ML20126F215
| ML20126F215 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 12/11/1992 |
| From: | Freudenberger, Holmesray P, Landis K, Merriweather N NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20126F164 | List: |
| References | |
| 50-302-92-27, NUDOCS 9212300151 | |
| Download: ML20126F215 (18) | |
See also: IR 05000302/1992027
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W4 UNITED ST ATES
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NUCLEAR REGULATORY COMMISSION
REGION 11
C 101 MARIETT A STREET, N.W.
$ -a g
- * ATL A NT A, GEORGI A 30323
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Report No.: 50-302/92-27
Licensee: Florida Power Corporation
3201 34th Street, South
St. Petersburg, FL 33733
Docket No.: 50-302 License No.: ORP-72
Facility Name: Crystal River 3
Inspection Conducted: October 18 - November 14, 1992
Inspector: 08 (cm fee 12f 11 M
P. Holmes-Ray, Senjor Resident Inspector Date Signed
Inspector: G . (2. [ce Poc l2 f 16 92
R. Freudenberger, Re5ident Inspector Date Signed
Inspector: .
ce M @ F1
FT-~Merriweather7Reaptor Inspector Date Signed
Approved by: 2/ h[uk
K. Landis, Section Chief
/$[i/
Dat'e Signed
v
Division of Reactor Projects
SUMMARY
Scope: -
This routine inspection was conducted by two resident inspectors and one
specialist inspector in the areas of plant operations, security, radiological
controls, Licensee Event Reports, plant modifications, and licensee action on
previous inspection items. Numerous facility tours were conducted and
facility operations observed. Backshift inspections were conducted on October
24, 25, 27, 31, and November 4, 6, 7, 11.
Results:
In the area of plant operations, the following violations were identified:
VIO 50-302/92-27-01: Failure to Follow Procedure Results in Valve
Misalignment and Reactor Building Spray (paragraph 3.a)
VIO 50-302/92-27-02: Failure to enter action statement 3.8.1.1 and
perform surveillance requirement 4.8.1.1.1.a with the "B" Emergency
Diesel Generator inoperable as the result of non-TS surveillance testing
(paragraph 4.a).
9212300151 921211
O ADOCK 05000302
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REPORT DETAILS
l. Persons Contacted
Licensee Employees
G. Boldt, Vice President Nuclear Production
- J. Buckner, Nuclear Regulatory Specialist
- R. Davis, Manager, Nuclear Plant Maintenance
- E. Froats, Manager, Nuclear Compliance
- A. Gelston, Manager, Site Nuclear Engineering Services (Acting)
- G. Halnon, Manager, Nuclear Plant System Engineering
B. Hickle, Director, Nuclear Plant Operations
- S. Johnson, Nuclear Chemistry and Radiation. Protection Superintendent
- K. Lancaster, Nuclear Maintenance Work Controls Superintendent
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- G. Longhouser, Nuclear Security Superintendent
W. Marshall, Nuclear Operations Superintendent *
- P.-McKee, Director, Quality _ Programs
- L. Moffatt, Nuclear Shift Manager
B. Moore, Manager, Nuclear' Integrated Scheduling
- D. Porter, Nuclear Shif t Supervisor
- S. Robinson, Manager, Nuclear Quality Assessments
~*W. Rossfeld, Manager, Site Nuclear Services
- J. Terry, Supervisor, Site Nuclear Engineering Services
- R. Widell, Director, Nuclear Operations Site Support
K. Wilson, Manager, Nuclear Licensing
Other licensee employees contacted included office, operations,
engineering,. maintenance, chemistry / radiation, and corporate personnel. ,
NRC Resident Inspectors
- P. Holmes-Ray, Senior Resident Inspector
- R. Freudenberger, Resident Inspector
- Attended exit interview
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Acronyms and initialisms used throughout this report are listed in the
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last paragraph,
2. Plant Status and Activities
The plant 1 continued in power operation (Mode 1) for the duration of this
inspection period.
On October 21, the Chief of Region II Reactor Projects.Section 2B was on
site for a routine visit.
During the week of November 2, a specialist inspection was conducted to
observe the Emergency Drill. The results of this inspection were-
documented in NRC Inspection Report 50-302/92-26.
