ML14181A872
| ML14181A872 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 01/17/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML14181A869 | List: |
| References | |
| 50-261-96-14, NUDOCS 9702110129 | |
| Download: ML14181A872 (45) | |
See also: IR 05000261/1996014
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket No:
50-261
License No:
Report No:
50-261/96-14
Licensee:
Carolina Power & Light (CP&L)
Facility:
H. B. Robinson Unit 2
Location:
2112 Old Camden Rd.
Hartsville, SC 29550
Dates:
November 17 - December 28, 1996
Inspectors:
B. Desai, Senior Resident Inspector
J. Zeiler, Acting Senior Resident Inspector
P. Byron, Resident Inspector, Surry
F. Jape, Project Engineer, RII (Section 07.2)
G. MacDonald, Project Engineer, RII (Section
07.2)
J. Lenahan, Reactor Inspector, RII (Sections
07.2, El, E2, ES, and E7)
G. Salyers, Reactor Inspector, RII (Sections P2,
P3, P5, P6, and P7)
Approved by:
M. Shymlock, Chief, Projects Branch 4
Division of Reactor Projects
Enclosure 2
9702110129 970117
ADOCK 05000261
G
EXECUTIVE SUMMARY
H. B. Robinson Power Plant, Unit 2
NRC Inspection Report No. 50-261/96-14
This integrated inspection included aspects of licensee operations,
maintenance, engineering, and plant support. The report covers a six-week
period of inspection. In addition to inspections conducted by resident
inspectors, it includes the results of an engineering inspection conducted by
a regional inspector, an emergency preparedness inspection conducted by a
regional inspector, and, a corrective action program inspection conducted by
regional project engineers and inspectors.
Operations
Operations personnel demonstrated a heightened sensitivity to potential
hydraulic transients with the identification of a water hammer during
startup of the C Auxiliary Boiler. Engineering performed a detailed
investigation of the transient and were successful in identifying the
root cause. Licensee planned corrective actions were appropriate to
address the procedure discrepancy identified, as well as the generic
implications of other potential procedural configuration weaknesses.
The inspectors noted that continued licensee emphasis and sensitivity to
potential hydraulic transients was warranted due to past weaknesses in
this area (Section 01.2).
Operators responded appropriately-upon noting the abnormal condition
relative to water dripping into an Emergency Diesel Generator room from
a crack in the concrete roof. The licensee adequately evaluated the
safety impact of the crack on the operability of diesel generator
(Section 01.3).
A failure of an instrument air tubing caused a Feedwater Heater level
controller to fail resulting in a transient and a subsequent power
reduction. Further, it was identified that Feedwater Heater relief
valves were not in a periodic testing program. The decision to restore
the 6A Feedwater Heater to normal alignment at full power was considered
a weakness. Continued licensee attention relative to the reliability of
the Instrument Air System, as well as periodic testing of secondary
relief valves is warranted (Section 01.4).
The onsite review functions of the Plant Nuclear Safety Committee (PNSC)
were conducted in accordance with Technical Specifications. The PNSC
meeting attended by the inspectors was well coordinated and meeting
topics were thoroughly discussed and evaluated (Section 07.1).
Based on review of selected Conditions Reports (CRs), it was concluded
that the licensee's corrective action management program was being
implemented in accordance with licensee procedures and regulatory
requirements (Section 07.2).
In general, personnel in all organizational components were identifying
and fixing problems within their area. CRs were discussed on a regular
basis and being assigned for action. CR assessments were thorough and
2
root causes analyses were considered good. Trending of CR data by unit
managers was an effective method for identifying and reversing problems
and adverse trends, and improve overall plant performance (Section
07.2(1)).
Several potential adverse conditions were voided with poor documentation
of justification. A need for training was indicated by the number of
voided CRs with poor documentation of justification. The large number
of voided CRs also indicated a weakness in personnel awareness of what
constituted an adverse condition (Section 07.2(1)).
Self-assessments in Engineering, and Materials and Contract services
indicated a need for training. Nuclear Assessment Section assessment
96-01 identified a weakness in the understanding of the CR process..
Discussions with plant personnel disclosed that there was no formal
training provided to personnel, other than CR evaluation personnel
(Section 07.2(1)).
The Operating Experience Program (OEP) was judged to be effective. The
completed OE evaluations reviewed were acceptable. OEP self-assessments
and NAS audits were thorough. The OE weekly status meeting, monthly
report, and OE tracking provided good program oversight. The
incorporation of OE data into routine daily activities was viewed as a
strength (Section 07.2(2)).
The self-assessment program has been effective in identifying
performance deficiencies and was useful in providing oversight to
management. Managers have been proactive in following up on issues
identified at other sites to identify and correct deficiencies at the
plant. Licensee management is committed to the self-assessment process
as indicated by the resources, including assistance of outside
organizations, involved in the self-assessment process, and the number
of self-assessments performed on an annual basis (Section 07.2(3)).
Operations personnel identification and response to an anomaly between
Steam Pressure transmitter output and energization of Freeze Protection
circuitry was considered an example of good attention to detail and
plant monitoring (Section M1.2).
Maintenance
The inspectors concluded that maintenance and surveillance activities
were performed satisfactorily (Section M1.1).
The lack of comprehensive preventive maintenance on the Freeze
Protection system was identified as a weakness in the licensee's cold
weather protection program. Had there been preventative maintenance to
verify the operability of Freeze Protection system thermostats, the
problems associated with thermostats in the Steam Generator and Steam
Header pressure transmitter cabinets could have been identified
previously (Section M1.2).
3
Engineering
The licensee's design change process was determined to be adequate,
however, a concern was identified that a process was in place that used
an engineering review in lieu of a design verification for plant changes
designated as configuration changes only. An Unresolved Item (URI) was
identified for further review of the licensee's engineering review
requirements. The existence of duplicate administrative procedures
(corporate and site specific) controlling the engineering design and
design change process could result in confusion and design control
errors in the future due to differences in requirements (Section E1.1).
Design changes and modification packages reviewed were determined to be
of good quality. The packages contained sufficient specifications,
drawings, and procedures to be properly installed and tested (Section
E1.2).
A violation was identified regarding the licensee's failure to follow
procedures in canceling corrective actions required by an engineering
evaluation for inspections of the containment liner plate for corrosion
(Section E2).
Engineers were actively involved in the day-to-day support of plant
equipment. The material condition of the plant and equipment was
considered good to excellent (Section E2).
The licensee's program for training and qualification of system
engineers was determined to meet regulatory requirements (Section E5).
An Unresolved Item was identified involving a potential inadequate
10CFR50.59 evaluation conducted for a change to a procedure allowing the
Containment Spray System to be aligned in an undesirable configuration
during Spray Additive Tank discharge valve leakage testing (Section
E8.1).
Engineering thoroughly evaluated Steam Generator and Steam Header
pressure transmitter output anomalies that were caused from higher than
designed cabinet temperatures resulting from Freeze Protection system
malfunctions (Section M1.2).
Plant Support
The Emergency Preparedness (EP) program was receiving strong management
support (Section P6). The EP facilities were satisfactorily equipped
and maintained in operational readiness (Section P2.1). The operational
status and maintenance of the siren system was good (Section P2.3).
The
licensees's dose assessment capabilities were satisfactory and
sufficient personnel were trained to perform onshift dose assessment
using real time meteorological and radiological data (Section P2.2).
The new designation and reorganization of the EP procedures was
considered an improvement (Section P3.1).
4
The licensee was effectively implementing the Emergency Response
Organization training program. The licensee had rewritten their
training program and reorganized their lesson plans. The new training
program and lesson plan were an improvement, but the exams could be
improved (Section P5.2).
Combining licensed operator retraining with
emergency preparedness drills was a strength for the emergency
preparedness program and resulted in an increase in the number of
training drills (Section P5.1). The number of drills performed during
the year, the level of participation, and the feedback training provided
to the players was a strength (Section P5.3).
Nuclear Assessment Section audits of the EP program were detailed in
scope and thorough (Section P7.1).
The EP organization was adequately tracking and resolving upper tier
issues. The licensee's loss of their lower level tracking system for EP
drill comments and issues contributed to continuing problems with
documentation. Control of documentation continues to be a concern
(Section P7.2).
Report Details
Summary of Plant Status
Unit 2 remained at power the entire inspection period completing 70 days of
continuous operation since startup from Refueling Outage 17. On December 22,
1996, a downpower to 96 percent and later to 90 percent was conducted in order
to recover from a feedwater heater transient and to reseat a relief valve that
lifted on the 5B Feedwater Heater. The 5B Feedwater Heater relief valve
lifted while attempting to place the 6A Feedwater Heater level control
instrument in service following an air-line failure to the level controller.
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 operations turnover, and
management review 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. Plant tours were
conducted to observe equipment status and housekeeping. Condition
Reports (CRs) were reviewed to assure that potential safety concerns and
equipment problems were reported and resolved. Specific events and
noteworthy observations are detailed in the sections below.
01.2 "C"
Auxiliary Boiler Water Hammer Incident
a. Inspection Scope (71707)
On December 20, while placing the "C"
Auxiliary Boiler in service, a
water hammer occurred downstream of the boiler in the piping to the C
Auxiliary Boiler Deaerator Tank. The inspectors reviewed the
circumstances leading to the water hammer, discussed the incident with
engineering personnel who were investigating the incident, and walked
down the piping to determine if all damage was properly identified by
the licensee.
b. Observations and Findings
On December 20, operations personnel were placing the "C"
Auxiliary
Boiler in service in accordance with Operations Procedure (OP)-401,
Auxiliary Heating Steam, Rev. 31. The purpose for starting the "C"
Auxiliary Boiler was to supply supplemental heating steam to certain
areas of the Auxiliary Building due to decreasing outside environment
temperatures. When valve AS-2317, the Auxiliary Steam to the "C"
Auxiliary Boiler Deaerator Tank', was opened in accordance-with the
procedure, evidence of a water hammer was heard downstream of AS-2317 in
2
the piping to the C Auxiliary Boiler Deaerator Tank. Boiler startup was
suspended and engineering personnel were notified of the incident and
requested to inspect the affected piping for any damage. Although no
damage was identified as a result of the incident, an investigation was
initiated to determine the root cause of the water hammer.
The licensee determined that the water hammer was the result of a drain
valve lineup problem associated with OP-401. The procedure required
that AS-2317 be closed whenever the C Auxiliary Boiler was not in
service. Closing AS-2317 also isolated a downstream steam trap allowing
steam trapped in the piping to condense and form voids in the piping.
When AS-2317 was opened during startup of the boiler, the sudden re
pressurization of the piping resulted in a water hammer.
The licensee planned to revise OP-401 to ensure that AS-2317 remained
open and provisions for verifying that the piping downstream of AS-2317
was properly drained of condensation prior to placing the C Auxiliary
Boiler in service. An operations clearance was placed on the C
Auxiliary Boiler until the procedure was revised. The inspectors
conducted a walkdown of the affected piping following the event. No
damage to the affected piping was observed from this walkdown.
