAR descriptions. While performing the inspections
discussed in this report, the inspector reviewed the applicable portions
of the UFSAR related to the areas inspected. The inspector verified
that for the select portions of the UFSAR reviewed, the UFSAR wording
was consistent with the observed plant practices, procedures and/or
parameters.
E8
Miscellaneous Engineering Issues (92903 and 37551)
E8.1 (Closed) URI 50-261/96-12-08, Resolution of ECCS Sump Design Issues:
This URI involved two separate parts. The first part involved the
licensee's identification of openings in the containment Emergency Core
Cooling System (ECCS) sump screens that were in excess of the 7/32 inch
screen mesh size. The inspector previously verified that appropriate
repairs had been made to the sump screens during the October 1996
refueling outage. The licensee determined the cause of the degraded
sump screen condition was the lack of adequate configuration controls.
The sump screens had been altered in the past to accommodate piping
changes through the sump. Additionally, various repairs had been made
to the sump screens over the years due to damage, tears. etc. During
these alterations and repairs, personnel failed to recognize and enforce
the design requirements and configuration control standards for.the
sump. The licensee's analysis of the impact of the degraded sump
condition determined that the openings could have allowed debris larger
than the screen design to enter the sump and ECCS recirculation
flowpath, resulting in potential clogging of some of the containment
spray system nozzles. However, the licensee concluded that there was
little likelihood that the number of nozzles clogged would impact the
available performance margin of the spray system. The inspector
previously reviewed the licensee's corrective actions for this issue
during review of LER 50-261/96-005-00 in NRC Inspection Report 50
261/97-08.
The inspector determined that the failure to provide adequate design
controls related to alterations and repairs to the ECCS sump screens was
a violation of 10 CFR 50, Appendix B, Criterion III, Design Control.
This non-repetitive, licensee-identified and corrected violation is
being treated as a Non-Cited Violation (NCV), consistent with Section
VII.B.1 of the NRC Enforcement Policy. This issue is documented as NCV
50-261/97-10-05:
Inadequate Design Controls Resulting in Degraded ECCS
Sump Screens.
The second part of this URI involved review of the licensee's evaluation
related to the impact of higher containment recirculation flood level on
the design of the ECCS sump filtration function. The UFSAR indicated
that floating and submerged debris was excluded from entering the sump
by the baffle located at the sump entrance. As a result of discovering
that the containment flood level would be higher than previously
calculated, the water level exceeded the height of this baffle wall.
The inspector reviewed ESR 9600646, dated October 13, 1996, which
examined the impact of the recirculation water level exceeding the
height of the sump baffle wall.
The licensee's evaluation results
showed that no additional floating debris would be deposited on the
screens as long as the baffle wall is higher than the top of the
screens, thus, ensuring that floating material would not be deposited on
the screens as the water level rises. This item is closed.
IV.
Plant Support
R1
Radiological Protection and Chemistry Controls
R1.1 General Comments (71750)
The inspector periodically toured the Radiological Control Area (RCA)
during the inspection period. Radiological control practices were
observed and discussed with radiological control personnel including RCA
entry and exit, survey postings, locked high radiation areas, and
radiological area material conditions. The inspector concluded that
radiation control practices were proper.
16
R1.2 New Turnstile at the Radiation Control Access Entrance
a. Inspection Scope (71750)
The licensee added a new turnstile at the RCA entrance to prevent
entries into the RCA without Electronic Dosimeter (ED).
b. Observations and Findings
The inspector documented in the recent past, several instances where
entries were made into the RCA by individuals without appropriate
electronic dose monitoring. As corrective action to preclude
recurrence, the licensee installed a turnstile at the main entrance to
the RCA. All individuals entering the RCA are now required to insert
the ED into the portal monitor. The portal monitor only allows entrance
into the RCA following confirmation that the ED has been appropriately
activated. Current licensee plans are to add approximately five of
these turnstiles at all RCA entrance points.
