ML14178A158
| ML14178A158 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 10/25/1991 |
| From: | Christensen H, Garner L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML14178A157 | List: |
| References | |
| 50-261-91-20, NUDOCS 9111220017 | |
| Download: ML14178A158 (15) | |
See also: IR 05000261/1991020
Text
RE~O
UNITED STATES
/0
NUCLEAR REGULATORY COMMISSION
REGION lI
0
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report No.:
50-261/91-20
Licensee:
Carolina Power and Light Company
P. 0. Box 1551
Raleigh, NC
27602
Docket No.:
50-261
License No.: DPR-23
Facility Name: H. B. Robinson
Inspection Conducted: September 7 -
October 11, 1991
Lead Inspector:
L. W. Garner, Senior Resident rspector
Ddte Signed
Other Inspector(s): K. R. Jury, Resident Inspector
Approved by:~ 6 (?L
oe
r.).
Christensen, Section Chief
Date Signed
Division of Reactor Projects
SUMMARY
Scope:
This routine, announced inspection was conducted in the areas of operational
safety verification, maintenance observation, onsite review committee
activities, engineered safety feature system walkdown, and followup.
Results:
An apparent violation was identified involving inadequate Engineering design
.control and interfaces (paragraph 5).
Three non-cited violations were identified involving: a security watchperson's
failure to perform an adequate personnel search; non-licensed operators
performing licensed operator duties; and a failure to provide adequate
procedures for performing Technical Specification surveillance testing
(paragraph 2).
An unresolved item was identified relating to Loss of Coolant Accident analyses
conformance with 10 CFR 50.46 requirements (paragraph 5).
Operator performance (i.e.,
command and control) was professional during two
reactor power reductions (paragraph 2)).
9111220017 911025
. ADOCK (,5000261
G
2
Immediate corrective actions taken in response to the OT Delta T issue were
timely and extensive (paragraph 5).
REPORT DETAILS
1. Persons Contacted
- R. Barnett, Manager, Outages and Modifications
- C. Baucom, Senior Specialist, Regulatory Compliance
- F. Bishop, Principal Engineer, Nuclear Assessment Department
- R. Chambers, Plant General Manager
- C. Dietz, Vice President, Robinson Nuclear Project
- D. Dixon, Manager, Control and Administration
- W. Gainey, Manager, Plant Support
- W. Jackson, Engineer, Technical Support
- J. Kloosterman, Manager, Regulatory Compliance
- A. Padgett, Manager, Environmental and Radiation Control
- M. Page, Manager, Technical Support
- R. Parsons, Manager, Robinson Engineering Support
- D. Stadler, Onsite Licensing Engineer, Nuclear Licensing
- R. Steele, Shift Supervisor, Operations
- A. Wallace, Acting Manager, Operations
- L. Williams, Manager, Emergency Preparedness, Security
Other licensee employees contacted included technicians,
operators,
mechanics, security force members, and office personnel.
- H. Christensen, Section Chief, Division of Reactor Projects was on site
October 9, 10,
and 11,
1991,
to meet with the resident inspectors and
plant management.
- Attended exit interview on October 11, 1991.
- Attended exit interview on October 21, 1991.
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2. Operational Safety Verification (71707)
The inspectors evaluated licensee activities to confirm that the facility
was being operated safely and in conformance with regulatory requirements.
These activities were confirmed by direct observation, facility tours,
interviews
and discussions with licensee personnel
and management,
verification of safety system status, and review of facility records.
To verify equipment operability and compliance with TS,
the inspectors
reviewed shift logs, Operation's records, data sheets, instrument traces,
and records of equipment malfunctions.
Through work observations and
discussions with Operations staff members,
the inspectors verified the
staff was knowledgeable of plant conditions, responded properly to alarms,
adhered to procedures and applicable administrative controls, cognizant of
2
in-progress surveillance and maintenance activities, and aware of
inoperable equipment status.