At the end of the inspection period, the licensee was still
investigating the reason why OP-401 had been written to allow the
improper lineup that allowed the potential for a water hammer event. A
procedure discrepancy was evident since plant piping details showed the
normal lineup for AS-2317 as open. The results of the licensee's
investigation and associated corrective actions to address the procedure
problem were to be documented in CR 96-03184, which was initiated to
address this incident.
The inspectors noted that this was the third steam or water related
hydraulic transient that had occurred over the past several months. For
example, in September 1996, during plant shutdown for refueling outage
17, a water hammer was introduced in certain feedwater heater drain
lines as a result of re-admitting steam to the Moisture Separator
Reheaters which had previously been isolated during plant cooldown. In
October, during reactor coolant system check valve leakage testing, a
water hammer occurred in the Safety Injection cold leg injection piping
as a result of not adequately re-pressurizing the piping during testing
restoration. In both of these two incidents, the primary cause was the
result of inadequate procedures controlling the system or test
alignment. In each of the three incidents, the problems associated with
the procedures had gone uncorrected over many years even though the
procedures had been used periodically. The inspectors noted that this
indicated a lack of sensitivity to recognizing and resolving minor
hydraulic transient problems.
The inspectors have noted a heightened awareness by operations and
engineering personnel/management to the potential for hydraulic
transients since the first two incidents discussed above. The
3
identification and detailed investigation of the C Auxiliary Boiler
water hammer transient was an example of this heightened awareness.
The licensee indicated that a more detailed review of all operations
system lineup and test procedures would be conducted to ensure that
other configuration problems which could lead to potential hydraulic
transients were identified and corrected.
c. Conclusions
The inspectors concluded that operations personnel demonstrated a
heightened sensitivity to potential hydraulic transients with the
identification of this incident. Engineering performed a detailed
investigation of the transient and were successful in identifying the
root cause. The licensee's planned corrective actions were appropriate
to address the procedure discrepancy identified, as well as the generic
implications of other potential procedural configuration weaknesses.
While the Auxiliary Boiler is not a safety related system, the
inspectors noted that continued licensee emphasis and sensitivity to
potential hydraulic transients was warranted due to past weaknesses in
this area.
01.3 Crack in the Emergency Diesel Generator Room Roof
a. Inspection Scope (37551, 71707)
The inspectors reviewed and discussed with the licensee, CR 96-03202
that was generated due to a noted crack in the concrete roof of the B
Emergency Diesel Generator (EDG) building.
b. Observations and Findings
The condition report was originated when an operator noted some water
dripping from the roof into the EDG room. Upon noticing the condition,
Robinson Engineering Support Section (RESS) was notified. Further it
was verified that no water was dripping onto electrical equipment within
the EDG room. The inspectors performed a walkdown of the EDG building,
including the roof with the licensee and discussed the condition with
the assigned structural engineer. The crack was not obviously visible
from the EDG room.
An evaluation associated with the condition report concluded that the
seismic/structural integrity of the building was not negatively impacted
by the crack in the EDG roof and that the ability to maintain negative
pressure in the auxiliary building was maintained. As immediate
corrective action, the affected area of the roof was re-coated with a
sealing paint. Additionally, the licensee plans to re-coat the entire
roof with a flexible water tight sealing material. Action request (AR
96-05410) was initiated by the licensee to track this planned corrective
action. The inspectors plan to continue to periodically monitor this
issue during the conduct of routine inspections.
c. Conclusions
The inspectors concluded that the operator acted appropriately upon
noting the abnormal condition relative to water dripping into the EDG
room. Further, the crack did not impact the operability of the EDG.
01.4 Failed Instrument Air Line Affecting 6A Feedwater Heater
a. Inspection Scope (71707, 62707, 37551, 40500)
An Instrument Air (IA)
line associated with a feedwater heater level
controller failed initiating a minor transient as well as power
reductions. The inspectors assessed licensee activities associated with
the event. CRs 96-03194 and 96-03195 were generated as a result of the
event.
b. Observations and Findings
On December 22, 1996, while Robinson Unit 2 was at 100% power, an
instrument air line on the 6A Feedwater Heater level controller (LC)
failed such that the 6A Feedwater Heater level control valves (LCV)
1508A and 1508B failed closed. With the 6A Feedwater LCVs closed, the
drain path to the heater drain tank was isolated and the 6A Feedwater
Heater shell side level started to increase. This initiated a transient
which manifested in a level deviation in the C Steam Generator (S/G) due
to lower S/G level and an increase in power to approximately 101.4 %.
The control room responded to the level deviation alarm and reduced
power to approximately 96%. Following restoration of S/G level and
stabilization of the transient, the plant was returned to full power.
The 6A Feedwater heater alternate LCV 1508B was opened to allow shell
side blow-through.
Troubleshooting and repairs were performed and the failed section of the
copper instrument air tubing to the LC was replaced. A small crack was
noted in the IA line which was attributed to cycling of the tubing for
connection and disconnection purposes. Upon discussion, the inspectors
were informed that the plant had experienced other problems with the IA
system, and consequently, the IA system is being carried as a "TOP 10"
item to appropriately prioritized attention and resources. The failed
portion of the IA tubing was replaced.
Additionally, since the 6A Feedwater Heater High level alarm had not
come in as expected following the closure of the LCVs, the shell side
level switch was checked and demonstrated to operate properly.
During the restoration to normal alignment following repairs, the SB
Feedwater Heater shell side relief valve HDV-381B lifted. Consequently,
a power reduction was initiated and the relief valve reseated at
approximately 90%. The restoration was being performed at full power
and it.involved transferring the 6A Feedwater Heater level controls from
the alternate to the primary LCV (i.e. from LCV 1508B to LCV 1508A).
The licensee is postulating that during this transfer, a pressure
5
perturbation occurred and was transmitted through the heater drain tank
to the 5B Feedwater Heater. The inspectors questioned whether the
licensee decision to restore the 6A Feedwater Heater to normal alignment
at full power was conservative. The licensee plans to review this
issue, including assistance from RESS, through the condition report
process.
Initially, the licensee believed that the relief valve had prematurely
lifted at approximately 176 psig with an expected setpoint of 225 psig.
This was based on the system pressure readings as observed on Emergency
Response Facility Information System (ERFIS) reading approximately 176
psig. However, upon further review, the licensee believes that the
system pressure did probably reach 225 psig and the data sampling
frequency of ERFIS was such that it did not capture the instantaneous
system pressure that caused the relief valve to lift.
Feedwater heater relief valves, including HDV-381B are not periodically
tested. Consequently, a work request was initiated to test the relief
valves on the 3A, 3B, 4A, 4B, 5A, 5B, 6A, and 6B heaters during the next
scheduled outage. Further, the licensee will assess the periodic
testing of the relief valves through the condition report. Upon
questioning, the inspectors were informed that the lifted relief valve
setpoint, if changed due to the lifting, is more likely to have lowered.
c. Conclusions
The inspectors concluded that a reliability problem associated with a
portion of the IA system resulted in a transient on the secondary side.
Continued licensee attention to address this issue, as well as periodic
testing of-secondary relief valves is warranted. The decision to
restore the 6A Feedwater Heater to normal alignment at full power was
considered a weakness.
07
Quality Assurance In Operations
07.1 Plant Nuclear Safety Committee Meeting
a. Inspection Scope (40500)
The inspectors evaluated certain activities of the Plant Nuclear Safety
Committee (PNSC) to determine whether the onsite review functions were
conducted in accordance with TS and other regulatory requirements.
b. Observations and Findings
On December 18, 1996, the inspectors attended the PNSC meeting during
which the committee reviewed an evaluation of SOER 96-1, Control Room
Supervision, Operational Decision Making, and Teamwork; a violation
response and procedural revisions; and a presentation from the Nuclear
Fuels Group on the disposition of the error in the Siemens' code for a
large break loss of coolant accident (LBLOCA). The presentations were
thorough and the presenters readily responded to all questions. The
- 6
committee members asked probing questions and were well prepared. The
committee members displayed understanding of the issues and potential
risks. The inspectors considered that the chairman appropriately
limited discussion to the issues and their safety ramifications.
c. Conclusions
The inspectors concluded that the onsite review functions of the PNSC
were conducted in accordance with TSs. The PNSC meeting attended by the
inspectors was well coordinated and meeting topics were thoroughly
discussed and evaluated.
07.2 Effectiveness of Licensee Controls in Identifying, Resolving, and
Preventing Problems
The licensee has provided a site-wide, common program for identifying
issues that require corrective action. The goal of the program was to
improve overall plant performance by correcting conditions adverse to
quality. During this inspection, the inspectors reviewed the
administrative and procedural aspects of the program, the effectiveness
of the corrective actions, the self-assessments and audits of the
program, and other processes that provided for the incorporation of
operating experience feedback.
1.
Corrective Action Program
Inspection Scope (40500)
The licensee's procedure, PLP-026, Corrective Action Program, Rev. 24,
was reviewed by the inspectors. In addition many of the specific
elements of the program and completed CRs were reviewed.
Observations and Findings
The inspectors reviewed 7 CRs which were classified as significant CRs
in accordance with PLP-026. The inspectors verified that operability
assessments were performed, management reviews were completed,
evaluations and recommended corrective actions were appropriate, and
when required, appropriate immediate corrective actions were performed
based on the nature of the problem. The following CRs were reviewed by
the inspectors and determined to be appropriately dispositioned.
95-01873: Inadequate corrective actions to respond to NAS
findings,
96-02272: Position of Containment butterfly valves,
96-02471: Cutting of incorrect conduit during plant
modification,
96-02754: Water hammer during safety injection accumulator
piping surveillance test,
95-01523: Inadvertent Residual Heat Removal pump start,
95-02216 - Unexpected Emergency Diesel Generator start during
clearance tagout, and,
95-01661 - Main Feedwater Isolation following high Steam Generator
level.
In addition to assessing the program, the inspectors reviewed another
sample of Condition Reports. Within the sample it was found that about
20% had been deferred to provide an extension of time for corrective
action, and about 44% required more time for evaluation.
Deferrals are permitted by PLP-026, with restrictions. The restrictions
include specific level of management approval for the first two
extensions. If an additional extension is needed, approval from the
Site Vice-President is required. The deferral rate was acceptable. The
inspectors concluded that the controls in place have kept the number of
CR deferrals in check. The inspectors did not find any deferred CRs
without a valid reason, nor did the deferral have an adverse effect on
safe plant operations. This.area was reviewed for trends by the Self
Assessment Manager to assure that items were not improperly deferred.
The inspectors screened 107 CRs that were voided in 1996 and observed
that 40% were duplicates or were incorporated into another CR.