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3. Plant Operations (71707, 93702, 40500, & 82301)
Throughout the inspection period, facility tours were conducted to
observe operations and maintenance activities-in progress. The tours
included entries into the protected areas and the radiologically
controlled areas of the plant. During these inspections, discussions
were held with operators, health physics and instrument and controls
technicians, mechanics, security personnel, engineers, supervisors, and
plant management. Some operations and maintenance activity observations
were conducted during backshifts. Licensee meetings were attended by
the inspector to observe planning and management activities. The
inspections confirmed FPC's compliance with 10 CFR, Technical
Specifications, license Conditions, and Administrative Procedures,
a. Inadvertent Reactor Building Spray
On October 15, 1992, with the unit at full power and a quarterly
surveillance run of the "A" Building Spray Pump in progress, a valve
misalignment resulted in the discharge of borated water into the Reactor
Building. A detailed description of the event and licensee initial
actions was included in NRC Inspection Report 50-302/92-25, detail 3.a.
Unresolved Item 50-302/92-25-01 was identified pending the completion of
licensee evaluations and the planned submittal of a voluntary report on
the ;ent.
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Inspector review of the circumstances of the event concluded that the
root cause was licensed operator error. The surveillance flow path was
to be from the Borated Water Storage Tank (BWST) through the BSP-1A
recirculation line back to the BWST. Step 4.0.5 of SP-340B aligns
recirculation flow for testing the "A" Reactor Building Spray Pump,
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including prepositioning manual valve BSV-28 at approximately 7 and 1/2
turns open. After the pump has been started, step 4.7.1 states
" Establish flow at 1500 gpm (with allowable oscillation averaged value
between 1470 gpm and>1530 gpm), by throttling BSV-28." The licensed
operator mistakenly opened and throttled with BSV-3, the motor operated
valve to the spray nozzles, allowing flow to the Reactor Building spray
,
The licensed operator involved did not use proper self-checking
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techniques while performing the surveillance. Nevertheless, he
volunteered his error when he recognized it and candidly assessed his
I own performance. Contributing factors to the error included the wording
and structure of the procedure step and simulator training that
practiced throttling of Reactor Building spray flow using BSV-3 during
L accident conditions.
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l The licensee performed an immediate assessment of plant conditions and
- developed an action plan to recover from the reactor building spray
l event. A preliminary evaluation was performed by the licensee in the
i following areas:
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Wetted areas of the RB
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- Metal corrosion, including galvanic corrosion, boron corrosion and
hydrogen production
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RB instrumentation condition
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Electric motors including:
RCP motors
AHF motors
Motor operated valves
Cable issues
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Primary system thermal stress
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RB cranes
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Comparison to RB hydrolysing experiences
- Fan cooler effects of boron precipitation
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EQ equipment impact assessment
The NRC's overall conclusion was that no immediate safety concern
existed and that continued operation was justified. The short term
actions consisted primarily of increased monitoring of equipment and
instrumentation for indications of degradation caused by the spray, and
a RB entry to assess the condition of the RB and equipment. The
Resident Inspector participated in the RB entry. No damage to safety-
related equipment as a result of the spray was identified. The long
term actions required additional visual inspections of equipment for
signs of degradation due to spray.
A region-based inspector was dispatched to the site on October 16, to
aid in the review of licensee's actions to recover from the inadvertent
actuation of Building Spray. The inspector met with the Engineering
Manager to discuss the event and the licensee's action plan status. The
action plan contained 14 action items of which most were considered
complete. The open items were identified as follows:
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- Walkdown main control board thoroughly and frequently to look for
indication of failed instruments or components.
Status: Ongoing on October 16, now complete.
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Accumulate a list of known damage and effects.
Status: Ongoing. As of October 16, only two failures had
occurred and they were discussed in NRC Inspection Report
50-302/92-25. Two more Control Rod Drive Shroud Fans
subsequently failed, which might be attributable to the
spray event, as described below.
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Determine what actions were taken at other plants having similar
events.
Status: Ongoing on October 16, now complete.
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The licensee's action plan was_ judged to contain action items that_were
similar to those described in a Safety Evaluation (SE) developed by the
l NRC Division of Systems Technology concerning " Inadvertent' Containment
Spray Events at Commercial Nuclear Power Plants." The SE was issued by
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an NRC memorandum from Thomas Murley, Director, Office of Nuclear
Reactor Regulation, to all Regional Administrators, dated March 13,
1991. This SE was attachment A to NRC Inspection Report 50-302/92-25.
The safety evaluation indicated that continued reactor operation
following a spray event was acceptable if an immediate assessment of
plant conditions was performed and an action plan was developed to fully
evaluate the consequences of the event on plant systems and components.
Inspection of short term actions taken by the licensee was performed.
Increased surveillance of instruments and equipment for degradation were
observed and the engineering assessments of. potential problem areas were
evaluated. One licensee action item required operations to walk down
the main control board twice per shift to look for indication of failed
instruments or components. A Short Term Instruction (STI)92-019 was
issued which required performance of SP-300, Operating Daily
Surveillance Log, twice per shift for one week, until October 22, 1992.