The inspectors- performed channel
verifications and reviewed component status and safety-related parameters
to verify conformance with TS.
Shift changes were observed, verifying
that system status continuity was maintained and that proper control room
staffing existed.
Access to the control
room was controlled and
operations personnel carried out their assigned duties in an effective
manner. Control room demeanor and communications were appropriate.
Plant tours and perimeter walkdowns were conducted to verify equipment
operability, assess the general condition of plant equipment,
and to
verify that radiological controls, fire protection controls, physical
protection controls,
and equipment tagging procedures were properly
implemented.
Non-Licensed Operators Standing Watch
On September 5, 1991, the licensee identified that two individuals who had
recently completed SRO training performed the duties of RO license
positions (stood watch) prior to receiving their NRC SRO licenses.
The
docket numbers for these individuals was telephonically transmitted on
August 19, 1991.
At that time, the licensee erroneously believed that a
docket number was sufficient basis to allow these individuals to stand
watch (i.e., docket number issuance was equivalent to license issuance).
One individual had an inactive RO license and was in the process of
license reactivation when he received his docket number. This individual
stood watch as RO and BOP operator on seven occasions prior to license
issuance.
The other individual was an "instant" SRO who was previously
licensed at another licensee facility (Shearon Harris).
He stood watch on
three occasions as RO and once as BOP operator prior to receiving his
license.
After recognizing this problem, the licensee immediately relieved the one
individual who was on shift. An ACR,91-317, was generated to document
and perform a root cause analysis on this problem.
Apparently, the
licensee believed the docket number to be sufficient documentation to
allow potential ROs or SROs who had taken and passed the NRC license
examination to stand watch.
Discussions were held between the licensee
and the Region II Operations Branch Chief to resolve this issue and to
discuss the historical basis for the licensee's position.
The licensee
was informed that ROs and SROs are not permitted.to perform licensed
duties before license issuance.
10 CFR 55.3 requires that a person must
be authorized by a license to perform the function of an operator or
senior operator.
10 CFR 55.53 (e) delineates the requirements to
reactivate a license.
Failure of these individuals to.meet the
requirements of 10 CFR 55 is a violation. However, this violation meets
the criteria specified in Section V.G.1. of the NRC Enforcement Policy (10
CFR 2, Appendix C) for not issuing a Notice of Violation and is not cited.
This violation is identified as an NCV: Non-Licensed Operators Performing
Licensed Operator Duties, 91-20-01.
7@
3
Inadequate Personnel Search
On September 12,
1991,
the inspector observed an inadequate personnel
search at PAP West.
The search was inadequate, in that, a watchperson
assigned to the metal detector did not perform a visual inspection of an
item which was not processed through the X-ray detector.
The inspector
questioned the watchperson and determined the watchperson was unaware of
what the unsearched item was.
The watchperson then stopped the employee
prior to him accessing the PA and searched the item.
The watchperson
determined that the item was permitted inside the PA.
After discussion of this event with security management, the licensee
performed a comprehensive investigation, took appropriate disciplinary
action, and provided emphasis (through a "Lessons Learned" memorandum) to
all security personnel on the necessity to follow procedures.
Security procedures require that all items or equipment be searched by
visual inspection or by processing through special purpose detectors.
The
watchperson's failure to perform the search as described above is a
violation.
However,
this violation meets the criteria specified in
Section V.A. of the NRC Enforcement Policy (10 CFR 2, Appendix C) for not
issuing a Notice of .Violation and is not cited.
This violation is
identified as an NCV: Failure To Perform An Adequate Personnel Search,
91-20-02.
Emergency TS Amendment Due To Inadequate Surveillance Testing
During internal electrical distribution system reviews on September 13,
1991, the licensee questioned whether or not each channel associated with
the loss of power load shed feature had been tested as required by TS
Table 3.5-3, item 3.a.
The licensee additionally questioned if
load
shedding upon a simulated loss of all-normal AC coincident with a safety
injection signal,
had been demonstrated as required by TS 4.6.1.2.