Approximately 25% contained insufficient data to verify that CR voiding
was appropriate, including 2 CRs which had no entry in the reason for
voidance field. Based on further discussion and review of the reason
for voidance, the dispositioning of the sample of voided CRs reviewed
was acceptable.
Other CRs were voided and the reason stated for voidance on the form
indicated that the item would be resolved by another mechanism.
However, in some cases the issue was not resolved. Paragraph 5.1.2.1 of
PLP-026 addresses the method to void CRs which, after evaluation, are
determined to not meet the definition of an adverse condition. The
procedure indicates that the reason for voiding a CR is to be documented
on a CR change form. The inspectors reviewed eleven randomly selected
"voided" CRs to verify the concerns documented on the CRs did not
constitute an adverse condition, and that voiding of the CR was
appropriate. The voided CRs reviewed were 96-00349, 96-00502, 96-00543,
96-01094, 96-02765, 96-00391, 96-00566, 96-00601, 96-00893, 96-02195,
and 96-01356. The inspectors concluded that none of the concerns
documented on the "voided" CRs met the definition of an adverse
condition. However, review of the "voided" CR resolutions disclosed
that the reason the CRs were voided was not always well documented.
Examples identified were as follows:
CR 96-00349 involved a procedure which required re
verification of the containment equipment hatch opening
times each time the hatch is opened. The reason for voiding
8
stated that the CR was intended to be an engineering service
request (ESR).
The inspectors determined that an ESR was
initiated (number 96-0122) but was later deleted since the
existing procedure was determined to be appropriate. The
inspectors did not identify a problem with the resolution of
the issue although the final disposition was not well
documented in the CR.
CR 96-00502 involved an error found on one of the original
plant construction drawings. The reason for voiding
documented on the CR stated that a drawing change request
(DCR) was initiated to revise the drawing. The inspectors
determined that a DCR (number 96-168) was issued, but later
also was voided. The final disposition of this concern was
to delete the drawing since it was no longer required.
However, this was not documented in the CR.
CR 96-00543 concerned a potential incorrect fire barrier
(penetration) design. The reason for voiding stated on the
CR was that engineering felt that this issue had been
previously evaluated, but that if the documentation could
not be provided, a new CR would be issued. Discussions with
the engineers involved in the resolution of the issue
disclosed that the concern had been evaluated, as stated on
the CR, and that the as-built design was acceptable.
However, a reference to the final disposition of the issue
was not documented in the CR.
CR 96-01094 concerned an equipment item which had not been
installed. An ESR, number 96-00272, was issued to resolve
the issue. The CR was voided pending resolution of the ESR.
The inspectors determined that ESR 9600272 was deleted by
ESR 9600476 which was still open. The final disposition of
the concern was not documented on the CR.
CR 96-02765 concerned an error on a safety-related system
flow diagram. The reason for voiding the CR stated that a
DCR would be issued to correct the problem. The inspectors
determined that DCR 96-1103 was issued to correct the
drawing and that the DCR (drawing correction) was being
implemented.
CR 96-00391 involved a potential inadequate review of significant
event report 92-012 regarding potential reverse rotation of
containment fan units when in standby or shutoff. The reason for
voiding the CR was not documented. Theinspectors reviewed the CR
resolution with licensee technical support and operations
personnel and determined that procedural controls were utilized to
prevent this problem as well as monthly surveillance. The
resolution was acceptable although the disposition was not
documented in the CR.
9
CR 96-00601 involved a potential spread of contamination issue
regarding High Efficiency Particulate Air (HEPA) filter hose left
open. Procedural requirements include sealing the hose after use.
It was later determined that the unit was still in use and did not
require sealing at that time. The inspectors determined that the
resolution was acceptable but the disposition was not documented
in the CR.
The inspectors also reviewed three additional "voided" CRs and concluded
that the reason for voidance was clearly documented in the CR. These
were CR numbers 96-01091, -01402, and -01941.
The inspectors identified the following as a weakness in the licensee's
corrective action program:
Incomplete/improper documentation of the
reasons for voiding a CR, and/or voiding a CR based on some planned
action when the action was still incomplete when the CR was voided.
Significant CRs are required to be evaluated within 14 days and
completed within 60 days of the evaluation approval date. Extensions or
deferrals are periodically reviewed for adverse trends by the management
of the Self-Assessment Section. Program data showed that about 2500 CRs
are initiated per year and that all organizations were actively involved
in the program. Corrective Action Program (CAP) tracking and data
trending was good and the backlog was under control. The program
recognition "Catch of the week" provided positive incentives. The
Operating Events Assessment unit involvement provided program oversight
which contributed to the success of the program. Management and site
personnel had a positive attitude toward the program.
Section 5.13.1.2 of PLP-026 requires each site section or unit to
perform a quarterly analysis of CR data to detect trends. The
inspectors reviewed the analysis of the trends based on condition
reports performed for the third quarter of 1996 in the Robinson
Engineering Support Section, maintenance, and operations units. The
analysis of the CR data indicated some potential adverse trends which
the managers in the units documented on new CRs to evaluate and develop
corrective actions to resolve the issues. The inspectors also attended
a weekly Robinson Engineering Support Section managers meeting during
which CRs identified during the previous week were discussed by the unit
managers to address corrective actions, causes of the CRs. and steps to
take to avoid similar CRs.
The OEA Manager performed trending and evaluation of the CR process.
The data indicated that the CR backlog was not trending up and CR
tracking was adequate for program control. The inspectors concluded
that the trending of CR data by unit managers was an effective method to
identify and reverse problems and adverse trends, and improve-overall
plant performance.
A sample of about 3000 CRs was examined to determine which
organizational component was identifying the issues and who was fixing
them. The following results were found:
Organizational Component
% Found
% Fixed
Environ. & Radiation Control
24
20
Operations
14
10
Maintenance
11
15
Mechanical Systems
9
14
Nuclear Assurance Section
8
8
Security
7
6
Outage & Scheduling
6
6
Elec I&C
4
9
Others
17.
20
From the above data, it was evident that all organizational components
were finding and fixing problems within their area. In some cases, such
as maintenance and operations, CRs that were identified by their own
personnel were assigned to another organizational component for
corrective action. This was expected.
Several managers directly involved within the licensee's problem
identification process and corrective action program were interviewed to
determine the extent of their understanding of the process and their
feelings toward ownership of the program. Those selected were from
maintenance, engineering, plant support, operations, and quality
assurance. The subjects discussed at these interviews included: the
extent of their involvement, amount of resources devoted to the program,
and, how well they thought the program was working.
All personnel interviewed accepted the program and were using it as
intended. It was evident to the inspectors that significant resources
were devoted to this program.
The inspectors reviewed the audits of the CAP conducted by NAS and
Performance Evaluation Section, and the reviews of the Corrective Action
Program by the onsite and offsite review committees. Self-assessments
reports were also reviewed. The findings and actions taken by the
various audits and reviews were examined for timeliness and
completeness.
Additional areas of the CAP were reviewed as follows:
a sample of recent events and issues were reviewed to determine
if a CR was prepared for the item,
the weekly Operating Experience Assessment Unit Weekly staff
meeting and a Failure Prevention Inc. Users Group meeting were
attended by the inspectors, and,
a sample of significant, completed, and voided CRs were reviewed.
Conclusions
Based on review of selected CRs, the inspectors concluded that the
licensee's corrective action management program was implemented in
accordance with PLP-026 and UFSAR Section 17.3, Robinson Quality
Assurance Program Description.
In general, all organizational components were finding and fixing
problems within their area. CRs were discussed on a regular basis, at
least weekly, and were assigned for action. CR assessments were
thorough and root cause analyses were good. Trending of CR data by unit
managers was an effective method to identify and reverse problems and
adverse trends, and improve overall plant performance.
Several potential adverse conditions were voided with poor
documentation. A need for training was indicated by the number of
voided CRs with poor documentation. The large number of voided CRs
indicated a weakness in personnel awareness of what constituted an
adverse condition.
Self-assessments in Engineering, and Materials and Contract services
indicated a need for training. NAS assessment 96-01 identified a
weakness in the understanding of the CR process. Discussions with plant
personnel disclosed that there was no formal training provided to
personnel, other than CR evaluation personnel.
2.
Operating Experience Program
Inspection Scope (40500)
The inspectors reviewed the licensee's Operating Experience (OE)
Program.
Observations and Findings
Operating Experience is a part of the overall H. B. Robinson CP&L
quality assurance process. The Operating Experience program ensures
industry data is sent to applicable Robinson work units and that
Robinson specific experience and data is supplied to other CP&L sites
and the nuclear industry as appropriate. The inspectors reviewed
Robinson procedure PLP-107, Operating Experience Program, Revision 0,
dated June 26, 1996. This procedure provided the requirements for
establishing the Robinson Operating Experience program including source
document receipt, screening, evaluation, recommended actions, action
tracking, action closeout and program status reporting.
OE feedback item applicability screenings, OE item evaluations, OE unit
self-assessments, OE program Nuclear Assurance Section (NAS) audits, and
OE tracking and work backlogs were reviewed. The inspectors attended
the weekly Operating Experience Assessment (OEA) meeting, interviewed
plant personnel and observed end use activities of the OE program.
12
OE source document screening items 5751, 5761, and 5774 were reviewed.
The screening reviews were performed in accordance with PLP-107 and the
applicability review and recommended actions were acceptable. The
inspectors reviewed completed OE item evaluations 96-00636, 96-00955,
and 96-01923. The evaluations were completed in accordance with PLP-107
and were thorough.
Self-assessments and NAS audits were performed on the OE program. The
inspectors reviewed OE self-assessments: 0EA 96-05, SOER/OSU 96-03,
SOER/0EF 96-02, OEA 96-01 and R-OE-95-01. NAS audits RSOER 96-01 and R
CA-96-01 were reviewed. Both the NAS audits and OE self-assessments
identified that procedures did not incorporate Significant Operating
Experience Report (SOER) references. CR 96-00956 was initiated for
resolution of this item. The inspectors concluded that the self
assessments and NAS audits were thorough and that the findings were
substantive. The licensee was taking actions to address the findings.
The inspectors attended the OEA unit weekly status meeting and observed
that the staff reviewed the OE items screened for the week and verified
the acceptability of the item dispositioned. Condition Reports
processed for the week were also reviewed including the CR
classification. The OEA staff selected one corrective action/
improvement item identified each week and provided an award and mention
for the CR initiator in a licensee newsletter. This provided positive
feedback for the problem identification process and demonstrated
commitment to problem self identification and resolution.
The OEA unit tracking and work backlog was reviewed. A monthly report
was prepared by the OE reviewer which addressed the items processed for
the month and tracked the evaluations issued, and the status and age of
open evaluations. The OE backlog was examined and the inspectors
determined that the backlog was not excessive and no evidence was noted
of items being deleted or deferred.