The NRC inspector toured the control room on October 17 and 18,1992,
attended shift turnover meetings, and witnessed the control room board
walkdowns at 8:00 a.m.,12:00 noon and 4:00 p.m. The data sheets for SP-
300, completed on October 17, 18 and 19, 1992, and the operating shift
log were reviewed to verify that no equipment failures had occurred that
could be attributed to the BS event. During the week of additional
monitoring, no other failures were identified. Other licensee action
items required engineering to perform evaluations of potential problem
areas as well as provide recommendations for 'short and_ long term action.
The preliminary evaluations performed by the licensee were reviewed and
found to be acceptable.
As discussed in NRC IR 50-302/92-25, immediately following the spray,
one of twelve control rod drive shroud exhaust fans (AHF-51A) and one
area radiation monitor (RMG-18) failed. Later in this report period,
two more of the control rod drive fans (AHF-51D & AHF-51K) failed. The
effect of these failures on reactor head service structure temperature
was negligible. Cause analysis of the recent failures was added to the
licensee's long term action plan, to determine if these failures were
the result of the spray.
The inspector confirmed that the licensee had a program in place to
perform increased surveillance of instruments to identify degradation of
components. The licensee's long term action plans, to assess equipment
for possible damage due to spray, appeared to be : appropriate. The plan
included such actions as visual inspections of selected plant equipment
and increased sensitivity to abnormal component conditions during
routine maintenance and calibration in future outages.
The licensee submitted a voluntary report on the event in a letter dated
November 4,1992, to the Regional Administrator, NRC, Region II. The
letter described the event and addressed the scope and sequence of
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licensee actions. Actions performed or planned included a human
performance evaluation and technical evaluation of the short and long
term affects. The licensee's human performance evaluation concluded
that the operator failed-to apply proper self-checking measures to
assure adequate comprehension and correct implementation of required
procedural guidance. The human performance evaluation proposed several
recommendations for consideration to prevent recurrence.
The operator's failure to properly implement the Step 4.7.1 of
Surveillance Procedure SP-340B was a violation, and was identified as
VIO 50-302/92-27-01: Failure to Follow Procedure Results in . Valve
Misalignment and Reactor Building Spray. Although the licensee promptly
initiated extensive corrective actions, as described in detail above,
the violation is being cited because of the inherent significance of an
operator error of this nature. Unresolved item 50-302/92-25--01 is
closed.
b. Emergency Drill Observation
On November 5, the licensee conducted an annual Emergency Preparedness
exercise. Specialist Inspectors from the Region II office of the NRC
were onsite to evaluate the exercise. The resident inspectors observed-
activities in the Simulator Control Room, The Technical Support Center,
and the Emergency Operations Facility.
This was the first occasion in which the control room simulator was used
to simulate accident conditions and provide realistic time frames for
emergency condition parameters.
Late in the scenario, the operators attempted to use a recently
installed high pressure auxiliary spray line to continue a rapid
cooldown and depressurization of the_ reactor coolant system following
the simulated steam-generator tube rupture. - Although the simulator had
been updated to provide simulation of use of the high pressure-auxiliary
spray, the operators identified that an out-of-date revision of
procedure OP-305, Operation of the Pressurizer, was in the simulator
control room and did not include a section for use of the high pressure
auxiliary spray. The procedure was replaced with a current revision.
The licensee's drill critique identified the deficiency and the_-
inspector verified that the correct revision of the procedure was in the
plant control room.
An assessment of the overall effectiveness of the exercise is documented
in NRC-Inspection' Report 50-302/92-26.
4. Maintenance and Surveillance Activities (62703 & 61726)
Surveillance tests were observed to verify that approved procedures were
being used; qualified personnel were conducting the tests; tests _were
adequate to verify equipment operability; calibrated equipment was
utilized; and TS requirements appropriately implemented.
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. The following tests were observed and/or data reviewedi
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SP-9078, Monthly Functional Test of 4160V ES Bus "B" Undervoltage
Relaying;
- SP-907A, Monthly Functional Test of 4160V ES Bus "A" Undervoltage
Relaying; and
- SP-317, Reactor Coolant Water Inventory Balance.
In addition, the inspector observed maintenance activities to verify
that correct equipment clearances were in effect; work requests and fire
prevention work. permits, as required, were issued and being followed;
quality control personnel performed inspection activities as required;
and TS requirements were being followed.
