ML20244C982
| ML20244C982 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 04/06/1989 |
| From: | Dance H, Levis W, Madden P, David Nelson, Ruland W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20244C969 | List: |
| References | |
| 50-324-89-05, 50-324-89-5, 50-325-89-05, 50-325-89-5, IEB-88-007, IEB-88-7, NUDOCS 8904210087 | |
| Download: ML20244C982 (25) | |
See also: IR 05000324/1989005
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION '
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REGloN il
I g 101 MARIETTA STREET. N.W.
s ATLANTA, GEORGI A 30323
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Report >o. 50-325/89-05 and 50-324/89-05
Licensee: Carolina Power and Light Company
P. O. Box 1551
Raleigh, NC 27602
Docket No. 50-325 and 50-324 License No. DPR-71 and DPR-62
Facility Name: Brunswick I and 2
Inspection Conducted: February 1 - March 15,1989
Inspectors: (- '
A ** 6 [
W. Rulan D6te Si' ned
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Dite'Si ned
P.
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. Madden
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D6te' Signed
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D. J. Nelso~n /
Date Signe'd
Approved By: b dNL ,/N
Fl. C. Daned, Section Chief Dat6 Signed
Division of Reactor Projects
SUMMARY
Scope: This routine safety inspection by the resident inspectors involved the
areas of maintenance observation, surveillance observation, operational safety
verification, Engineered Safety Feature System walkdown, onsite Licensee Event
Reports review, in office Licensee Event Reports review, handling of emergency
diesel generator fuel oil, implementation of requested actions of NRC Bulletin
88-07, installation and testing of modifications, drawing system verification,
and action on previous inspection findings.
Results: In the areas inspected three violations were identified. The first
violation involved the hanging of an improper clearance on certain Unit 1 SLC
valves, which led to the inadvertent draining of the SLC tank. Accordingly,
increased management attention is required over clearance control,
paragraph 12.g. The second violation, which is not being cited, involved a
failure to document a valve position change (locked open to open) on an
exception form. The third violation resulted from failure to adequately verify
correct pressure in stored pressure dry chemical fire extinguishers,
8904210087 890406 ^
PDR ADOCK 05000324
Q PDC
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paragraph 4.b. All three violations occurred in the operations area,
indicating that continued management attention is required over that work
group.
The licensee made an interpretation of the definition of " core alteration"
that is not supported by the current language of the Technical Sepcifications.
The licensee plans to submit an amendment request to NRR, paragraph 4.a.
Housekeeping remains a strength. However, system walkdowns still show that
minor leaks and other discrepancies are not being documented and corrected by
the plant staff, paragraph 5.b.
The licensee satisfactorily implemented Bulletin 88-07, but certain
discrepancies still require resolution, paragraph 9.
Plant drawings satisfactorily supported operations in the control room and
technical support center. A previous problem with timely delivery of aperture
cards to the control room was resolved through third party /QA in"olvement.
P&ID hard copies in the control room were well controlled with virtually no
plant modification outstanding. The licensee's complete yearly ' inventory of
CR/ Operations drawings should keep the aperture card file updated. Two system
descriptions were not adequately maintained current. Excessive plant
modifications remained outstanding against two SDs, paragraph 11.
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REPORT DETAILS
1. Persons Contacted j
Licen see . Employee s
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- K. Altman, Engineering Supervisor i
W. Biggs, Engineering Supervisor i
- F. Blackmon, Manager - Operations
J. Brown, Resident Engineer
- S. Callis, On-Site Licensing Engineer
T. Cantebury, Mechanical Maintenance Supervisor (Unit 1)
- G. Cheatham, Manager - Environmental & Radiation Control i
- M. Ciemnicki, Security
R. Creech, I&C/ Electrical Maintenance Supervisor (Unit 2) ;
- W. Dorman, Supervisor - QA i
- K. Enzor, Director - Regulatory Compliance i
R. Groover, Manager - Project Construction
- V. Grouse, Employee Relations
- J. Harness, General Manager - Brunswick Nuclear Project
W. Hatcher, Supervisor - Security
a. Hegler, npervisor - Radwaste/ Fire Protection
n. Helme, Manager - Technical Support
J. Holder, Manager - Outages -l
L. Jones, Director - Guality Assurance (QA)/ Quality Control (QC)
M. Jones, Director - On-Site Nuclear Safety - BSEP )
R. Kitchen, Mechanical Maintenance Supervisor (Unit 2)
G. Oliver, Manager - Site Planning and Control
- J. O'Sullivan, Manager - Training
- B. Parks, Engineering Supervisor
- M. Pastva, Senior Specialist
R. Poulk, Project Specialist - NRC
- J. Smith, Director - Administrative Support j
S. Smith, I&C/ Electrical Maintenance Supervisor (Unit 1) '
- R. Starkey, Project Manager - Brunswick Nuclear Project ,
- R. Warden, Manager - Maintenance i'
B. Wilson, Engineering Supervisor
- T. Wyllie, Manager - Engineering and Construction
Other licensee employees contacted included construction craftsmen,
engineers, technicians, operators, office personnel, and security force
members.