An
operability determination (91-20) was initiated to determine the status of
testing and compliance with TS requirements.
On September 14, based upon engineering reviews, the licensee determined
that the applicable TS surveillance requirements had not been fully
satisfied.
These reviews identified instances in which the ability of
both channels to initiate load shedding had not been tested. In addition,
breakers were identified which had not been demonstrated to open when a
load shed signal was initiated.
Upon the determination that these
surveillance requirements had not been properly implemented, the loss of
voltage instrument channels were declared inoperable (TS Table 3.5-3, item
3.a).
An 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to hot shutdown LCO was appropriately entered at 4:50
p.m. Based upon the circuit components known to have been tested and the
reliability of the components which were either not tested or still under
evaluation, the licensee determined that a high confidence level existed
that the loss of voltage instrumentation safety function would be
accomplished
if
called upon(i.e.,
the condition had minor safety
significance).
However, due to the complexity of developing a test
4
procedure, testing could not be performed prior to LCO expiration. Thus,
the licensee requested a Wavier of Compliance from Region II to determine
the feasibility of developing a test procedure which could be performed
with the plant on line and/or the need for emergency TS relief.
Regional
management, after consultation with NRR, agreed to a Waiver of Compliance
which authorized continued power operation until midnight on September 18.
A condition of the waiver was to train Operations personnel
on
compensatory actions which could be taken if
load shedding would fail to
occur.
The inspectors verified, through attending training sessions and
interviews with personnel, that the committed training was provided.
On September 16, Engineering recommended, and plant management concurred,
that on-line testing was not desirable.
Thus, emphasis was shifted to
emergency TS change development to allow continued operation until RO 14
or an outage of sufficient length to allow time for test procedure
development and performance.
On September 18,
per letter NLS-91-245,
the licensee submitted an
emergency request for license amendment.
Enclosure 5 of this letter
identified the circuit components and functions which were not fully
tested.
The
PNSC meetings which approved the emergency request for license
amendment is discussed in paragraph 5. A Waiver of Compliance was granted
on September 18, 1991, to allow continued operation pending NRC review and
approval of the emergency request. On September 27, 1991, the NRC issued
Amendment No. 136 to grant authorization to operate until testing can be
performed on, or no later than, RO 14.
The failure to perform surveillance testing as required by TS is a
violation.
A previous violation (90-11-01) was issued in June 1990 for
failure to take adequate corrective action to preclude inadequately
established surveillance procedures.
In response to this violation, a
program was initiated to ensure that established procedures adequately
implement instrumentation surveillance test procedures.
At the time of
discovery, this process had not yet been performed on the TS surveillance
requirements
in question.
The identification of this violation by
engineering personnel was considered a strength.
No violation is being
cited as the criteria of Section V.G.1 of the NRC Enforcement Policy (10
CFR 2, Appendix C) was met.
The violation is identified an an NCV:
Failure To Provide Adequate Procedures For Performing TS Surveillance
Testing, 91-20-03.
B Condensate Pump Motor Ground
On September 19, 1991, at 11:41 p.m., a 4160V switchgear ground alarm was
received on the RTGB.
Although I & C verified that the alarm input was
valid, there were not any other indications that a ground existed.
Additional troubleshooting early the following morning, revealed that the
4160V buss 4 ground device had actuated as indicated by closed relay
contacts; however,
the normal visual indicator, a red flag, did not drop.
5
Shortly after 9:00 a.m.,
smoke was smelled in the vicinity of the power
cable conduit associated with the B condensate pump motor. At 9:18 a.m.,
a reduction to 50 percent power was initiated to allow removal of the B
condensate pump. from service.
When the B condensate pump motor breaker
was opened, the ground alarm reset. Inspection of the field power cables
to the motor stabs revealed damage indicative of a current path in this
area (i.e., electrical short).
The motor windings were found to be
undamaged.