Maintenance was observed and work packages were reviewed for the
following maintenance activities:
- WR 302973, Installation:of Phase Gating Unit for Phase B for
Control Rod Group 6A Power Supply;
- WR 262140 & 299344, Preventive Maintenance on Inverter 1A;
- WR 302712 Troutteshooting Inverter 1E intermittent output voltage
fluctuation;
- WR 303112 & 303086, Cleaning and Ultrasonic Inspection of Nuclear-
Services Closed Cycle Cooling System Suction Header; and
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WR 290604, Prefabrication of Replacement Nuclear Services Closed
Cycle Cooling Suction Header Piping.
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The following items were considered noteworthy:
a. Technical Specification' Action Statement Applicability During
Surveillance Testing
On October.27,'1992, the -licensee performed SP-907B, Monthly
Functional Test of 4160V ES Bus "B" Undervoltage Relaying. The
purpose of the procedure was to demonstrate operability of the
4160V ES Bus B undervoltage protection scheme. The undervoltage
protection scheme is comprised of three undervoltage modes: First
Level Undervoltage Relays (loss of voltage); Second Level
Undervoltage Relays (degraded voltage); and Second Level
Undervoltage with an ES actuation. Each mode is capable of
stripping the 4160V ES Bus B and initiating a start-of Emergency
Diesel Generator 3B. The performance of SP-907B is not required
by TS.
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Performance of the procedure included disabling the Emergency
Diesel Generator by tripping the fuel rack and isolating starting
air to prevent an inadvertent start. Degraded voltage conditions
were then simulated to actuate the FLUR and SLUR relays and
measure their response time. The inspector observe 6 tae test and
equipment restoration, which was performed satisfactorily.
The inspectot noted that although the "B" Emergency Diesel
Generator was disabled for approximately two hours as directed by
the procedure, the licensee did not enter TS action statement
3.8.1.1 nor perform action b, performance of surveillance
requirement 4.0.1.1.1.a, which requires verification of the
breaker alignments and indicated power availability to the offsite
circuits within one hour. This was identified as VIO S0-302/92-
27-02: Failure to enter action statement 3.8.1.1 and perform
surveillance requirement 4.8.1.1.1.a with the "B" Emergency Diese'
Generator inoperable as the result of non-TS eJrveillance testing.
The safety sigr.ificance of this violation was minor because
offsite power circuits remained operable throughout the
performance of the SP. In addition, the Emergency Diesel Generator
was inoperable for significantly less than the 72-hour time period
allowed by the action statement before shutdown must be initiated.
Review of the circumstances of the above violation revealed that
historically, the licensee has not entered TS action statements
when TS related equipment became inoperable as the result of
performing SPs. It was recognized that this practice was not
consistent e ' the NRC staff's position stated in Part 9900:
Technical f.1.nce - Operability of the NRC Inspection Manual
published in Generic Letter 91-18 "Information to Licensee's
Regarding Two %"C Inspection Manual Sections on Resolution of
Degraded and F._ conforming Conditions and on Operability " dated
November 7, 1991. This guidance states "If TS surveillances
require that safety equipment be removed from service and rendered
incapable of performing its safety function, the equipment is
inoperable. The LC0 accion statement shall be entered unless the
TS explicitly direct otherwise." However, some surveillance
requirements such as RPS testing which removes a RPS channel fr;m
service cannot be completed within the action statement time
al'. owanc e .
FPC is currently examining their position on entering the required
actions of TS when equipment is rendered inoperable as a direct
result of periodic surveillance testing based on their review of
WRC GL 91-18 and implementation of the Revised Standard Technical
Specifications (RSTS).
A licensee written positien or, the issue provided to the
inspectors following discussions with FPC management states that
FPC " understands this issue was discussed at the Region 1
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NRC/Public workshop on GL 91-18 and that as the result of issues
identified at that time, it it the NRC Staff's intent to further
discuss it at subsequent GL 91-18 workshops. FPC intends to
remain involved in these discussions and work, together with other
utilities, towards a resolution that provides adequate operational
latitude while maintaining full cognizance of equipment
availability / operability." RSTS accommodates implementation of the
NRC Staff's position and is currently scheduled for implementation
in the Fall of 1993.
b. Reactor Coolant Water Inventory Balance
The reactor coolant drain tank level indicator (WD-23-LT).has
experianced sporadic perturbations in indication since startup -
from the 1992 refueling outage. Due primarily to inaccessibility
of the components during power operations, troubleshooting
activities have not been successful at identifjing and correcting
the cause of the indicated perturbations.
The level change in the reactor coolant dra?n tank is monitored
during the performance of SP-317, Reactor Coolant Water Inventory
Balance, to determine the identified leakage in accordance with TS 3.4.6.2. Leakage from the reactor coolant system to the reactor
coolant drain tank would originate from the pressurizer power
operated relief valve, code safeties, core flood tank drains or
reactor coolant system vents and drains. During initial -
troubleshooting efforts, reactor coolant leakage to the reactor ,
coolant drain tank was considered in the unidentified leakage
calculation.