- Attended the exit interview.
Note: Acronyms and initialisms used in the report are iisted in
paragraph 14. l
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2. Maintenance Observation (62703)
The inspectors observed maintenance activities, interviewed personnel, and
reviewed records to verify that work was conducted in accordance with
approved procedures, Technical Specifications, and applicable industry
codes and ~ standards. The inspectors also verified that: redundant
components were operable; administrative controls were followed; tagouts
were adequate; personnel were qualified; correct replacement parts were
used; . radiological controls were proper; fire protection was adequate;
quality control hold points were adequate and observed; adequate
post-maintenance testing was performed; and independent verification
requirements were implemented. The inspectors independently verified that
selected equipment was properly returned to service.
The inspectors observed / reviewed portions of the following maintenance
activities:
87-AGDD1 Diesel Generator Centrol Panel Termination Connection
Inspection and Repair.
88-AXGN1 Service Water Valve SW-V18 Replacement of Valve Actuator
Grease.
88-BFMA1 Replacement of Emergency Control Room Ventilation Fan Motor !
Bearings.
89-AAWJ1 RSCS Card Inspection.
89-AfiIR1 Diesel Generator Building Basement Fire Retardant Cable
Coatings. ]
89-ADKE1 Diesel Generator No. 1, No. 7 Cylinder Valve Cover Gasket
Replacement.
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89-AFQC1 HPCI Injection Valve Testing.
89-DBF011 Breaker Compartment Inspection for 2-E11-F016A.
No violations or deviations were identified.
3. Surveillance Observation (61726)
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The inspectors observed surveillance testing required by Technical l
Specifications. Through observation, interviews, and record review, the i
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inspectors verified that: tests conformed to Technical Specification
requirements; administrative controls were followed; personnel were l
qualified; instrumentation was calibra;ed; and data was accurate and l
complete. The inspectors independently verified selected test results and I
proper return to service of equipment.
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The inspectors witnessed / reviewed portions of the following test
activities:
1MST-BATT14W Batteries, Spare, Weekly Operability Test.
IMST-PCIS24M PCIS High Condenser Pressure Trip Unit Channel Calibration.
2MST-APRM21Q APRM A and LPRM Group A Channel Calibration Functional
Test.
2MST-RHR27R RHR and CS Time Delay Relays Channel Calibration.
OI-3.1- Unit 2 C0 Daily Surveillance' Requirements.
PT-14.1.29 CRD System Charging Water Check Valve C11/C12-115,
Operability Test.
SRM Channel Functional Test Adequacy
AsL detailed' in inspection rsport 89-02, the inspector' questioned the
adequacy Lof the licensee's channel functional test performed on the SRMs-
prior to core alterations. Specifically, the inspector questioned why the
licensee's ' test did not detect a preamplifier problem on one SRM and a
control room-indicator problem on another SRM which occurred shortly after
commencing core load.
Channel Functional Test is defined in the Technical Specificai"sns as "the' 1
injection of a simulated signal into the channel as close to the primary
sensor as practicable to verify OPERABILITY, including alarm and/or trip
functions." The- licensee used 1/2 MST-SRM11W, SRM Channel Functional
Test, to meet this requirement. In the test, a square wave output is
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supplied from a ' function generator to the SRM input signal cable at the
SRM drawer. A counter is also connected to the drawer to measure the-
count rate. The frequency of the function generator is varied to
obtain the necessary count rates to check the alarm and trip functions of
the SRM. The associated count rate for the alarm and trip function is !
measured and recorded from the counter.