The motor was shipped offsite for repairs.
Shop inspection
revealed that a breakdown had occurred in the B phase stab's insulation
which had initiated a current pathway through the fiberglass stab holder
block to one of the stab holder block's. mounting bolts.
The damaged
components were replaced or repaired as necessary.
The motor was
re-installed, successfully tested, and returned to service on September
24, 1991.
Power escalation to 100 percent was initiated, but was delayed
due to repairs to a leaking relief valve on the 5B FW heater and the 6A FW
heater's level indicating column and level control valve.
Full power
operation resumed on September 26, 1991.
Investigation into the failure of the ground relay flag to actuate
disclosed that a design problem exists.
The amount of current which
activates the flag's positioning relay is determined by the high
resistance of the annunciator circuit.
Due to this high resistance, the
current was not sufficient to activate the relay. The licensee was in the
process of evaluating possible design changes to correct the condition, as
well as reviewing other-circuits to determine if similar conditions exist.
This is an IFI: Review Corrective Actions Associated With Failure Of A
Ground Relay Flag To Drop, 91-20-04.
Turbine Drain Line Steam Leak
On September 27,
1991,
a leak developed in the number 4 governor valve
drain line.
After consideration of possible on-line repairs, the licensee
decided to remove the unit from service to replace the affected line and
inspect similar lines from the other governor valves. Since repairs were
expected to require less than a day, reactor power was maintained at
approximately 0.01 microamperes as indicated on the intermediate range
power monitors.
The affected line and two others which had unacceptable
wall thinning, as determined by ultrasonic inspections, were replaced.
The unit was returned to service the next day and resumed 100 percent
power operation on September 29.
The line failure was attributed to
errosion.
The licensee is re-evaluating the
scope of their
errosion/corrosion program.
Both power reductions described above were witnessed by the inspectors.
The Operations staff demonstated good command and control during these
evolutions, as both power reductions were professionally performed without
incident.
Three non-cited violations were identified.
6
3. Monthly Maintenance Observation (62703)
The inspectors observed safety-related maintenance activities on systems
and components to ascertain that these activities were conducted in
accordance with TS,
approved procedures,
and appropriate industry codes
and standards.
The inspectors determined that these activities did not
violate LCOs and that required redundant components were operable. The
inspectors verified that required administrative, material,
testing,
radiological,
and fire prevention controls were adhered to.
In
particular, the inspectors observed/reviewed the following maintenance
activities:
CM-507
Emergency Diesel Lube Oil Strainer
Emergency Diesel Generator Inspection
Number 1
WR/JO 91-ALNAl
Exhaust Turbocharger Oil Leak
WR/JO 91-ALEMI
Air Receiver Relief Valve Replacement
WR/JO 91-FMA392
EDG B Compresser Oil Change
No violations or deviations were identified.
4. Onsite Review Committee (40500)
The inspectors evaluated certain activities of the PNSC to determine
whether the onsite review functions were conducted in accordance with TS
and other regulatory requirements. In particular, the inspectors attended
the September 16 and 17,
1991 PNSC meetings in which the request for a
Waiver of Compliance from the requirements of TS Table 3.5.3 and
surveillance requirement 4.6.1.2 was reviewed.
(See paragraph 2 for
details concerning this issue.)
During the September 16 meeting, the
inspectors observed that the PNSC members mixed their safety review
function with their management function.
The focus of this meeting
shifted from evaluating the safety implications (risk and potential
consequences) of the issue to improving the wording of the Waiver of
Compliance to maximize the probability it would be approved.
This was
manifested by the PNSC expending almost all of the two and one half hour
PNSC meeting in rewording and rewriting the proposed request for
regulatory relief.
The
PNSC recognized that another review would be
necessary and scheduled one for the next day. After the first meeting,
the inspectors expressed concerns about the conduct of the meeting with
plant management. The inspectors subsequently determined that even though
the potential scope of the problem was recognized on September 16,
the
degree to which various components had been tested, if at all, was not
known by the PNSC members.