STI 92-0021 was issued on October 19, 1992, after long term
trending of the WD-23-LT indication. The STI allows use of
WD-23-LT level indication for the calculation of identified
leakage provided a review of the history of the output of WD-23-LT
for a period including one hour before and after the collection of
SP-317 data is reviewed and no perturbations exist. :
Plans were established to conduct further troubleshooting in the .
event of an unplanned octage. The inspector reviewed SP-317 data
from throughout the report period. Reactor coolant- system leakage
has remained stable and low following the 1992 refueling outage.
The inspector considered the licensee's actions to address this
issue to be acceptable,
c. Nuclear-Services Closed Cycle Cooling Suction Header Degradation
On November 5,-a maintenance planner performing a walkdown of a WR
for replacement of the Nuclear Services Closed Cycle Cor' + (SW)
suction header identified leakage from the header in the v:,inity
of the joint of the six inch surge line to the eighteen inen
suction header.
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The suction header and the surge line are located in a trench in
the floor of the Seawater Room in the Auxiliary Building. The
suction header is common to three SW system circulating pumps.
One pump is the normal duty pump, with two ES pumps normally in
standby. The SW system provides cooling to safety related
components such as; high pressure injection pumps, letdown
coolers, reactor building coolers, spent fuel pool coolers,
reactor coolant pumps, and control rod drive mechanism coolers.
Decay Heat Removal is supplied by separate closed cycle cooling
systems.
On November 6, the licensee performed a detailed visual inspection
of the leaking section of pipe. Two additional pin hole type
leaks were identified on the bottom of the suction header. A
temporary non-rode repair was designed and installed to reinforce
the structural integrity of the leaking section adjacent to hanger
SWH-18. The repair consisted of encasing approximately three feet
of the surge line and suction header in high density grout,
filling the trench in the area of the hanger SWH-18. The repair
was installed in accordance with a temporary modification, MAR
number T92-11-02-01. The MAR was reviewed and the PRC meeting
that approved the MAR was attended by the inspector. Prior to
installation of the temporary non-code repair, the NRC reviewed
and approved the installation in accordance with GL 90-05,
" Guidance For Performing Temporary Non-Code Repair of ASME Code 1,
2, and 3 Piping."
During the week of November 9, an ultrasonic inspection to
characterize the condition of the remainder of the surge line and
suction header, including the two additional leaks, was perf ormed.
Portions of this inspection were observed by the inspectors.
Inspection results indicated that significant external corrosion
had caused general wall thinning on the lower third of the
eighteer-inch portion of the header and the full circumference of
the six inch surge line in the trench. A stress analysis of the
piping was completed by the licensee which indicated the piping
remained operable and the leaks did not compromise the structural
integrity of 'Se piping. The inspectors reviewed the analysis and
provided the information to NRC personnel involved in approval of
the temporary non-code repairs. It was determined that the
analysis provided sufficient justification that the piping
remained operable with minimal margin for further degradation.
The licensee submitted a request for approval of non-code repairs
for the remaining leaks in a letter dated November 13.
An operations STI was issued on November 9, which directed the
Primary Plant Operator to monitor the suction header at least
twice per shift for any change in leakage. The STI remains
effective until December 1, 1992.
Prefabrication of permanent replacement piping for the affected
areas was ongoing at the end of the inspection period. The
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licensee's actions to monitor the condition of the SW will be
assessed in future inspections.
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5. Review o' '< ensee Event Reports (92700)
LERs we 9m iewed for potential generic impact, to detect trends, and
to detero.ne whether corrective actions appeared appropriate. Events
that were reported immediately were reviewed as they occurred to
determine if the IS were satisfied. LERs were also reviewed in
accordance with the current NRC Enforcement Policy,
a. (Closed) LER 91-04: Personnel error caused reactor vessel level
required for inadequate core cooling to be incorrectly calibrated.
See paragraph 6.b for details.
b. (Closed) LER 91-05: ECCS pump and flow paths were secured due to ,
valve leak resulting in a condition outside the plant design
basis.
Crystal River Unit 3 was operating at 100 percent ful? power on
May 30, 1991. Between 9:00 p.m. and 9:07 p.m., operators received
indications of leakage from the Makeup and Purification system in-
- the Auxiliary Building. Operators located the leakage source by
visual observations and by measuring piping surface temperatures.
Leakage was originating from the inter-stage packing leakoff
connection on MVP discharge crosstie valve, MUV-3. The leak was
stopped at 10:23 p.m. by backseating the valve.