With this test configuration, the problems with the preamplifier and the i
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control room log count rate meter would not be detected. However, the
channel functional test does comply with the Technical Specification
requirements. A ~ simulated signal is inserted into the channel and- the
alarm and trip functions are verified. The preamplifier and log rate
count meter are verified on another surveillance test which is verified to
be current prior to core alterations. Also, after loading fuel around the
SRMs to establi sh sufficient' count rate, the licensee checks the
discrimination circuitry and high voltage power supply. The licensee has
agreed, however, to perform a two point check of their control room log
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l rate count meter during their channel functional test. The test signal
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will be supplied from a function generator and will check two points to
. ensure that the -control room indicator is' tracking properly. The' .
inspectors had no further questions concerning this issue.
No violations.or deviations were identified.
4. Operational Safety Verification (71707)
The inspectors verified that Unit I and Unit 2 were operated in compliance
with Technical Specifications and other regulatory requirements by direct
observation of activities, facility tours, discussions with personnel,
reviewing of records and independent verification of safety system status.
The' inspectors verified that control room manning requirements of
10 CFR 50.54 and the Technical Specif. cations were met. Control operator,
shift supervisor, clearance, STA, daily and standing instructions, and
jumper / bypass logs were reviewed to. obtain .information concerning-
operating trends and out of service safety systems to- ensure that there
were no conflicts with Technical Specification Limiting. Conditions for
Operations. Direct observations were conducted of control room panels,
instrumentation, and recorder traces important to safety in order to
verify operability and that operating parameters were within -Technical
Specification limits. The inspectors observed shift turnovers to verify
that continuity of system status was maintained. The inspectors also
verified the status of selected control room annunciators.
Operability of a selected Engineered Safety Feature division was verified
weekly by ensuring that: each accessible valve in the flow path was in
its correct position; each power supply and breaker was closed .for
components that must activate upon initiation signal; the RHR subsystem
cross-tie valve for each unit was closed with the power' removed from the
valve operator; there was no leakage of major components; there was proper
lubrication and cooling water availabie; and a condition did not exist
which might prevent fulfillment of the system's functional requirements.
Instrumentation essential to system actuation or performance was verified
operable by observing on-scale indication and proper instrument valve
lineup, if accessible.
Tha inspectors verified that the licensee's health physics
poiicies/ procedures were followed. This included observation of HP
practices and a review of area surveys, radiation work permits, postings,
and instrument calibration.
The inspectors verified that; the security organization was properly I
manned and security personnel were capable of performing their assigned
functions; persons and packages were checked prior to entry into the
'PA; vehicles were properly authorized, searched and escorted within the
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! PA; persons within the PA displayed photo identification badges; personnel
in vital areas were authorized; and effective compensatory measures were
employed when required.
i The inspectors also observed plant housekeeping controls, verified
l position of certain containment isolation valves, checked several
clearances, and verified the operability of onsite and offsite emergency !
power sources.
a. Shutdown Margin and Core Alteration Requirements l
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During a tour of the control room, the inspectors noted that the
licensee was removing Unit 1 control rods one at a time in order to 4
rebuild the associated control rod drive. Technical Specification 3.9.10.1, states the requirements that the licensee must meet. to
remove a single control rod evolution. Some of the requirements are:
SRMs are operable per TS 3.9.2. '
Shutdown margin specified in TS 3.1.1 satisfied. l
All other rods are inserted or have adjacent fuel removed.
Surrounding rods in a 5 x 5 matrix electrically disarmed.
The inspector questioned whether the SDM requirements were satisfied
since the core had been recently refueled and no SDM demonstration
specified by TS 3.1.1 had been performed. The licensee stated that
the SDM requirements were satisfied by analytical means and referenced
their Cycle 7 Core Management Report dated January 3, 1989, which 1
calculated a SDM of 1.89% delta K/K. The licensee did suspend all
further rod withdrawal until the question was resolved.
The inspectors examined Technical Specifications of other BWR
facilities and discussed the SDM requirement and core alterations
definition with regional and headquarters personnel. The inspectors
determined that NRC has accepted a calculation of SDM as an adequate
means of determining SDM at other facilities under certain
circumstances. However, the inspectors could find no information to
support the licensee's interpretation of core alterations.