Prior PNSC meetings,
both routine and
special, have typically been well conducted with the appropriate emphasis
on safety. The September 17, 1991 meeting which approved the request for
Waiver of Compliance was more typical of the manner in which PNSC meetings
have been conducted. On September 27, 1991, the inspectors met with the
Plant General Manager and the Regulatory Compliance Manager to discuss
concerns with the PNSC's performance.
The inspectors expressed concern
about the focus of the September 16 PNSC meeting, the potential conflict
7
due to possible ownership by the PNSC for a document which the PNSC had
essentially generated, and the lack of a total understanding of what had
not been tested (i.e., could not make an adequate evaluation of the
issue's safety significance).
The Plant General Manager acknowledged the inspectors concerns.
Though
not totally agreeing with the inspectors comments,
he did indicate that
the September
16
PNSC
meeting was atypical and had not met his
expectations.
Both the inspectors and plant management agreed that
between the two meetings,
the PNSC had adequately discharged its duties
during the review of the Waiver of Compliance request. It was determined
that provisions of the TS dealing with membership, review process,
frequency, and qualifications were satisfied.
No violations or deviations were identified.
5.
Followup (92700, 92701, and 92702)
(Closed)
URI 91-14-01,
Review Impact Of Entrainment Losses On
Analysis, and URI 91-19-01, Determine Safety Significance and Root Causes
Of Excessive OT Delta T and OP Delta T RPS Time Delays.
These issues (discussed in IRs 91-14 and 91-19, respectively) involved
numerous design/engineering breakdowns.
However,
at the time the
associated IRs were issued, questions involving ECCS performance during a
SBLOCA had not been fully resolved. Also, the licensee's review into the
significance and root causes of the excessive OT Delta T and OP Delta T
RPS time delays had not been completed.
The following paragraphs
summarize the LOCA issues and related analyses (SI issue),
as well as,
provide an update to the excessive OT Delta T and OP Delta T RPS time
delays
The SI issue involved the effects of entrainment inventory losses and
securing ECCS flow during the transfer from the injection phase to the
recirculation phase of a LOCA. The amount of inventory prior to and the
rate of inventory loss during the time ECCS is interrupted, determines the
PCT during the transfer.
The transfer is performed via Emergency
Procedure EPP-9, Transfer to Cold Leg Recirculation.
EPP-9
is required to be initiated when the RWST level reaches 27 percent and the
actual transfer is to be completed prior to RWST level reaching 9 percent.
The procedure restricts the time that ECCS flow is interrupted to ten
minutes for SI system component re-alignments when RCS system pressure is
above the shutoff head of the RHR pumps and to three minutes when the RCS
system pressure is below this value. The former case corresponds to small
SBLOCAs while the latter case corresponds to the larger SBLOCAs and
On June 20,
1988, TS Amendment 119 was issued to support single SI pump
operation.
The analysis to support the amendment ,failed to address the
consequences of having only one SI pump available during implementation of
EPP-9.
In January 1989,
NFS Design Activity 89-001 was generated to
8
provide justification for a revision to EPP-9 to recognize that only one
SI pump may be available during a LOCA .
Utilizing a simple decay heat
model from a text book, written by El-Wakil,
Design Activity 89-001
demonstrated that the flow rate from one SI pump would be slightly greater
than the steaming rate due to decay heat.
Consequently, the licensee
concluded that core cooling is maintained during performance of EPP-9;
thus operation with one SI pump was deemed acceptable.
However, on May
14,
1991,
as a result of IPE activities, the licensee determined that
Design Activity 89-001 did not consider the inventory loss due to
entrained water in determining the flow out of the break.
The previous
analyses associated with a minimum operation of two SI pumps during EPP-9,
the plant configuration prior to February 1988,
had appropriately
incorporated entrainment losses.
Upon this discovery, reactor power was
reduced to 60 percent as previous analysis supported.