The licensee had incorporated OE feedback data into several routine
activities. The inspectors observed that OE feedback items were
discussed at morning shift turnover meetings. The checklist for
conducting pre/post job briefings requires that the briefing include a
discussion of applicable OE data for the evolution. An OE item file by
system was maintained in the control room for use in conjunction with
the OE database for conducting briefings. The files contained
experience data identified by the NRC, INPO, and other CP&L sites. The
frequent use of OE data in routine daily activities was viewed as a
strength.
Discussions with site personnel indicated that performance during the
outage was improved with the emphasis on frequent use of CE data. OE
information was used in briefings for all the major evolutions of
shutdown, cooldown, startup, and heatup. The recent safety injection
system water hammer event was an example where previous experience did
not preclude a similar event.
13
Conclusions
The Operating Experience Program was determined to be effective. The
completed OE evaluations reviewed were acceptable. The OE self
assessments and NAS.OE audits were thorough. The OEA weekly status
meeting, monthly report, and OE tracking provided good program
oversight. The incorporation of OE data into routine daily activities
was viewed as a strength.
3.
Self-Assessment Activities
Inspection Scope (40500)
The inspectors reviewed self-assessment activities performed within the
Robinson line organizations.
Observations and Findings
Self-assessments are part of the overall CP&L quality assurance program
at Robinson. Self-assessments are critical evaluations of activities,
processes, or programs performed by the individuals or organizations
accountable for the work. The results of these assessments are
categorized as strengths, or findings. Findings may be adverse
conditions, areas not meeting expectations, or areas needing
improvement. The inspectors reviewed Robinson procedure PLP-057, Self
Assessment, Revision 5, dated September 16, 1996. This procedure
specifies the requirements for establishing the self-assessment program
including development of an annual self-assessment plan, the frequency
for self-assessments, areas to be covered, e. g., the corrective action
program in each work unit, conducting assessments, reporting results,
and follow-up activities.
The inspectors reviewed the 1996 Self-Assessment plans for the following
Robinson work units: the engineering support section, training,
operations, maintenance, materials and contract services, and the
Robinson NAS. The inspectors noted that the majority of the planned
assessments were performed on schedule, assessments were not being
canceled or deleted, and assessments were added to the schedule or were
being rescheduled (planned dates moved-up) to respond to events which
occurred at other sites. The licensee also performed additional
assessments if findings were identified which appeared to have generic
implications. An example of this was the self-assessment of the 50.59
process in the Robinson Engineering Support Section which indicated
deficiencies in the quality and documentation of safety evaluations
performed for design changes. A site wide assessment was performed by
NAS to determine if similar problems existed in 50.59 evaluations
performed by other site work units. The inspectors also noted that
assistance was provided by personnel from other sites and other
organizations to perform some of the self-assessments. The use of
individuals from other organizations provides additional insight in the
various processes which are being evaluated. The self-assessments
covered all major functional areas.
14
The inspectors reviewed the following self-assessments:
R-96-OP-04: Operator Actions not Covered by Procedures,
MNT 96-01: Effectiveness of Maintenance CAP Program,
MNT 96-05 - UFSAR Commitments,
TRAIN 96-03 - Training Section Corrective Action Program,
RESS 96-09 - RESS Corrective Action Program,
RESS 96-12 - Temporary Modification Control (follow-up),
RESS 96-15 - RESS Organization & Administration,
RESS 96-18 - Engineering Product Quality,
RESS 96-26 - Environmental Qualification,
RESS 96-31 - Identification and Updating of Affected Design
Documents (follow-up),
RESS 96-32 - Safety Review Screening,
RAS 96-01 - 10 CFR 50.59 Program, and,
M&CS/P 96-06 - Corrective Action Program.
From review of the above self-assessments, the inspectors determined
that CRs were initiated when findings in self-assessments were
identified as adverse conditions, follow-up reviews were performed, and
improvement CRs were initiated to track recommended actions resulting
from self-assessments. Licensee management was actively involved in
monitoring the results of the self-assessments and monitoring the
overall effectiveness of the program.
Conclusions
The inspectors concluded that the self-assessment program at Robinson
has been effective in identifying performance deficiencies and was
useful in providing oversight to management. Managers have been
proactive in following up on issues identified at other sites to
identify and correct deficiencies at Robinson. The inspectors also
concluded that licensee management was committed to the self-assessment
process as indicated by the resources, including assistance of outside
organizations, involved in the self-assessment process, and the number
of self-assessments performed on an annual basis.
15
08
Miscellaneous Operational Issues (92901)
08.1
(Closed) VIO 50-261/95-21-01, Operator Failure To Monitor Plant Status:
This violation was issued because operators failed to adequately monitor
steam generator (S/G) levels and take appropriate actions. As a result,
a high S/G level trip occurred. The root causes were determined to be
personnel error (inattention to detail and misjudgment) by operations
personnel, and equipment degradation of feedwater regulating valves
(FRVs) and FRV bypass valves. The corrective actions included event
review with operating crews, additional emphasis on operations self
assessments, improvement to pre-job and post-job briefings, evaluation
of FRV bypass valve leakage, and revisions to operator event simulator
training. The inspectors reviewed shift personnel statements, event
review training records, Operations Shift Error Prevention Plans,
discussed pre-job and post-job briefing changes with operations
personnel, Engineering Evaluation of FRV bypass valves leakage, Training
Scenario EPP-4 Reactor Trip Response, and scenario training records.
The inspector verified the corrective actions described in the
licensee's response letter, dated September 11, 1995, to be reasonable
and complete. The corrective actions addressed the event root cause.
Two new corrective actions subtasks were established to implement FRV
bypass valve vendor recommendation for improving valve leakage
performance at the next valve overhaul. This item is closed.
08.2 (Closed) VIO 50-261/95-27-01, Inadequate Clearance Results In
Unexpected Emergency Diesel Start: This violation was issued because an
unexpected Emergency Diesel Generator (EDG) start occurred while
implementing a clearance for scheduled maintenance. An inadequate
clearance boundary allowed air trapped in the air start piping to start
the engine. An incorrect assumption was made that the volume of trapped
air would not start the engine. The licensee and vendor evaluated the
event and determined that no engine damage occurred. This EDG
evaluation was described in NRC Inspection Report 50-261/95-27 as
adequate. The event cause was due to personnel error. The corrective
action included performing the evaluation of the EDG and providing
training. The inspectors reviewed the EDG evaluation (ESRs 9500990 and
9500993), the work request which inspected the EDG (WR/JO 95ALTZ1), and
the records for the training on venting/draining requirements and the
need for conservative decisions regarding operation and clearances for
Engineered Safety Features equipment of procedure Operations Management
Manual (OMM)-005, Clearance and Test Request. The inspectors verified
the corrective actions described in the licensee's response letter,
dated December 14, 1995, to be reasonable and complete. The corrective
actions addressed the event root cause. This item is closed.
08.3 (Closed) VIO 50-261/96-01-01, Auxiliary Feedwater System Valve
Misalignment: On January 16, 1996, during a walkdown of the accessible
areas of the Auxiliary Feedwater (AFW) System, the inspectors identified
that two valves were not in the specified position. Operating Procedure
(OP)-402, Auxiliary Feedwater System, Revision 38, Attachment 9.1, AFW
Valve Checklist requires that valves AFW-110 and AFW-111 be in the full
open position. The inspectors observed that these valves were in the
16
throttled position and notified the Shift Supervisor. An auxiliary
operator(AO) later verified that the valves were 60% open and placed
them in the specified position. CR 96-00126 was initiated to follow
this item.
The licensee performed an extensive investigation and concluded that the
most probable cause for AFW-110 and AFW-111 to be found 60% open was
flow induced vibration. Testing would not have detected the
mispositioned valves. The valves are in the recirculation line of each
motor driven AFW pump and allowed sufficient flow to meet the
surveillance acceptance criteria.
On February 13, 1996, during the performance of Operations Surveillance
Test (OST)-201-B, MDAFW System Component Test-Train B (Monthly), the AO
who was performing the test and a system engineer who was assisting
observed that AFW-111 vibrated five full turns in the closed direction.
CR 96-00359 was initiated to follow this issue. The licensee's
corrective action was to lock open valves AFW-110 and AFW-111 and revise
the flow diagram. CR 96-00126 was also revised to reflect the CR 96
00359 corrective actions. Additional corrective actions were to revise
Operations Management Manual (OMM)-001, Conduct of Operations, to
provide additional guidance for valve verification. PLP-030,
Independent Verification, was also revised to reflect the changes of
OMM-001. The event was reviewed with the operators during training.
The inspectors reviewed Flow Diagram G-190197, Revision 38, Sheet 4 and
verified that valves AFW-110 and AFW-111 were locked open. They
reviewed lesson plans and training records and verified that training
was given to the operators. The corrective actions have been completed
and this item is closed.
II. Maintenance
M1
Conduct of Maintenance
M1.1 General Comments
a. Inspection Scope (61726 and 62707)
The inspectors observed all or portions of the following maintenance
related WRs/JOs and surveillances and reviewed the associated
documentation:
WR/JO 95-ANLEl: Replacement of Instrument Air Check Valve IA-474
WR/JO 96-AIPP-003: "B" Instrument Air Compressor Preventative
Maintenance
WR/JO AHVN-001: Thermal Overload Testing of 480V Breaker for
Motor-Operated Valve CC-749A
17
OST 352-2: Containment Spray Component Test - Train B, Rev. 2
b. Observations and Findings
The inspectors observed that these activities were performed by
personnel who were experienced and knowledgeable of their assigned
tasks. Work and surveillance procedures were present at the work
location and being adhered to. Procedures provided sufficient detail
and guidance for the intended activities. Activities were properly
authorized and coordinated with operations prior to start. Test
equipment in use was calibrated, procedure prerequisites were met,
system restoration was completed, and surveillance acceptance criteria
were met.
c. Conclusions
The inspectors concluded that maintenance and surveillance activities
were performed satisfactorily.
M1.2 Lack of Comprehensive Preventive Maintenance for Freeze Protection
Circuits
a. Inspection Scope (62707)
The inspectors continued folTowup on several maintenance related issues
identified during the previous inspection report period involving Freeze
Protection (FP) circuitry. Additionally, the inspectors reviewed the
licensee'As evaluation of an anomaly in the output of the Steam Generator
and Steam Header pressure transmitters due to a FP circuitry failures.
b. Observations and Findings
During the previous inspection period, the inspectors conducted a review
of the licensee's cold weather protection program. Associated with this
review, the inspectors performed a walkdown of the selected FP circuitry
status panels and identified that several FP circuit status lights were
not illuminated when they should have been. Also, the inspectors noted
that the settings for FP circuitry thermostats were not periodically
verified to be at their proper setpoint to ensure that the circuits
energized and deenergized at the proper temperature. Based on
discussions with the Electrical/Instrumentation & Control (I&C)
supervisor during the earlier inspection, the licensee felt that other
surveillances being performed by either I&C or operations would identify
any circuitry problems. These other surveillances included the periodic
manual energization of FP circuits and measurement of the current drawn,
and operations personnel requirement to monitor for FP circuit status
lights that were not illuminated.