During the inspection, the inspectors learned that the licensee did
not consider the insertion or withdrawal of control rods by their
normal means as a core alteration. Technical Specifications states
that " CORE ALTERATION shall be the addition, removal, relocation, or
movement of fuel, sources, incore instruments, or reactivity controls
in the reactor core with the vessel head removed and fuel in the
vessel. Suspension of CORE ALTERATIONS shall not preclude completion
of the movement of a component to a safe, conservative location."
The licensee felt that their definition was justified since the
original Unit 2 Technical Specifications specifically stated that ;
movement of control rods by normal means was not a core alteration.
Clearly, the current Technical Specifications have no such provision.
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The inspector found that no t tolation of Technical Specifications
occurred as a result of the licensee's incorrect definition of core
alterations. The inspector examined the time pe.riod .that the
shorting links were ~ installed during this reporting period. -
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f: inspector. noted - that, during this time, control rods were being
. withdrawn, their: respective control ' rod drive removed, rebuilt and -
reinserted, and the rod was timed to verify proper operation. These
actions were performed in accordance with procedure 0WP 7/1, Rev. 3,
Control Rod Drive Mechanism Removal With Fuel.in Vessel, and met ~the.
requirements of.TS 3.9.10.1. The inspector found no cases where the-
licensee violated TS 3.9.2 governing core alterations. during this
reporting. period as a result of their definition of core alterations.
.The licensee: plans to submit a TS amendment request to clarify the
definition of core ' alterations, and the SDM requirements. The
licensee will also submit a letter to NRR. explaining their position
on SDM and .the' adequacy of a calculation to' satisfy TS requirements
.for single or multiple control rod withdrawal and removal. This will
be an Inspector Followup Item: Submission and Approval of Clarifi-
cation of SDM and Core Alterations Amendment ' Request, (325/89-05-04
and 324/89-05-04).
b. Undercharged Fire Extinguishers
The inspector informed the control room of two fire extinguishers
that were inadequately ' charged on February 27, 1989. The two dry
chemical fire extinguishers were located on elevation 23' of the
Control Building, in the Unit 2 cable spreading room at fire
extinguisher station CB-2-2, and in the ' Unit 2 Reactor Building on
elevation - 80', west, at fire extinguisher station RX-2-26. On
March 8, 1989, the inspector found the undercharged extinguishers
still in place., Additionally, the inspector noted that the
extinguisher in the Unit 2 cable spreading room, according to the
inspection tag on the extinguisher, was inspected on March 8,1989,
and found to be acceptable in its' current under pressurized
condition.
Surveillance procedure OPT-34.11.2.1, Portable Fi re Extinguisher
Inspection . Reactor Building 1 and 2, Revision 6, section 6,
acceptance criteria 6.0.1.7 requires, for hand held stored pressure
dry chemical extinguishers, that the pressure gauge indicator must
fall within the acceptable range and, for those extinguishers that do
not meet this criteria, that they be replaced. The licensee did not
fully implement the requirements of this procedure and, therefore,
this is identified as a Violation: Inadequate Surveillance of Stored
Pressure Dry Chemical Fire Extinguishers (324/89-05-03).
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The licensee replaced the extinguishers on March 8, 1989.
c. RHR Valve Not Adequately Controlled
During a walkdown of the -17' elevation of the Unit 2 Reactor
' Building on March'14, 1989, the' inspector,1at 11:45 a.m., noted that'
-the.RHR pump D minimum flow isolation valve E11-F018D had the locking
chain and locking seal removed for maintenance without a clearance
being issued. No work was:in progress and the . work, replacement. of
the handwheel, appeared complete. The inspector. notified the control
room that the valve should be locked open.
Since the valve was not under a clearance and was not in the locked
open position required by the system operating procedure, the
position of.this valve should be controlled under 01-13, Revision.29,
Valve and Electrical Lineup Administrative. Controls. The shift .
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foreman -indicated that a valve lineup exception form was not
initiated as required by 01-13, section 4.8.3. The licensee
subsequently locked the valve in the open position. This is
identified as a Violation: Failure to Complete Valve / Breaker
Exception Form for an Unlocked Valve (324/89-05-02).
This violation meets the criteria specified in Section V of the NRC
Enforcement Policy for not issuing a Notice of Violation and is not
' cited.
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Two violations were identified.