Between 9:42 p.m. and 9:55 p.m., while attempting the isolate the
leaking valve, operators stopped all makeup flow, closed another
discharge crosstie valve, MUV-4, the recirculation valve, MUV-264,
and removed control power to the circuit breaker for one of the
MVP/HPI Pumps. These actions placed the plant in a condition
outside the design basis. This condition existed from 9:42 p.m.
until approximately 11:05 p.m.. At this time, operators opened
the valves and restored control power to the pump circuit breaker.
The FSAR for CR-3 discusses combinations of operable MVPs and HPI
valves necessary to ensure adequate HPI flow in the event-of an
accident. With control power removed from-the MVP-1C circuit
breaker, the pump could not be started. -Since_MVP-1B was not
aligned to automatically start, only one pump was available to
provide HPI flow. With MUV-4 closed, only two nozzles were
available. Based on information in the FSAR, it is not clear that
this pump / valve combination would have provided adequate HPI- r' low
under certain accident scenarios. Control Room personnel did not
initially consider that these actions placed the unit in a
condition outside the plant design basis. During subsequent
review of the event, plant personnel determined that the unit was
temporarily outside the plant design basis.
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The licensee developed detailed guidance regarding HPI flow path
operability documented in TSI 92-02. The failed valve packing was
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replaced during the 1991 maintenance outage with an improved
design packing arrangement. This LER is closed.
c. (Closed) LER 91-10: Wiring problem causes transformer breakers-to
open actuating the emergency diesel generator.
On October 20, 1991 CR-3 was in Mode 5 (COLD SHUTDOWN) for a
scheduled maintenance outage. At 2:43 p.m. the breakers for the
offsite power transformer opened, disconnecting the ES busses from
the offsite power supply. Decay heat cooling was interrupted for
less than a minute while the emergency diesel generator loaded the
ES bus and operators restarted the DHP. Upon starting the DHP, a
purification relief valve lifted causing a drop in pressurizer
level. Operators quickly identified the source and isolated the
purification system. At 2:47 p.m., the oparators manually
energized the remaining ES bus via the CR-3 startup transformer.
This event was caused by a pre-existing wire installation which
inadvertently applied 115V AC to the CR-3 battery bus.
The improperly installed wire was removed by WR 0289924. The
breaker relays were replaced with less sensitive ones by WR 0289619 to reduce the possibility of repeating this_ event. An
Operations Study Book entry describing this event and lessons
learned was issued November 7,1991, and was signed off by all
active operators. Procedure AP-770, Emergency Diesel Generator
Actuation, was revised to address restarting the DHP if required
following 4160V bus undervoltage. This LER is closed.
d. (Closed) LER 91-12: Procedure deficiency leads to inadvertent
emergency diesel generator actuation during engineered safeguards
testing.
The procedure inadequai.y in SP-457, Refueling Interval ECCS
Response to a Safety Iajection Test Signal, was corrected by
Revision 10 which was affective July 22, 1992. Some test switches
are spring loaded to return to normal position some are not. The
revision clearly required placing the test switches back to pre-
test positions verses releasing the test switches. This LER is
closed.
e. (Closed) LER 92-21: Lack of Required Lube Oil Leakage Collection
Tank Reserve Capacity For Reactor Coolant Pumps Violates 10 CFR 50
Appendix R Design Criteria
The issue described in this LER was the subject of a violation
detailed in NRC Inspection Report 50-302/92-25, detail 3.b.
Corrective actions will be reviewed as part of the violation
followup VIO 50-302/92-25-02, therefore this LER is closed.
Violations or deviations were not identified.
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6. Licensee Action on Previously Identified Inspection Findings (92702 &
92701)
a. (Closed) NCV 50-302/90-32-02: Failure to provide adequate design
control measures as required by 10 CFR 50, Appendix B, Criterion
III.
On September 24, 1990, with the reactor at full power, the " area
owner" was making a walkdown of the "B" decay heat pit. He
noticed that the guard encapsulation for DHV-43 was not leak tight
in that two small diameter pipe nipples did not contain plugs.
The area owner, an operations assistant shift supervisor, wrote a
memorandum to engineering requesting information as to whether the
nipples should be open or plugged. On September 25,1990, the
system engineer, accompanied by a senior reactor operator,
examined the guard enclosure for both decay heat trains and found
the plugs missing on both decay heat train encapsulations. The
system engineer referred operations to the FSAR chapter 5 which
stated:
" Penetrations 345 and 346 have only one containment isolation
valve etch. The second barrier, which is required in order to
meet the CR-3 containment isolation derign basis, is provided by- ;
an encal sulation around each recirculation.line from the
containment to beyond the first isolation valve. This
encapsulation is leak-tight at containment design pressure and is
not directly connected to the containment sump or atmosphere. A
single passive or active failure in these lines or encapsulations
will not provide a path for leakage to the environment."