During this report period, the inspectors verified that appropriate
repairs were performed to correct the problems previously identified
with the FP circuits.
18
Also during this report period, the licensee identified an example where
a FP cabinet heater thermostat for the Steam Generator pressure
transmitters failed to deenergize which caused excessive cabinet
temperatures. This resulted in the output of the transmitters
indicating higher than actual pressures. This problem was identified by
operations personnel on December 12, 1996, when it was noticed that
whenever the FP cabinet heater energized, an increase in steam pressure
occurred. The worst case observed was approximately 10 psig. This
problem was significant since the output of the steam pressure
transmitters provide inputs to the reactor protection system.
The
higher pressure signals could result in exceeding the analyzed values
for the instrument uncertainties. A similar problem was identified when
the FP circuitry in the Steam Header pressure transmitter cabinets. Due
to one of the heaters in this cabinet being miswired, it remained
energized all the time, resulting in higher than expected temperatures
inside.
The inspectors reviewed CR 96-03075 which documented these incident.
The results of an engineering evaluation on the effect of the increase
in steam generator and steam header pressure outputs determined that the
available margin in the instrument uncertainty calculations was not
exceeded. The licensee's corrective actions for these problems included
a review of all transmitters subject to freezing for proper freeze
protection design and the addition of periodic preventive maintenance
for checking the operability and setpoint of FP thermostats. The
inspectors determined that the licensee had adequately evaluated and
proposed adequate corrective actions to address this issue.
c. Conclusions
The inspectors concluded that the lack of comprehensive preventive
maintenance on Freeze Protection circuitry was a weakness in the
licensee's cold weather protection program. Had there been preventative
maintenance to verify the operability of Freeze Protection thermostats,
the problems associated with the thermostats in the Steam Generator and
Steam Header pressure transmitter cabinets could have been identified
previously.
Operations personnel identification and response to the anomaly between
Steam Pressure transmitter output and energization of Freeze Protection
circuitry was considered an example of good attention to detail and
plant monitoring.
Engineering thoroughly evaluated Steam Generator and Steam Header
pressure transmitter output anomalies that were caused from higher than
design cabinet temperatures resulting from Freeze Protection system
malfunctions.
M8
Miscellaneous Maintenance Issues (92902)
.
M8.1 (Closed) VIO 50-261/95-19-05, RHR Pump Start Due to Troubleshooting:
This violation was issued because adequate measures were not established
19
to prevent inadvertent operation of B RHR Pump during troubleshooting of
a defective relay. The licensee's root cause evaluation determined
personnel error as the cause of the event. No positive controls were
used to prevent inadvertent pump start. The event was reviewed with
shift operations personnel and maintenance mechanics and technicians.
The inspectors reviewed the records of this training and verified that
Procedure Maintenance Management Manual MMM-001, revision 29 contained
the requirement that maintenance personnel will use positive controls
such as clearances, caution tags or procedural guidance to prevent
inadvertent equipment operation. The inspectors verified the corrective
actions described in the licensee's response letter dated August 23,
1995, to be reasonable and complete. The corrective action addressed
the event root cause. This item is closed.
M8.2 (Closed) LER 50-261/95-06-00, Technical Specifications Violation Due To
Failure To Meet Minimum Degree Of Redundancy:
and,
(Closed) LER 50-261/95-07-00, Condition Prohibited By Technical
Specifications Due To Failure To Meet Minimum Degree Of Redundancy:
and,
(Closed) LER 50-261/95-07-01, Condition Prohibited By Technical
Specifications Due To Failure To Meet Minimum Degree Of Redundancy:
and,
(Closed) LER 50-261/95-08-00, Condition Prohibited By Technical
Specifications Due To Failure To Meet Minimum Degree Of Redundancy:
On September 3, October 29, and November 5 and 14, 1995, the licensee
had similar events. The first three events were caused by the
Overtemperature Delta-Temperature (OTDT) Temperature Indicator and the
fourth was caused by the Overpower Delta-Temperature (OPDT) setpoint
indicator drifting beyond their acceptable tolerances and the associated
protection channel was declared inoperable. The minimum degree of
redundancy as required by Technical Specification 3.5, Table 3.5-2,
Items 5 and 6 could not be satisfied until the channel was placed in a
tripped condition. These event are described in detail in the subject
LERs.
CRs 95-02062, 95-02556, 95-02618, and 95-02687 were issued to track each
of the events. The licensee combined the November 5 and October 29
events into a single LER (95-07) as the second event was caused by an
improper installation of a component. Hardware inspection revealed that
a failed capacitor was the cause of the OTDT drifting. The licensee
determined that the electrolytic capacitors in the Hagan modules would
be replaced. A Technical Specification change to provide an allowed
outage time for instrumentation channels was one of the proposed
corrective actions. The proposed change was submitted to the NRC by
20
Letter RNP-RA/95-0214 on December 11, 1995, and was granted in Amendment
175. The amendment allows for the licensee one hour to meet the minimum
degree of redundancy. These LERs were closed.
III. Engineering
El
Conduct of Engineering
E1.1 Design Change Processes
a. Inspection Scope (37550)
The inspectors reviewed the licensee's procedures which control the
design change program to determine if the licensee was properly
controlling the design basis of the plant.
b. Observations and Findings
The inspectors reviewed the procedures listed below which control design
and design changes to determine if the procedure implement the
requirements of 10 CFR 50, Appendix B, Criterion III and 10 CFR 50.59.
The following procedures were reviewed:
.EGR-NGGC-001, Conduct of Engineering Operations, Rev. 1,
dated June 28, 1996
EGR-NGGC-003, Design Review Requirements, Rev. 0, dated June
3, 1996
EGR-NGGC-005, Engineering Service Requests, Rev. 2, dated
November 7, 1996, and,
EGR-NGGC-0304, Maintenance of Design Documents, Rev.0, dated
November 11, 1995.
The EGR-NGGC series of procedures were corporate level procedures
being issued to standardize engineering work activities at all
three CP&L nuclear plants. However, the inspectors noted that
when the new EGR-NGGC procedures were issued to improve design
control activities, previously issued procedures which they were
meant to replace were not deleted and/or canceled. For example,
EGR-NGGC-005 was issued to replace procedures PLP-064 and MOD-022.
The inspectors noted that PLP-064 and MOD-022 were still being
maintained current. Discussions with licensee engineers disclosed
that these procedures will be superseded and deleted from the
licensee's document control system in the near future. EGR-NGGC
005, Engineering Service Requests, streamlined the process for
performing engineering work.
The inspectors concluded that the new procedures adequately
addressed: design input, training, drawing changes, post-
21
modification testing, control of field changes, 10 CFR 50.59
safety evaluations, and ALARA reviews. However, review of EGR
NGGC-005 disclosed the following problem:
EGR-NGGC-005 defines
three types of engineering service requests (ESRs) which is the
process used for performing engineering work. These are design
change (DC), configuration change (CC), and engineering
disposition (ED) ESRs. Design change ESRs were defined as a
change which affects the design input of a system, structure, or
component (SSC), while a configuration change was a change to a
SSC which does not change the design inputs. Engineering
disposition ESR were used to supply information and did not
produce design output documents or change any SSC. ESRs
designated as design change ESRs require design verification to
meet the requirements of 10 CFR 50 Appendix B, Criterion III, ANSI
N45.2.11, and Regulatory Guide 1.64. ESRs designated as
configuration changes require an engineering review, instead of a
design verification. The engineering review, as defined.by CP&L
procedure EGR-NGGC-003 does not meet the in-depth review and
independent review requirements as defined by Appendix B,
Criterion III, ANSI N45.2.11, and Regulatory Guide 1.64. Pending
further review of the licensee's engineering review requirements,
this issue was identified as URI 50-261/96-14-01, Review
Licensee's Design Verification Requirements.
c. Conclusions
With the exception of the issue identified in URI 50-261/96-14-01, the
inspectors concluded that the licensee's design change control
procedures complied with the requirements of 10 CFR 50.59, and 10 CFR
50, Appendix B, Criterion III.
However, the inspectors noted that
duplicate procedures exist which could possibly result in confusion in
the future and could result in potential design errors. Further, a
process was in place that used an engineering review in lieu of a design
verification for plant changes designated as configuration changes only.
This practice does not appear to meet the requirements of 10 CFR
Appendix B and another regulatory guidance.
E1.2 Review of Design Changes and Modification Packages
a. Inspection Scope (37550)
The inspectors reviewed the design change and modification packages to:
(1)
determine the adequacy of the safety evaluation screening and the 10
CFR 50.59 safety evaluations; (2) verify that the modifications were
reviewed and approved in accordance with Technical Specifications and
administrative controls; (3) verify that applicable design bases were
included; (4) verify that Updated Final Safety Analysis Report
requirements were met;
(5) verify that both installation testing and
post modification testing requirements were specified so that adequate
testing would be accomplished.
22
b. Observations and Findings
The inspectors reviewed the following design change and modification
packages:
ESR-9500870:
PORV Block Valve Stem Replacement,
.ESR-9500782:
Resolve GIP Issues for RFO 17,
ESR-9600579:
MSIV Evaluation,
ESR-9600538:
Functional and Structural
Evaluation, and,
ESR-9600375:
Provide Input on EDG Fuel Oil Storage Tank
Level.
The inspectors found that the modification packages had been
reviewed and approved in accordance with the licensee's design
control procedures and that the format and content of the
modification packages was consistent with the design control
procedure. The quality of the modification packages was good.
c. Conclusions
In general, the modification packages were judged to be of good
quality and would not degrade plant performance, safety, or
reliability. The modification packages contained sufficient
specifications, drawings and procedures to be properly installed
and tested. The licensee's 10 CFR 50.59 evaluations were completed
in accordance with NRC requirements.
E2
Engineering Support of Facilities and Equipment
a. Inspection Scope (37550)
The inspectors performed a walkdown inspection of safety-related
structures and reviewed engineering involvement in maintaining
material condition of safety-related structures, systems, and
components.
b. Observations and Findings
The initial point of contact for maintenance personnel to obtain
engineering assistance is the RESS rapid response team. The
purpose of the rapid response team is to respond to emergent
issues, and to provide engineering assistance to plant personnel.
The rapid response team is involved directly in day-to-day
maintenance activities. The rapid response team has been recently
reorganized to include the predictive maintenance, preventative
maintenance, and thermal performance programs.