5. Engineered Safety Feature System Walkdown (71710)
a. Duplex Strainer Position
During a walkdown of the Emergency Diesel Generator fuel oil system, ,
the inspector found the selecting lever on fuel oil discharge duplex
strainer mispositioned. The selecting lever can be placed in one of
three positions; to place either strainer element in service or to
place both in service. Interruption of flow is not possible,
however, by use of the selecting lever alone. The inspector found j
both elements in service, which defeats the purpose of a duplex j
strainer. No . element is kept clean to permit cleaning of a fouled i
element. With both elements in service, both would become fouled and -i
interruption of flow would be necessary to clean the strainer and {
return it to service. )
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The inspector notified the licensee of this condition. The licensee
agreed that a single strainer element should be in service and
returned the duplex strainer to the correct position. The licensee
could not determine when the incorrect lineup was made. This
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condition had no effect on EDG operability since the strainers were
not fouled. The inspector verified correct strainer alignment on the
remaining EDGs. The licensee determined that a misaligned strainer
could occur elsewhere in the plant because these strainer levers are
not identified on system drawings or by tagging. The licensee
initiated Surveillance Field Report 89-010 to address this concern.
The inspectors will review the licensee's actions during future
routine inspections.
b. Core Spray System Walkdown
The inspectors conducted a detailed assessment of the Unit 1 and
Unit 2 Core Spray Systems. The assessment included a review of
outstanding work orders, plant walkdowns to verify valve positions
and material conditions, and a check of selected core spray
surveillance procedures to determine their adequacy.
Physical verification of local and remote valve positions revealed no
discrepancies with actual position versus the required valve position
operating procedure valve lineup. However,'a review of the operating
system valve lineup for the Unit 2 A loop, OP-18, Revision 35, showed
three valves in a different position than shown on the P&ID, D-02524,
Sheet 2, Revision 22. The discrepancies are shown below:
E21-V4 indicates closed on P&ID, open on OP-18 valve lineup.
E21-V72 and E21-V81, indicate open on P&ID, closed on OP-18
valve lineup.
Physical inspection of the core spray systems revealed numerous
material deficiencies. None of the items found by the inspector
posed an operability concern. However, these type of items should be
detected and corrected by existing licensee programs. Examples of
items found by the inspector for which no existing trouble ticket or
work order could be found include:
Fluid leaking from low pressure vent fitting from
2-E21-FS-N006A.
Small grease leak from 2-E21-F031A, F031B, and 1-E21-F031B motor
actuators.
2-E21-F030 leaking.
Pipe caps missing f rom 2-E21-IV-783, IV-728, IV-726, IV-781,
F0218, V12, V11.
Junction box located behind pump 2A not secured (screws not
tightened) and upper conduit fitting taped to junction box.
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2-E21-V13 mi ssing handwh'e el .
Grease leaking from.1-E21-F001A.
Packing _ leak from 1-E21-F004B.
Grease ' dripping from motor T ' drain for 1-E21-F004B, _ and
2-E21-F0018.
Small oil leak at the bottom fill connection'for all four pumps.
These and other discrepancies were discussed with the system et.gineer.
The system engineer inspected the items 'and initiated work requests
as necessary to correct the discrepancies.
The licensee continues to develop the system engineers and organiza-
tional changes are. still in progress. Based on a comparison of the
Core Spray inspection and the RHR inspection in November, 1988, no
changes have occurred relative to system conditions. The inspectors
' will continue to inspect safety systems to monitor ' the licensee's
progress.
The inspector also checked PT-7.1.8, . Core Spray System Component
Test, - to determine its adequacy. The inspector noted that ' the 4
minimum flow valve, F031A(B), a valve in the flow path that is not 1
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locked, sealed, or otherwise secured in position, is not checked in.
its . proper position as required by TS 4.5.3.1.6.2. This valve is
normally open during no flow or low flow conditions and shuts when
core spray flow reaches a -specified value. The licensee stated that
this valve is not included in the PT because the position noted
during standby operati.on (0 pen) differs from the valve ' position i
expected when the core spray system operates! (Closed). When core
spray is injecting to the vessel, the minimum flow valve is a flow-
path boundary valve. The licensee also stated that the valve
position indicator on the RTBG is checked during shift turnover. The
inspector concluded that this valve position should - be checked as
part of the monthly PT. The issue of what constitutes a flow path
valve was raised in inspection report 88-38 and resulted in URI 325,
324/88-38-02. This item will be referred to the Region /NRR for
further clarification. This issue, the requirement to check the
position of the F031A(B) during the monthly PT, will be included with
the previous unresolved item.