Following an
interim Westinghouse analysis justifying operation at 95 percent power
(assuming a 700 degree F maximum PCT after the injection phase and a core
heat load based on ANS 1979 decay heat plus 2 sigma),
power was increased
to 90 percent on May 15,
1991.
Later that day, the NRC informed the
licensee that use of the ANS 1979 decay heat model was not in compliance
with 10 CFR 50 Appendix K requirements.
Accordingly,
on May 16, the
licensee informed the staff that the interim analysis was reperformed
using the ANS 1971 decay heat plus 20 percent model and that acceptable
results were obtained for power operation up to 92.5 percent.
On May 29,
1991,
based on a more rigorous re-analysis which used the
ANS-1971 plus 20 percent model,
Westinghouse determined that the maximum
PCT while ECCS flow is interrupted per EPP-9 during a LBLOCA
was
approximately 1250 degrees F.
The results of this re-analysis were
discussed with the NRC,
and the unit was subsequently returned to full
power later that day.
(Based
on questions by the NRC regarding mass
quantity and distribution in the core, the maximum PCT while ECCS flow.is
interrupted per EPP-9 during a LBLOCA was subsequently revised to
approximately 1400 degrees F.)
Since. the licensee and Westinghouse assumed the LBLOCA to be the most
limiting case, none of the analyses discussed above addressed the affects
of a SBLOCA during the EPP-9 time frame. This bounding of the SBLOCA was
based upon the engineering judgement that prior to securing ECCS flow per
EPP-9 during a SBLOCA, the inventory in the vessel would be as great or
greater than that which would exist for a LBLOCA.
Prompted by the NRC.,
subsequent
SBLOCA analysis revealed that during the transfer to
recirculation with only one SI pump available, the SBLOCA is not bounded
by the LBLOCA. Specifically, this new analysis indicated that the SBLOCA
inventory level is significantly less than previously assumed (i.e., core
uncovery is greater and exists for a longer period of time than that
previously anticipated).
Thus, as calculated for the worst case SBLOCA (a
one and one-half inch break), the maximum PCT of 1936 degrees F during the
time ECCS flow is interrupted exceeds the worst case LBLOCA
PCT of
approximately 1400 degrees.
The SBLOCA PCT during EPP-9 is less than the
2200 degrees F 10 CFR 50.46 ECCS acceptance criteria and less than the
values calculated for both the SBLOCA and LBLOCA PCT during the initial
9
injection phase (i. e.,
2096 and 2178 degrees F, respectively).
When the
plant license was amended in June 1988 to allow the configuration of only
one .SI pump being available to mitigate the consequences of a design basis
accident, the licensee failed to analyze the consequences of only one SI
pump operation during ECCS switchover. This issue was identified by the
NRC during their review of re-analyses associated with the entrainment
issue. As determined, the SBLOCA is independent of the entrainment issue
due to the higher RCS pressures experienced.
Accordingly, URI 91-14-01
regarding entrainment losses is considered closed.
However,
the
acceptability of a second peak (i.e., approximately 1400 and 1936 degrees
F for the LBLOCA and SBLOCA, respecitvely) is still under review by the
NRC.
This is an URI:
Determine If The Existance Of Second Peak Is In
Accordance with 10 CFR 50.46, 91-20-05.
Summarizing the SI issue, there were -significant breakdowns in the
technical reviews/analyses performed throughout the chronology.
These
included: (1) Failure to perform an analysis to support single SI pump
operation in June 1988; (2) Inadequate analysis performed in January 1989
(Design Activity 89-001)
to support single SI
pump operation; (3)
Inadequate analysis performed by Westinghouse to permit power operation up
to 95 percent power,
and this was not identified by the licensee prior to
power accession from 60 percent to 90 percent power; and (4) Incomplete
SBLOCA analysis performed due to the belief that the LBLOCA analysis was
more limiting.