23
The inspectors, accompanied by a licensee engineer from the rapid
response team, walked down the auxiliary, control, containment,
and fuel handling buildings and examined plant material condition
and the condition of plant equipment. During the walkdown, the
inspectors noted that plant material condition was good to
excellent. There was no evidence of degraded operating equipment;
however, a few minor deficiencies were observed in containment
building. These included the presence of a rag, piece of duct
tape, pieces of string and other miscellaneous loose items in the
containment. Minor damage to the sheet metal waterproof barrier
covering the containment liner plate insulation was also noted.
The damage to the waterproof barrier included damaged/buckled
sheet metal panels and deteriorated caulking between numerous
sections of sheet metal and at the floor line. EBASCO
specification No. CPL-R2-M-18 and drawing G-190343 required the
liner insulation to be positively sealed against moisture. The
specification also required periodic monitoring of the presence of
moisture between the insulation and the liner plate. The purpose
of monitoring for moisture is to prevent corrosion of the liner
plate.
Discussions with licensee engineers disclosed that problems with
the sheet metal panels and containment liner corrosion were
documented in Engineering Evaluation EE-93-159 which was closed in
May, 1994. Some corrosion damage to the containment liner plate
was observed and evaluated. The inspectors reviewed the general
required actions list to close the engineering evaluation. These
included issuing of a work request (number WR 94-AHRZ1) which
required removal of additional panels for inspection of the liner
for potential corrosion during the next scheduled refueling outage
(refueling outage 16).
The inspectors reviewed the work request
and noted that it had been canceled (deleted) without the required
inspections being performed. Licensee engineers were unable to
provide any justification for not performing the liner
plate/insulation inspections. Paragraph 5.14.5.1 of CP&L
procedure MOD-001 Engineering Evaluation Rev. 1 requires the
engineering evaluation (EE) to be revised if the intent of the
required actions to close the EE are changed. Paragraph 5.9.2 of
CP&L procedure MMM-003 Maintenance Work Request requires the
reason for cancellation of a work request to be documented on the
work request. Failure to revise the engineering evaluation when
the intent of the required actions (perform additional inspections
of the containment vessel liner plate for corrosion damage) were
changed, and failure to document the reason for cancellation of
the work request was identified to the licensee as a violation of
10CFR50, Appendix B, Criterion V, failure to follow procedures.
This issue was identified as Violation 50-261/96-14-02, Failure to
Complete Corrective Actions to Resolve Containment Liner Corrosion
per Engineering Evaluation. The licensee initiated Condition
Report No. 96-03023 to followup on the condition of the liner
insulation and degraded panels.
24
c. Conclusions
A violation was identified regarding failure to follow procedure
in canceling corrective actions required by an engineering
evaluation. However, the inspectors concluded that licensee
engineers are actively involved in day-to-day support of plant
equipment. The material condition of the plant and equipment is
good to excellent.
E5
Training and Qualification of System Engineers
a. Inspection Scope (37550)
The inspectors reviewed the licensee's program for training and
qualification of plant (system) engineering personnel to assure
the quality of engineering training.
b. Observations and Findings
The inspectors reviewed the following procedures which specify the
requirements for training of engineering personnel:
Training Program Procedure TPP-213, Engineering Support
Personnel Training Program, Rev. 5, dated July 17, 1996
Technical Support Management Manual TMM-105, System Engineer
Certification Procedure, Rev. 2, dated April 20, 1996
These procedures establish the guidelines for training and
certification of personnel in the Robinson Engineering Support
Section (RESS).
Individual training schedules have been developed
for all RESS engineers which document required training, training
completed to date, and the scheduled completion dates for any
remaining training. The training includes initial orientation
training and position specific training for each engineer assigned
to RESS. After completion of their required training, the
engineers will receive certification as plant engineers. The
plant engineers will be responsible for both system design and
operation/maintenance. The inspectors reviewed the training
guides for individual engineers and noted that almost all
engineers are scheduled to be fully qualified as plant engineers
by June 1997.
c. Conclusions
The inspectors concluded that the licensee's program for training
and qualification of system engineers meets NRC requirements.
25
E7
Quality Assurance in Engineering Activities
E7.1 Special UFSAR Review
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 inspection
discussed in this report, the inspectors reviewed selected portions of
the UFSAR that related to the areas inspected. The inspectors 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 (37551 and 92903)
E8.1 (Closed) LER 50-261/94-18-01, -02, Technical Specification 3.0:
Containment Spray System: These LERs involved the licensee's entries
into TS 3.0 to sample the concentration of sodium hydroxide downstream
of the Containment Spray System (CSS) Spray Additive Tank (SAT)
discharge valves. The purpose of the sampling was to verify that sodium
hydroxide from the SAT was not leaking past the discharge valves. The
sample was obtained from a drain valve on the SAT eductor line after
aligning a 2-inch Refueling Water Storage Tank (RWST) line to the SAT
eductor piping. The licensee performed this sampling in conjunction
with the performance of CSS Inservice pump testing. In August 1994, the
licensee recognized that this sampling alignment resulted in the
potential inoperability of both trains of CSS since water from the
2-inch RWST line would be educted along with sodium hydroxide from the
SAT. This could result in reduced concentration of sodium hydroxide to
the suction of both CSS pumps should -a
CSS actuation signal occur.
Sodium hydroxide is used in the CSS to remove Iodine from the
containment atmosphere during design basis accidents. The licensee
determined that this sampling lineup potentially rendered the Iodine
removal function of the CSS inoperable, since the design concentration
of sodium hydroxide could not be assured to CSS pumps. As a result of
the potential inoperability of both trains of CSS, the licensee entered
the action requirement of TS 3.0 during the pump testing and sampling
evolutions until this issue could be resolved.
The licensee's corrective actions included performing an evaluation to
determine the effect of delaying the addition of sodium hydroxide to the
containment atmosphere on the control room operator 30-day thyroid dose
following an accident. The inspectors reviewed the results of this
evaluation which were documented in Calculation RNP-M/MECH-1592, Rev. 0.
General Design Criteria (GDC) 19 limits the 30-day thyroid dose to the
control room operators to 30 Rem. The results of the licensee's
calculation indicated that sodium hydroxide could be delayed by as much
as 6 minutes without exceeding the 30 Rem regulatory limit. However,
this delay would result in a slight increase from the previously
calculated control room operator dose of 27.3 Rem to 29.7 Rem. At the
end of the inspection period, the inspectors had not completed a
26
detailed review of the methodology used in the calculation to ensure
that it was acceptable. Pending completion of this review, this item
will be tracked as Part 1 of Unresolved Item (URI) 50-261/96-14-03:
Review Aspects of Containment Spray Additive Tank Eductor Line Sampling.
Using the results from the revised control room operator dose
calculation, the licensee determined that continued sampling using this
alignment could be performed without rendering the Iodine removal
function of the CSS inoperable as long as the SAT could be returned to
its normal alignment within 6 minutes. The licensee revised the CSS
pump test procedure, as well as other procedures where the sampling was
conducted, to add procedural controls for returning the SAT to its
normal alignment within 6 minutes of a CSS actuation signal.
The
inspectors reviewed Operations Surveillance Test (OST)-352, Containment
Spray Pump Test, Rev. 31, dated January 12, 1995, which incorporated
these changes. The inspectors determined that detailed guidance was
added to ensure that manual operator actions were completed to realign
the SAT to its normal lineup should a CSS actuation signal occur. The
inspectors verified that these actions were performed properly on
December 17, 1996, while witnessing the inservice testing of the "B"
pump.
Upon review of the 10CFR50.59 evaluation for OST-352, Rev. 31. the
inspectors questioned whether it was adequate. Specifically, the
inspectors questioned whether the change to the procedure constituted an
unreviewed safety question which would require NRC review and approval
prior to implementation. The inspector noted that this change might be
considered an unreviewed safety from several perspectives. First, based
on review of the UFSAR and TSs, the sampling evolution was not required
by. nor discussed in either of these licensing documents. Based on
this, the evolution might be considered a new "test" (i.e., leak check
of the SAT discharge isolation valves), which would make the change an
unreviewed safety question. Secondly, the licensee stated in their
evaluation that the change did not create the possibility of a
malfunction of equipment important to safety of a different type than
any evaluated previously in the Safety Analysis Report (SAR). The
inspectors.disagreed with this conclusion since failure of the operator
to close the manual RWST valve and failure of this manual valve to open
due to mechanical failure both introduce new failure modes which could
result in an increase in the probability of malfunction of the CSS
Iodine removal function. Thirdly, the licensee stated that the change
did not reduce the margin of safety as defined in the basis of the TSs
or increase the consequences of an accident evaluated previously in the
SAR. The inspectors disagreed with these conclusions since the
licensee's recalculation of control room operator dose showed that there
would be an increase from the current control room operator dose value
that was referenced in the SAR as a result of allowing a 6 minute delay
in sodium hydroxide to the containment atmosphere. At the end of the
report period, the inspectors were still discussing with the licensee
and NRR personnel specifics with regard to the adequacy of this
10CFR50.59 evaluation. The inspectors determined that further NRC
review of this issue was necessary, as such, this issue will be tracked
27
as Part 2 of URI 50-261/96-14-03: Review Aspects of Containment Spray
Additive Tank Eductor Line Sampling.
The inspectors discussed with engineering personnel the origin of the
SAT eductor line sampling evolution. The licensee initiated the
sampling evolutions in 1988 after it was identified that one of the SAT
discharge valves leaked by causing the contamination of sodium hydroxide
in the RWST and RCS. The licensee determined that continued sampling
was necessary to prevent recurrence of this incident. However, based on
inspector discussions with engineering personnel, they could not recall
any further incidents since 1988-89 where sample results had identified
similar leakage. This was attributed in part to repairs performed on
the SAT discharge valves which improved their leak tightness. The
inspectors questioned whether the licensee had evaluated other sampling
options or configurations and if it was still considered prudent to
perform this sampling evolution using such an undesirable configuration.
At the end of the report period, the inspectors were continuing
discussions with the licensee on the justification for continuing with
the present sampling configuration in lieu of other options which did
not challenge the operability of the CSS iodine removal function. This
will be tracked as Part 3 of URI 50-261/96-14-03: Review Aspects of
Containment Spray Additive Tank Eductor Line Sampling.
The LERs were closed based on tracking the issues identified from this
review via URI 50-261/96-14-03.
E8.2
(Closed) LER 50-261/95-02-00, Inadvertent Main Steam Isolation Valve
Closure During Plant Cooldown: On June 6, 1995, the unit was in Hot
Shutdown (231oF) and reactor coolant temperature decreasing to Cold
Shutdown (<2120F). A Main Steam Isolation signal was received which
caused an automatic closure of the Main Steam Isolation Valves (MSIVs),
which are Engineered Safety Features (ESFs). CR 95-01501 was initiated
to follow this item.