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No violations or' deviations were identified.
6. Onsite Review of Licensee Event Reports (92700)
The below listed LERs were reviewed to verify that the information
provided met NRC reporting requirements. The verification included
adequacy of event description and corrective action taken or planned,
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existence of potential generic problems, and the relative safety
significance of the event. Onsite inspections were performed and
concluded that necessary corrective actions have been taken in accordance
with existing requirements, license conditions, and commitments.
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(CLOSED) LER 1-88-07, Primary Containment Group 1 Isolation Following
Reset of Main Turbine Trip Signal. The licensee revised Operating
Procedures 1-0P-26 and 2-0P-26, Turbine Operating Procedure, to require
that the "All Valves Closed" and the " Emergency Trip Reset" push buttons
be pushed and held until the mechanical and emergency reset lights come
on. This prccedural action should preclude the changing of the main
turbine speed logic selection from " Valves Closed" to "1800 RPM" whenever
the main turbine trip signal is reset. The inspector reviewed the
licensee's corrective ' actions associated with this event and found them
appropriate. 4
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(CLOSED) LER 2-87-10, Inoperability of Reactor Building Fire Hose Station !
2-RB-23 Resulting from Personnel Error During/Following Fire Drill. The
inspector reviewed the licensee's corrective actions associated with this
event. The licensee revised operating instruction OI-36, Shift Fire
Drills, to require that the equipment utilized during the drill be
identified on the drill evaluation sheet and verified that the equipment
is restored to an operable status. In addition, real time training on
this event was conducted for the radwaste/ fire protection operating
shifts. The inspector verified 0I-36 had been appropriately revised and
that the training was conducted as a part of the fifth quarter fire
brigade training session, course No. 88-1-5, completed on February 15,
1988. Based on the inspector's review of this event and the licensee's
corrective actions, the inspector found the licensee's response
satisfactory.
(CLOSED) LER 2-88-07, Pinhole Leaks and Linear Indications in the Insert ;
and Withdraw Lines of Unit 2 Control Rod Drives. The licensee, during the
Unit 21988 refueling outage, conducted a visual and liquid penetrant
inspection of the control rod insert / withdraw lines. The licensee found
pinhole and linear indications on 21 lines. The licensee replaced
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sections of 11 withdraw and 4 insert lines and performed a base metal
repair to one insert line. The remaining seven lines with indications
were evaluated and found acceptable by the licensee per the guidance of 4
ASME, Section X1 requirements. The licensee performed the inspection and !
repairs under plant modification PM-87-128, Unit 2 Refueling Outage Weld l
Overlays, Field Revisions 30, 31, 32, 35 and 39. In addition, the
licensee inspected the withdraw and insert CRD lines on Unit I under 1
PM-88-040, CRD Pipe Repairs. No unacceptable indications were identified !
using visual and liquid penetrant inspection techniques. The inspector j
reviewed the licensre's corrective actions associated with the repairs
made on Unit 2 and the results of the CRD line inspection conducted on
Unit 1 and found them acceptable. .
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(CLOSED) LER 2-88-12, . Inability of High Pressure Coolant Injection System
Auxiliary 011 Pump Motor Termination Splices to Meet Environmental
Qualification Criteria. The inspector reviewed the documentation package
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and other inspection reports' dealing with the :HPCI Auxiliary 011 Pump
Mctor Splices. Previous insoection in this . area are documented in
inspection reports 88-24 and 88-39. Based on these previous inspections
and the information provided in the- LER, the inspector had ro further
questions.
No~ violations or deviations were identified.
7. In Office Licensee Event Report Review (90712)
The below listed LER was reviewed to verify that the information provided
,
met NRC reporting requirements. The verification included adequacy of
event . description and corrective action taken or planned, existence of
potential generic problems, and the relative safety significance of the
event.
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(CLOSED) LER 1-88-21, Primary Containment Group 6 Isolation, Reactor i
Building Ventilation Isolation- and Standby Gas Treatment System
Auto-Starting During Cancellation of 48 VDC Battery Clearance.