The drawings for the encapsulation (FPC Drawing Number P0-301-621)
details the two socket weld adapters but does-not show any
attachment or closure devices. Therefore, the encapsulations are
in accordance with the drawings. There is no test data, readily
available, to indicate that the encapsulation is capable of
withstanding containment design pressure. The licensee has
plugged the openings but has not tested the encapsulation. .
A violation was considered for this issue because the fact that
the encapsulations in the plant were in accordance with plant
drawings but not in accordance with the design basis indicated
that the design control measures required by 10 CFR 50, Appendix
B, Criterion III were not effective.
This was one of the issues discussed during an Enforcement
Conference at the NRC Region 11 Office on October 31, 1990. The
licensee presented information that-the design basis of the
encapsulations was different from that described in the current
revision of the FSAR. Information from B&W correspondence'from
1971 stated:
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... the intent of the guard pipe is to prevent excessive '
quantities of fluid escaping from the Reactor Building sump in the
unlikely event a LOCA and subsequent rupture of this Decay Heat
line were to occur."
B&W correspondence in 1987, relative to the-function of
encapsulations stated:
"The function of the piping jacket is to prevent drainage of the
RB sump in the event of failure or breakage of the piping between
the RB penetration and the isolation valves."
ANSI N271-1976 states the following relative to these containment
penetrations:
3.6.4 Sinale valve and closed system outside containment:
"The single valve and piping between the containment and the
valve shall be enclosed in a protective leak tight p_r
controlled leakane housina to prevent leakage to the
atmosphere."
Inaccurate information relative to the definition of this type
penetration was included in the 1989 revision of the FSAR.
Based on the information presented at the Enforcement Conference, *
the issue was categorized as a non-cited violation. The violation
was held open to verify the revision of the FSAR to accurately. .
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describe the design basis of the encapsulations,
The current FSAR description of the design basis-of the
encapsulatiuns was reviewed. It accurately described the design
basis. This-item is closed.
b. (Closed) URI 50-302/91-04-01: Review and approval of inadequate .
procedure steps for calibration of reactor vessel level
instruments.
On April 24, 1991, after licensee followup of NRC questions,
errors were identified in the calibration data sheets for reactor
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level instruments RC-163A-LT and RC-163B-LT, RC-164A-LT-and RC-
l 164B-LT, and RC-201-LT and RC-202-LT. The errors associated with
the calibration status of reactor vessel head level instruments
(RC-164A-LT and RC-164B-LT) was evaluated to be a condition
outside the design basis as referenced in FSAR section 7.3.4.2.1
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and TMI Action Plan item II.F.2. Therefore, the licensee made a
one hour ENS call on May 14,.1991, and submitted LER 91-04 on June
13, 1991.
The licensee attributed the calibration errors to FPC engineering
l personnel who incorrectly transposed calibration data from a
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contractor instrument data sheet. The document apparently did not j
clearly indicate instrument zero. This resulted in the RC-164A-LT
and RC-164B LT level devices measuring the reactor vessel head
stand pipe level rather than the level from hot leg to reactor
head. A modification was implemented in August 1985, (MAR 83-03-
04-02) to meet NRC Order requirements which added these new :
reactor vessel level monitoring devices.
The licensee verified the instrument calculations and data sheets,
and revised the appropriate SPs (SP-144A, RCITS Reactor Vessel and
Hot Leg Level Channel Calibration; and SP-195, Remote Reactor
Vessel Level Instrumentation Calibration). WRs 283679 and 283680
recalibrated the affected instruments on May 17, 1991 and May 18,
1991, respectively.
Problem Report SYPR-91-0012 was issued to document this issue, to
determine root.cause and to recommend corrective actions. The
licensee determined the level instruments to be operable and
therefore the associated TS action statements (TS 3.3.3.6.b and c
for TS Table 3.3-10 items 21 and 22) were not entered. In
addition, a PRC meeting on May 13, 1991,- reviewed operability and
concluded these in.ctruments to be operable. The basis for this
determination was that tne RC-164A-LT and RC-164B-LT devices would ,
still measure a 'ressel voiding condition as they were monitoring '
the reactor vessel stand pipe level. Also, other instrumentation
was available t<s the operator (e.g., void monitor, core exit
thermocouples and h'st leg level monitor).
The inspector reviewed the LER, the PR, the SPs and WRs, and the
FSAR. The '.nspectJr also discussed this item with licensee
engineerir.g, maintenance, operations and management personnel.