Investigation revealed that high steam flow bistables actuated with zero
steam flow indicated on the RTGB. The high steam flow signal was
created by a loss of water in the steam flow transmitter sensing line
which actuated the high steam flow bistables. An inspection of the
sensing line revealed that a portion of the line had been insulated
preventing radiant and convective heat loss. As a result, the water in
the sensing line flashed to steam as the operators decreased secondary
pressure to cool the plant.
The insulation was removed from the flow element ring headers of all
three steam generators to allow radiant and convective heat loss to
sustain condensation in the sensing lines during low steam line
temperature and pressure conditions. Labels were affixed to these lines
which specify that the lines should not be insulated. The licensee
revised General Procedure (GP)-007, Plant Cooldown From Hot Shutdown to
Cold Shutdown, in Revision 37 to preclude having the plant in the
condition-to receive these spurious actuations of the MSIVs.
28
The inspectors verified the placement of the signs on the sensing lines.
GP-007, Revision 37 was reviewed and the inspectors noted that Section
5.2.39 was changed to read reactor coolant temperature rather than steam
generator pressure and Section 5.2.39.8.d was added to close the MSIVs.
The inspectors reviewed GP-007, Revision 41 and verified that it
contains the same information. This item is closed.
E8.3
(Closed) LER 50-261/95-04-00, Reactor Trip Due To Main Steam Isolation
Valve Closure:
On June 30, 1995, a reactor trip occurred with the unit
operating at 100% power, as the result of an inadvertent closure of the
"B" Main Steam Isolation Valve (MSIV), MS-V1-3B. The closure of MS-V1
3B resulted in a Reactor Protection System (RPS) reactor trip signal
from Low-Low "B" Steam Generator Level.
The operators placed the unit
in Hot Shutdown in accordance with procedures. CR 95-01660 was
initiated to follow this event.
The followup investigation revealed that the MSIV closure was caused by
a loose fuse block fuse clip for the fuse that supplies control power to
the MSIVs actuator "open" air supply solenoid valve. A loss of power to
the solenoid valve occurred while an operator was reinstalling a fuse in
another circuit on the same fuse block. A second loose fuse clip was
identified during a panel walkdown.
The inspectors determined that on October 9, 1993, the licensee
experienced a short circuit between fuse clips which resulted in arcing
in a fuse block in the MSIV control cabinet. CR 93-00193 was initiated
to document the event. Corrective actions were to replace the fuse
blocks with a newer, more rigid design and review the event with the
operators. Engineering Service Request (ESR) 94-00543 was issued to
evaluate an improved design. Work Request (WR) 94-AHFQ1 was issued to
replace some of the older design fuse blocks. The work was scheduled
for Refueling Outage (RFO)-16 but subsequently deferred to RFO-17.
The licensee's corrective actions for the loose fuse clips included
replacing all the old design fuse blocks in accordance with the
resolution of ESR 94-00543 and reviewing the event with Operations and
Maintenance personnel.
WR 94-AHFQ1 was canceled and WRs 95-ALAJ1, 95
ALAK1, and 95-ALALl were issued to perform the work.
The inspectors reviewed CRs 93-00193 and 95-01660; training records;
ESR94-00543; and WRs 94-AHFQ1, 95-ALAJi, 95-ALAK, and 95-ALAL1. They
verified that the event had been reviewed with Operations and
Maintenance personnel. The review of the WRs which replaced the fuse
blocks indicated that the work had been completed between September 19
and 25, 1995. The licensee completed their corrective actions and this
item is closed.
29
IV. Plant Support
P2
Status of EP Facilities, Equipment, and Resources
P2.1 Facility Inspection
a. Inspection Scope (82701)
The inspectors toured the facilities to determine whether key facilities
and equipment were adequately equipped and maintained.
b. Observations and Findings
During the training drill on November 12, 1996, the inspectors toured
the Technical Support Center (TSC), Operational Support Center (OSC),
and Emergency Operations Facility (EOF) and observed the licensee's
facilities and equipment being utilize during the drill.
The
Telephones, fax machines, Safety Parameter Display System (SPDS),
Emergency Response Facility Information System (ERFIS), Dose Assessment
Computer, and the Emergency Notification Network (ENN) phone system
operated properly.
The inspectors reviewed surveillance records of emergency supplies and
equipment required in EPPRO-02, Maintenance and Testing. All
surveillances were performed at the required frequencies. The
documentation of the surveillances indicated that the licensee
maintained good control of their emergency supplies and that the
emergency equipment was reliable. No discrepancies were noted by the
inspectors. No significant changes had been made to the facilities.
c. Conclusion
The inspectors concluded that the facilities were well equipped and the
licensee maintained the facilities and equipment in a good level of
operational readiness.
P2.2 Emergency Response Dose Assessment Capabilities
a. Inspection Scope (82701)
Dose Assessment Capabilities were inspected to verify that the licensee
maintained continuous dose assessment capabilities which used real time
meteorological and radiological data.
b. Observations and Findings
The licensee's dose assessment program was on the Emergency Response
Facility Information System (ERFIS) computer. The inspector observed
the licensee's dose assessment program in operation during the training
drill.
The program was a straight line gaussian calculation which used
30
real time radiological and meteorological data which was automatically
updated and input into the program.
The licensee maintained Emergency Plan Implementing Procedure, EPRAD-03,
Dose Projection, for performing manual dose calculations. All licensed
operators were trained in both the computer and EPRAD-03 to perform
on-shift dose assessment.
c. Conclusion
The inspectors concluded that the licensees's dose assessment
capabilities were satisfactory and that sufficient personnel were
trained to perform onshift dose assessment using real time
meteorological and radiological data.
P2.3 Public Alert And Notification Capabilities
a. Inspection Scope (82701)
This area was inspected to review the licensee's method of notifying the
public in the event of an emergency, the notification test frequency,
and notification test data.
b. Observations and Findings
The licensee maintained 45 sirens within the Emergency Preparedness Zone
(EPZ) for their public alert and notification system. The licensee
performed a bi-weekly silent test, quarterly growl test, and an annual
sounding of the sirens. The 1995 Robinson Nuclear Plant siren
availability report summary indicated a siren availability of 98.5
percent.
The inspectors reviewed documentation of Robinson's siren testing from
October 1995, through October 1996 and determined that the sirens had
been tested at the required frequencies.
c. Conclusion
The inspectors concluded that the operational status and maintenance of
the siren system was good.
P3
EP Procedures and Documentation
P3.1 Maintenance of the Emergency Plan and Procedures
a. Inspection Scope (82701)
The inspectors reviewed the licensee's process for making changes to the
Emergency Plan and Plan Emergency Procedures (PEPs). The inspectors
reviewed changes to the PEPs to verify that the changes were in
agreement with and.implemented the Emergency Plan.
31
b. Observations and Findings
The inspectors compared the instrumentation ranges and nomenclature
identified in the Emergency Action Levels (EALs) to the installed
instrumentation in the Control Room. In the comparison, no
inconsistencies in nomenclature or in the use of terms were identified
by the inspectors. The inspectors verified that the EALs were reviewed
and agreed upon by the State.
The licensee had performed a detailed "word by word" annual review of
their Emergency Plan in Revision 34. Concurrently with Revision 34, the
licensee completely reviewed and re-organized their PEP's. In the
procedure reorganization, procedure identifiers were changed from PEP to
EP plus the facility or function identifier.
The inspectors reviewed Administrative Procedure AP-22, "Document Change
Procedures," the licensee's process for making changes to their Plan and
Plan Emergency Procedures (PEP), Plant Licensing Procedure PLP-032,
10 CFR 50.59 Reviews of Changes, Tests And Experiments, and the
licensee's re-organized emergency procedures. The inspector determined
that the re-organized procedures were in agreement with the plan, and
the licensee had followed AP-22 and PLP-32 in making the plan and
procedure changes.
The inspectors viewed the emergency procedure changes as a excellent
organizational and ergonomic improvement of the EPs.
The inspectors reviewed the change matrix associated with the EP's
re-organization and the change packages associated with the individual
EP changes and determined that they were satisfactory and followed AP-22
and PLP-032.
The process for making changes to the PEPs and the Emergency Plan met
the intent of 10 CFR 50.54(q).
All of the changes reviewed were approved and distributed in accordance
with the licensee's procedures. The NRC was notified within 30 days of
all changes as required in 10 CFR 50 Appendix E.
Controlled volumes of the EPs in the Technical Support Center (TSC),
Emergency Operations Facility, and Operational Support Center (OSC) were
reviewed and determine to be maintained up to date.
The inspectors reviewed the letters of agreement identified in
Appendix 6.2, "Agreement Letters", of the Emergency Plan and verified
that they were up-to-date.
c. Conclusion
The inspectors concluded that the licensee's Plan and procedure change
review process was thorough and met the requirements of 10 CFR 50.54(q).
The inspectors viewed the new designation and reorganization of the
32
emergency procedures as a excellent organizational and ergonomic
improvement.
P3.2 Use Of The Emergency Implementing Procedures
a. Inspection Scope (82701)
The inspectors reviewed the licensee's event declarations to verify that
each event was properly classified and the Emergency Implementing
Procedures were properly implemented.
b. Observations and Findings
Review of the licensee's 10 CFR 50.72 reports since September 1995,
revealed that the licensee had made one event declaration:
May 13, 1996, a Unusual event was declared due to a fire in the
mechanical equipment room of the chemistry building lasting
greater than ten minutes.
c. Conclusion
The inspectors review concluded that the licensee properly classified
the event.
P5
Staff Training and Qualification in EP
P5.1 Drill Observation
a. Inspection Scope (82701)
Observe a licensee training drill, their preparation, degree of play,
and critique.
b. Observations and Findings
Records reviewed showed that each of the five shift operating crews
drilled with one of the emergency response team in each of the three
cycles of their annual retraining. As a result of the licensee
combining licensed operator requalification training and emergency
preparedness training, the licensee plans to perform fifteen emergency
response drills this year.
The inspectors observed an Emergency Preparedness drill on November 19,
1996. The drill was observed as a training evolution rather than being
evaluated. The licensee had committed almost as much work in the
drill's planning and details as licensee's normally do for an evaluated
exercise. Scenario booklets were developed, pre-drill evaluator briefs
and post drill critiques were held. All of the facilities were
activated and functioned properly. As part of the scenario, the OSC was
relocated when the facilities habitability was challenged. The
licensee's critique following the scenario was objective. Issue's
33
identified during the critique were documented by the licensee as
improvement items or corrective actions, particularly in the Joint
Information Center.
c. Conclusion
The inspector concluded the licensee's combining of licensed operator
requalification training and emergency preparedness training was a
strength for the emergency preparedness program.