Engineering/design control concerns similar to the SI issue discussed
above were also seen in the OT Delta T and OP Delta T excessive time delay
problem addressed in URI 91-19-01. The OT Delta T septpoint provides for
the on-line protection against DNB.
This setpoint is part of the RPS
circuitry, and provides a reactor trip when the core Delta T, a measure of
reactor power, exceeds the setpoint value.
The setpoint is calculated
based on inputs of core temperature,
pressure, and power distribution.
The plant safety analyses assume the OT Delta T trip function is used to
mitigate three UFSAR Chapter 15 events.
As discussed in IR 91-19, the problem resulted from capacitors (filters)
being installed in the OT Delta T and OP Delta T (which is not used in
accident analyses) RPS circuitry. These capacitors imparted an additional
approximate two second time delay on RTD system response time.
As a
result, the OT Delta T protection circuitry response time exceeded that
used in the accident analyses approximately 6.75 seconds versus the 4.75
seconds analyzed.
Based on a review by the fuel vendor (Siemens)
for
cycles 13 and 14,
the licensee has concluded that sufficient margin was
available to compensate for the additional channel response time, such
that the OT Delta T trip function would have performed as required to
maintain the MDNBR greater than the TS value of 1.17. However, actual RCS
flow rates had to be utilized for one of the three Chaper 15 events
(Uncontrolled Control Rod Assembly Withdrawal at Full Power) to obtain an
MDNBR greater than 1.17.
10
As identified by the licensee, the root cause of this event was that
the modification designer, failed to include capacitor
removal in the modification work instructions (FCN) or to perform a post
modification transient test of the associated circuitry. It appears that
an excessive reliance was placed on Westinghouse for FCN completeness and
neither the reviews performed on the FCN nor subsequent modification
reviews identified the fact these capacitors needed to be removed.
Additionally,
even
though
the
document
change
recommendation
identified the change in the capacitors' time delay (identified in PLS
document to be zero), the hardware changes required were not communicated
nor independently identified.
These problems indicate design control
breakdowns between Westinghouse and the
licensee's engineering
organizations.
The licensee's immediate corrective action after identifying this issue
was both timely and appropriate.
An independent investigation team,
including NSD and NAD, performed a thorough review/root cause analysis of
this issue and previous related OT Delta T issues.
While this issue's
safety significance (discussed above)
was not great,
the licensee
recognized the necessity of accurate RPS setpoints.
Long term corrective
actions will be tracked via LER 91-009 and the violation below (91-20-06).
Accordingly, URI 91-19-01 is considered closed.
The chronology of engineering review/communication breakdowns for the OT
Delta T and the SI issue indicates that there has been, and continues to
be, significant deficiencies in engineering design control and interfaces.
This is contrary to 10 CFR 50 Appendix B, Criterion III, and is identified
as an apparent Violation:
Inadequate Engineering Design Controls and
Interfaces, 91-20-06.
The following historical examples demonstrate that the adequacy of design
controls and interfaces has been a continuing problem for the licensee:
-
Inadequate engineering communications and reviews were issues in 1988
and 1989 related to OT Delta T concerns previously addressed in IRs
88-03 and 89-12.
These issues resulted in a violation of 10 CFR 50
Appendix B Criterion III in 1989 (Vio 89-12-02).
Inadequate
calculational, design, and modification testing review problems were
identified with the AFW NPSH issue in late 1989 ( EA 89-188 and IRs
89-11,
89-18,
and 89-20).
In addition, inadequate engineering
reviews were also identified in 1989 involving the Agastat relay
tolerance issue (IR 89-12).
-
During
1990
(IR
90-22),
concerns were identified with the
interdepartmental
communications during development of two
modifications.
Engineering also failed to identify that one of the
modification's proposed radiation monitors was inadequately ranged.
-
Also in 1990, errors involving LBLOCA analysis computer codes and
interpretation of TS figure 3.10-5 (IR 90-23) indicated inadequate
oversight/communications between the licensee and the fuel vendor.