The inspector questioned the licensee's operability determination
since tne licens'se concluded the RC-164A-LT and RC-164B-LT -
instrument calibration was outside the design basis. The design
basis as state 6 in the FSAR and in the THI Action Plan Item II.F.2
was that the level from the reactor vessel hot leg to the vessel
head was to be the measured range. Also, the LER appeared
deficient in that it did not address the related TS issues nor
provide the basis for instrument operability determination. This
issue appears to be mitigated based on the licensee corrective -
actions including instrument re-calibration with four days of
identifying the condition, (well within the seven day TS Action
Statement) and the availability of redundant monitors for
potential core voiding. In addition, this instrument provides an
indication function only and operator implementation -of E0Ps would
direct them to successfully assess a condition of inadequate core
cooling. Also, the licensee was proactive in their corrective
actions in that they reviewed all safety related and NRC
Regulatory Guide 1.97 level instruments for similar type . errors
and none were found. All system engineers were required to review
l this event.
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Based on the above actions, URI 50-302/91-04-01 and LER 91-04 are
considered closed.
Violations or deviations were not identified.
7. Exit Interview
The inspection scope and findings were summarized on November 16, 1992,
with those persons indicated in paragraph 1. The inspectors described
the areas inspected and discussed in detail the inspection results
listed below. Proprietary information is not contained in this report.
Dissenting comments were not received from the licensee.
Item Number Status (Lescrintion and Reference
VIO 50-302/92-27-01 Open Failure to Follow Procedure Results
in Valve Misalignment and Reactor
Building Spray (paragraph 3.a)
VIO 50-302/92-27-02 Open Failure to enter action statement
3.8.1.1 and perform surveillance
requirement 4.8.1.1.1.a with the "B"
inoperable as the result of non-TS
surveillance testing (paragraph 4.a)
UNR 50-302/92-25-01 Closed Followup of inadvertent Actuation of
Reactor Building Spray (paragraph
3.a)
LER 50-302/91-04 Closed Personnel error caused reactor
vessel level required for inadequate
core cooling to be incorrectly
calibrated (paragraph 5.a, 6.b)
LER 50-302/91-05 Closed ECCS pump and flow paths were
secured due to valve leak resulting
in a condition outside the plant
design basis (paragraph 5.b)
LER 50-302/91-10 Closed Wiring problem causes transformer
breakers to open actuating the
(paragraph 5.c)
LER 50-302/91-12 Closed Procedure deficiency leads to
inadvertent emergency diesel
generator actuation during
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engineered safeguards testing
(paragraph 5.d)
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LER 50-302/92-21 Closed Lack of Required Lube Oil Leakage
Collection lank Reserve Capacity For
Reactor Coolant Pumps Violates 10
CFR 50 Appendix R Design Criteria
(paragraph 5.e)
NCV 50-302/90-32-02 Closed failure to provide adequate design
control measures as required by 10
CFR 50, Aapendix B, Criterinn 111
(paragrap16.a)
URI 50-302/91-04-01 Closed Review and approval of inadequate
procedure steps for calibration of
reactor vessel level instruments
(paragraph 6.b)
8. Acronyms and Abbreviations
AHF - Air Handling fan
ANSI - American National Standards Institute
a.m. - ante meridiem
AP - Administrative Procedure
ASME - American Society of Mechanical Engineers
BS - Reactor Building Spray
B&W - Babcock & Wilcox
BWST - Borated Water Storage Tank
CFR - Code of Federal Regulations
CRDM - Control Rod Drive Motor
DHP - Decay Heat Pump
ECCS - Emergency Core Cooling System (s)
ENS - Emergency Notification System
E0P - Emergency Operating Procedure
EQ - Environmental Qualification
ES - Engineered Safeguards
FPC - Florida Power Corporation
FSAR - Final Safety Analysis Report
gpm - gallons per minute
HPI - High Pressure Injection System
LC0 - Limiting Condition for Operation
LER - Licensee Event Report
MAR - Modification Approval Record
MVP - Makeup and Purification System
NCV - Non-cited Violation
NRC - Nuclear Regulatory Commission
OP - Operating Procedure
p.m. - post meridiem
PR - Problem Report
PRC - Plant Review Committee
RB - Reactor Building
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- Reactor Coolant Pump
RSTS
- Revised Standard Technical Specifications
SE - Safety Evaluation
SP r
- Surveillance Procedure
SW - Short Term Instruction (
TMI - Nuclear Services Closed Cycle Cooling System
TS
- Three Mile Island
- Technical Specification
URI - Technical Specification Interpretation
- Unresolved Item
V - volt
VIO - Violation
WR - Work Request
B
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