P5.2 Training of Emergency Response Personnel
a. Inspection Scope (82701)
The inspectors reviewed the Emergency Response Training Program and the
verified that emergency response personnel were initially trained and
retrained annually to maintain their training current.
b. Observations and Findings
The licensee's Emergency Preparedness training program EPPRO-03,
Training and Qualification was rewritten in October 1996. The inspector
interviewed staff personnel responsible for rewriting the program and
reviewed the changes between the old and new program. The new program
consolidated or reorganize lesson plans and course requirements for the
different positions. In the.two programs the same level of specific
information was being taught to the member, but the scope of information
presented had been expanded. The inspectors concluded that the new
program provided more flexibility to the licensee in cross training
Emergency Response Organization personnel and provided-broader training
for an individual ERO member. The inspector viewed the new program as a
program improvement.
Emergency Preparedness training consisted of initial training, annual
retraining, and continuing training. Initial training consisted of
respirator qualification if required, classroom instruction and testing,
reading the required procedures, job list, and observation or evaluation
of performance in drill or exercise. Annual retaining consisted of
reading the required procedures, job list and observation or evaluation
of performance in drill or exercise. Continuing training consisted of
classroom discussion prior to drills base upon training needs identified
during drills/exercise critiques, student feedback, and/or related
current industry events.
The inspectors reviewed the lesson plans and exams for the Overview,
TSC, and OSC. The inspectors noted from the review that the lesson
plans were organized and contained the appropriate depth of material.
The exams could be improved upon. The exams were multiple choice and
contained negative learning questions (were the student is asked to
chose the wrong answer), poor distractor (obvious wrong answers), and
instances in which the question asked was the answer to the preceding
question. The inspectors discussed the exams with the licensee. The
34
licensee stated that they intended to re-write the exams as part to the
program upgrade.
The status of ERO training was reviewed by randomly selecting ten
individuals from the ERO and reviewing their training records. The
training for all of the individuals reviewed by the inspectors was
up-to-date. The licensee continued to maintain ERO training in
accordance with their Emergency Plan and EPPRO-03.
c. Conclusion
The inspectors concluded that the licensee was effectively implementing
the ERO training program.
P5.3 Emergency Planning Drills
a. Inspection Scope (82701)
The inspectors compared the licensee's drill commitments to the actual
drills performed, and evaluated the quality of those drills.
b. Observations and Findings
Three scenarios were used in fifteen drills during the year. One
scenarios was used for each of the three cycles of licensed operator
training.
The inspectors reviewed the documentation from six of the licensee's
drills. The scenarios were challenging, and the licensee's evaluation or
critiques of the drills were objective. The drill comments were well
documented, tracked, and resolved.
The inspectors reviewed the licensee's matrix of their exercise
elements. The matrix identified required exercise elements and the last
time the element was exercised. The matrix corresponded to the elements
identified in the guidance of NUREG-0654, "Criteria for Preparation and
Evaluation of Radiological Emergency Response Plans and Nuclear Power
Plants" and NUREG-0737, "Clarification of TMI Action Plan Requirements."
As a minimum, each element was to be exercised once every six years.
All exercise element requirements were currently satisfied.
c. Conclusion
The license's conduct of drills exceeded their commitment in their
Emergency Plan. The combining of licensed operator retraining with
emergency preparedness drills, the number of drills performed during the
year, the level of participation, and the feedback provided to the
players was a strength.
35
P6
EP Organization and Administration
a. Inspection Scope (82701)
The inspectors reviewed this area to determine if any changes in
management or personnel had occurred which would effect the efficiency
or performance of the Emergency Response Organization.
b. Observations and Findings
The manager responsible for the emergency preparedness programs
direction and support recently changed. No significant changes had
occurred which negatively affected the performance or maintenance of the
Emergency Preparedness Program as a result of that change. During the
inspection, the inspectors observed several areas that indicate that
emergency preparedness was receiving strong management support.
Examples were:
Upgrading of the siren system,
Personnel and time committed to drills and training,
Rewriting or reorganizing of the emergency procedures, and
Rewriting or reorganizing of the training program.
c. Conclusion
No changes occurred had which affected the performance of maintenance of
the Emergency Preparedness Program. Emergency Preparedness was
receiving strong management support.
P7
Quality Assurance of EP Activities
P7.1 Required 10 CFR 50.54(t) Audit Of Emergency Preparedness Program
a. Inspection Scope (82701)
The inspectors reviewed this area to assess the quality of the required
audit, the qualification of the auditors, and verify that the audit met
the requirements of 10 CFR 50.54(t).
b. Observations and Findings
The inspector reviewed Audit Report R-EP-95-02 and draft Audit Report
R-EP-96-01. Audit Report R-EP-95-02 was a six person team audit
conducted in November 1995 and identified one strength, one issue, and
three weaknesses. Audit Report R-EP-96-01 was a six person team audit
conducted in October 1996 and identified one potential issue, and one
potential weakness.
36
After reviewing audit report R-EP-95-02 and draft audit report
R-EP-96-01, the inspector reviewed the assessment outlines that had been
developed prior to each of the audits. The inspector noted that the
outlines were detailed and well organized. Audit areas were clearly
defined and the elements used to audit the different areas were detailed
and of sufficient scope to perform a thorough audit of the area.
After reviewing the audit summaries and assessment outlines, the
inspectors interviewed the Lead Auditor and reviewed the auditor's
elements and notes. The inspectors concluded from the interview and
review of the auditor's notes that the scope and depth of the audit
satisfactorily covered the elements required by 10 CFR 50.54(t) for an
annual independent audit of the Emergency Preparedness program.
The inspectors reviewed the qualification and training, of the auditors
and lead auditor. The auditor's qualifications met the licensee's
Quality Audit program requirements.
c. Conclusion
The inspectors concluded that the auditors' qualifications were good,
and the scope of the audit was good. The audit satisfied the 10 CFR
50.54(t) requirement for an annual independent audit of the EP program.
P7.2 Licensee's Corrective Action Program For Drill Comments and Issues
a. Inspection Scope (82701)
The area was inspected to evaluate the licensee's corrective action to
comments and issues identified in their drills.
b. Observations and Findings
The inspectors reviewed findings from audits, inspection reports,
and exercise and drill critiques. These findings were compared to
the issues identified in the licensee's CAP.
The inspectors selected eight completed packages from the emergency
preparedness CAP list for a more detailed review. The packages were
reviewed to evaluate the licensee's responsiveness to resolving issues
and the adequacy of their closure. From the packages reviewed, the
inspectors determined that the licensee was responsive in addressing
emergency preparedness issues and that the closure resolutions were
adequate.
The licensee stated that they maintained a separate emergency
preparedness tracking list for emergency preparedness issues (drill
critiques) which do not rise to the level of the CAP program. The
licensee stated that they were transferring the list from a "hard copy"
to a computer based list, and that while upgrading the site's computer
systems, the program was lost. The licensee was in the process of
restoring their lower level tracking system. The inspectors selected
37
several issues that had been identified in drill critiques and were not
in the CAP program, and verified they had been corrected.
Documentation had been identified as concerns in a previous NRC
inspection and in Audit Report R-EP-95-02. Other examples of missing
documentation note by the inspector during this inspection were:
First semi-annual PASS drill,
Two letters of agreement, and
Corrected pages in procedure change form documentation.
c. Conclusions
The emergency preparedness organization was adequately tracking and
resolving upper tiered issues through the CAP program. The licensee's
loss of their lower level tracking system contributed to continuing
problems with documentation. Control of documentation continues to be a
concern.
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 January 6, 1997.
Interim exits were conducted on November 22 and 27, and December 6,
1996. The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during
the inspection should be considered proprietary. No proprietary
information was identified.
38
PARTIAL LIST OF PERSONS CONTACTED
Licensee
H. Chernoff, Supervisor, Licensing/Regulatory Programs
J. Clements, Manager, Site Support Services
D. Crook, Senior Specialist, Licensing/Regulatory Compliance
C. Hinnant, Vice President, Robinson Nuclear Plant
J. Keenan, Director, Site Operations
B. Meyer, Manager, Operations
G. Miller, Manager, Robinson Engineering Support Services
R. Moore, Manager, Outages/Scheduling
J. Moyer, Manager, Maintenance
D. Stoddard, Supervisor, Operating Experience Assessment
R. Warden, Manager, Nuclear Assessment Section
T. Wilkerson, Manager, Environmental Control
D. Young, General Manager, Robinson Plant
NRC
B. Desai, Senior Resident Inspector
J. Zeiler, Acting Senior Resident Inspector
P. Byron, Resident Inspector, Surry
39
INSPECTION PROCEDURES USED
IP 37550:
Engineering
IP 37551:
Onsite Engineering
IP 40500:
Evaluation of Licensee Self-Assessment Capability
IP 61726:
Surveillance Observations
IP 62707:
Maintenance Observation
IP 71707:
Plant Operations
IP 82701:
Operational Status Of The Emergency Preparedness Program
IP 92901:
Followup - Operations
IP 92902:
Followup - Maintenance
IP 92903:
Followup - Engineering
ITEMS OPENED, CLOSED, AND DISCUSSED
Opene
Typ
Item Number
Status
Description and Reference
50-261/96-14-01
Open
Review Licensee's Design Verification
Requirements (Section E1.1)
50-261/96-14-02
Open
Failure to Complete Corrective Actions to
Resolve Containment Liner Corrosion per
Engineering Evaluation (Section E2)
50-261/96-14-03
Open
Review Aspects of Containment Spray
Additive Tank Eductor Line Sampling
(Section E8.1)
Closed
jp Item Number
Status
Description and Reference
50-261/95-21-01
Closed
Operator Failure To Monitor Plant Status
(Section 08.1)
50-261/95-27-01
Closed
Inadequate Clearance Results In Unexpected
Emergency Diesel Start (Section 08.2)
50-261/96-01-01
Closed
Auxiliary Feedwater System Valve
Misalignment (Section 08.3)
50-261/95-19-05
Closed
RHR Pump Start Due to Troubleshooting
(Section M8.1)
LER
50-261/95-06-00
Closed
Technical Specifications Violation Due To
Failure To Meet Minimum Degree Of
Redundancy (Section M8.2)
40
LER
50-261/95-07-00
Closed
Condition Prohibited By Technical
Specifications Due To Failure To Meet
Minimum Degree Of Redundancy (Section
M8.2)
LER
50-261/95-07-01
Closed
Condition Prohibited By Technical
Specifications Due To Failure To Meet
Minimum Degree Of Redundancy (Section
M8.2)
LER
50-261/95-08-00
Closed
Condition Prohibited By Technical
Specifications Due To Failure To Meet
Minimum Degree Of Redundancy (Section
M8.2)
LER
50-261/94-18-01
Closed
Technical Specification 3.0: Containment
Spray System (Section E8.1)
LER
50-261/94-18-02
Closed
Technical Specification 3.0: Containment
Spray System (Section E8.1)
LER
50-261/95-02-00
Closed
Inadvertent Main Steam Isolation Valve
Closure During Plant Cooldown (Section
E8.2)
LER
50-261/95-04-00
Closed
Reactor Trip Due To Main Steam Isolation
Valve Closure (Section E8.3)