In addition to the turnstile, the inspector noted increased efforts on
the part of Radiation Technicians to assure that personnel entering the
RCA had reviewed applicable survey maps and Radiation Work Permits, as
well as were appropriately wearing an ED.
c. Conclusions
The inspector concluded that the licensee corrective actions resulting
from the problem related to personnel entering the RCA without
appropriate monitoring was aggressive.
S1
Conduct of Security and Safeguards Activities
S1.1 General Comments (71750)
During the period, the inspector toured the protected area and noted
that the perimeter fence was intact and not compromised by erosion nor
disrepair. Isolation zones were maintained on both sides of the barrier
and were free of objects which could shield or conceal an individual.
The inspector periodically observed personnel, packages, and vehicles
entering the protected area and verified that necessary searches,
visitor escorting, and special purpose detectors were used as applicable
prior to entry. Lighting of the perimeter and of the protected area was
acceptable and met illumination requirements.
S1.2 New Security Firing Range
a. Inspection Scope (71750)
The inspector toured the renovated/upgraded firing range that was
recently completed to train security staff at Robinson.
17
b. Observations and Findings
The inspector noted that the firing range had undergone major
renovations and repairs. The range now includes 20 foot berms, Hogans
Alley (live fire building with moving and pop-up electronic targets),
elevated shooting platform, storage building, and a classroom building.
c. Conclusions
The inspector concluded that the licensee's efforts to provide the
security force with an upgraded firing range training facility was
indicative of good management support to further enhance security
personnel performance.
V. Management Meetings
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee
management at the conclusion of the inspection on October 24, 1997. No
proprietary information was identified.
18
PARTIAL LIST OF PERSONS CONTACTED
Licensee
J. Boska, Manager, Operations
H. Chernoff, Supervisor, Licensing/Regulatory Programs
T. Cleary, Manager, Maintenance
J. Clements, Manager, Site Support Services
J. Henderson, Manager, Environmental and Radiation Controls
J. Keenan, Vice President, Robinson Nuclear Plant
R. Duncan, Manager, Robinson Engineering Support Services
R. Moore, Manager, Outage Management
J. Moyer, Manager, Robinson Plant
R. Warden, Manager, Nuclear Assessment Section
T. Wilkerson, Manager, Regulatory Affairs
D. Young, Director, Site Operations
NRC
B. Desai, Senior Resident Inspector
J. Zeiler, Resident Inspector
19
INSPECTION PROCEDURES USED
IP 37551:
Onsite Engineering
IP 40500:
Effectiveness of Licensee Controls in Identifying, Resolving, and
Preventing Problems
IP 61726:
Surveillance Observations
IP 62707:
Maintenance Observation
IP 71707:
Plant Operations
IP 71750:
Plant Support Activities
IP 92901:
Followup - Operations
IP 92903:
Followup - Engineering
IP 92902:
Followup - Maintenance
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
Type Item Number
Status
Description and Reference
50-261/97-10-01
Open
Complete Review of LPMS Testing and
Maintenance Activities (Section 01.3)
50-261/97-10-02
Open
Apparent Violation of 10 CFR 50, Appendix
B, Criterion II,
for Mispositioned EDG
Switch (Section 08.1)
50-261/97-10-03
Open
Apparent Violation of 10 CFR 50, Appendix
B, Criterion XVI
for Mispositioned EDG
Switch (Section 08.1)
EEl
50-261/97-10-04
Open
Apparent Violation of 10 CFR 50.59
Requirements for USQ Related to Spent Fuel
Cask Movement (Section E2.2)
50-261/97-10-05
Open
Inadequate Design Controls Resulting in
Degraded ECCS Sump Screens (Section E8.1)
Closed*
Type Item Number
Status
Description and Reference
50-261/97-09-01
Closed
Review Licensee Evaluation of EDG Output
Breaker Control Switch Mispositioning
(Section 08.1)
50-261/96-12-08
Closed
Resolution of ECCS Sump Design Issue
(Section E8.1)
50-261/97-10-05
Closed
Inadequate Design Controls Resulting in