Additionally, a 1991 issue (VIO 91-01-03) was identified involving
inadequate engineering review of modification M-1016,
Electrical
Penetration Replacement.
(Closed)
VIO 89-09-05,
Design Control
Measures Were Not Adequately
Established to Assure That The 50 GPM Leak Isolation Capability Design
Basis
Was Correctly Translated Into Specifications,
Drawings,
and
Procedures for the RHR System.
The inspectors reviewed the licensee's
response dated July 26, 1989, to the NOV. The inspectors agreed that the
root cause was a lack of adequate design basis and that the DBD process
should correct this deficiency.
The inspectors reviewed modification
M-1017,
Eliminate RHR Pump Common Mode Failure, which provided enhanced
leak detection
and isolation capabilities.
This consisted of:
installation of RHR pit sump level indicators on the RTGB; control room
annunciation of high water level in the pit; installation of motors on the
RHR-752 A, B, valves; and movement of the isolation valves for the CCW
supply lines to the RHR pump Hxs' and SW supply lines to the RHR room
coolers into areas which would be accessible during the recirculation
phase of an accident. This modification provides adequate indication of a
leak in the RHR pit, as well as providing remote leak isolation
capability. This item is-closed.
(Open) LER 89-11, Auxiliary Feedwater System Flow Rate Could Exceed Limits
of Accident Analysis.
The SDAFW
pump discharge flow control valve,
FCV-6416, has been mechanically limited such that under steam line break
accident conditions, the maximum flow rate does not result in a mass input
into the CV in excess of that used in the safety analysis.
This
limitation results in the SDAFW pump being limited to approximately half
its flow capacity during normal plant transients.
Modification 1025,
Upgrade AFW FCV 6416, is being developed for installation in RO 14 to
correct the design deficiency.
This
item remains
open pending
installation and successfully testing of the modification.
One violation was identified.
6. Organizational Changes
On September 10, 1991, Mr. R.H. Chambers, Operations Manager, was named as
General Manager -
Robinson Plant. Mr. W. J. Flanagan, previosly Manager,
Modification Projects, and recently licensed as an SRO, was appointed to
the position of Operations Manager.
On September 18, 1991, Mr. C.R.
Dietz, Manager - Robinson Nuclear Project, was elected to the position of
Vice President.
7. ESF System Walkdown (71710)
This inspection was performed during the EDSFI conducted the weeks of
September 23-27,
October 7-11,
and 21-25,
1991.
The details of this
inspection will be documented in IR 91-21.
13
e.g.
For Example
End Path Procedures
F
Fahrenheit
Field Change Notice
Flow Control Valve
Hx
Heat Exchanger
Instrumentation & Control
Individual Plant Evaluation
IR
Inspection Report
KV
Kilovolt
Large Break Loss of Coolant Accident
LCO
Limiting Condition for Operation
Loss of Coolant Accident
M
Modification
Motor Driven Auxiliary Feed Water
MDNBR
Minimum Departure from Nucleate Boiling Ratio
Non-cited Violation
NED
Nuclear Engineering Department
Nuclear Fuels Section
NLS
Nuclear Licensing Section
Net Positive Suction Head
NRC
Nuclear Regulatory Commission
Nuclear Reactor Regulation
OT Delta T
Overtemperature Delta Temperature
p.m.
Post Meridiem
Protected Area
Personnel Access Portal
PC
Protective Clothing.
Project Change Notice
Peak Cladding Temperature
Precautions, Limitations, and Setpoints
PNSC
Plant Nuclear Safety Committee
REV
Revision
Radiation Monitoring System
Robinson Nuclear Project
Reactor Operator
Refueling Outage
Resistance Temperature Detector
Reactor Turbine Generator Board
Reactor Water Storage Tank
Small Break Loss of Coolant Accident
Safety Injection
Senior Reactor Operator
14
TS
Technical Specification
Updated Final Safety Analysis Report
Unresolved Item
Violation