No violations or deviations were identified.
8. TI 2515/100 (25020)
(OPEN) TI 2515/100, Proper Receipt, Storage and Handling of Emergency
Diesel Generator Fue, 011.
Events at other operating reactor sites involving problems' with DG fuel
oil and fuel oil systems prompted the NRC to issue the above Temporary
Instruction. This TI provides inspection guidance to NRC . inspectors to
evaluate the likelihood of similar events occurring at individual reactor
sites. The inspector conducted a portion of this TI during this reporting
period. This inspection consisted of collecting specific information
regarding the licensee's diesel fuel oil system with emphasis on fuel oil
sampling and analysis. The inspector noted discrepancies between NRC
Regulatory Guide 1.137, Revision 1, Fuel Oil Systems for Standby Diesel
Generators, an FSAR commitment, and actual programs and practices of the
licensee. For example, the licensee is not cleaning and inspecting all
fuel oil storage tanks at a 10 year minimum interval per Regulatory
Guide 1.137. These discrepancies were also noted by the licensee's site
QA/QC and are being dispositioned in accordance with the licensee's-QA/QC
program. None of these discrepancies appear to affect the operability of
the Emergency Diesel Generators. However, the inspectors will monitor the
licensee's action to ensure all issues are properly resolved.
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The inspector also noted a problem with a fuel oil system strainer that
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may be generic to many strainers / filters at the site. This is. discussed '
in detail in paragraph'5.a of this report.
No violations or deviations were identified.
9. TI.2515/99 (25599)
(CLOSED) TI 2515/99, Implementation of Requested Actions of NRC
Bulletin 88-07, Power Oscillations in Boiling Water Reactors.
The Bulletin describes a double recirculation pump trip event at 'LaSalle
Unit 2 where significant thermal-hydraulic instabilities occurred in the
reactor. . After the recirculation pumps tripped, feedwater heating
automatically isolated and core flow was due to natural circulation.
Under those power to flow conditions, peak-to peak oscillations were from
. 25?; to 50?4 power every two to three seconds as indicated on the. Average
Power Range Monitors. Seven minutes after the dual pump trip, the unit
scrammed automatically on high neutron flux. The Bulletin - and its
supplement requests BWR licensees, including Brunswick, to take certain
actions in response to the LaSalle event.
The inspector interviewed personnel, reviewed procedures and training
materials, and examined instrumentation ' to verify that the licensee.
completed the committed actions from the Bulletin.
a. Briefing on LaSalle Event
The inspector interviewed 12 operations personnel (SR0s, R0s, STA),
about the LaSalle event. Twenty-five percent of the operators
interviewed recalled. few event details. All operators interviewed
recalled the new procedural required actions for thermal-hydraulic
instability.
b. Procedure Changes
l The inspector verified that the licensee revi scri the appropriate
procedures to:
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Require a manual scram if both recirculation pumps trip when
the mode switch is in RUN (A0P-4.3, Rev. 8, February 6,1989,
Recirculation Pump Trip and Others).
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Require a manual scram, if region A of the power to flow map,
was entered.
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Require a manual scram if indications of instability occur.
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Identify indications of thermal-hydraulic instability - 10% peak
to peak APRM oscillations or LPRM upscale-downscale alarms. I
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The inspector reviewed . the below listed procedures, which also
.contain revised-guidance per above, for thermal-hydraulic instability:
0-A0P-4.0,' Rev. 6, Recirculation Flow Control Failure - Decreasing
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0-A0P-4.1, Rev. 4, Recirculation Flow Control. Failure - Increasing
Flow
.1/2-0P-02, Rev. 17 & 62, Reactor Recirculat' ion System Operating.
Procedure
GP-04', Rev. 14, Increasing. Turbine Load to Rated Power
GP-05, Rev. 30, Unit Shutdown
1-APP-A-06, Rev. 6,' Annunciator Response Procedure
2-APP-A-06, Rev. 7, Annunciator Response Procedure
The inspector.noted these problems:
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In the above annunciator procedures, window 1-7, LPRM Downscale,
requires a reactor scram if power is i 15%. This criterion
differs from the 10% peak to peak ( Sis) interim , corrective
actions published by.GE. All other procedures used the 10f, peak
-to peak criterion as required.
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During a procedure walk through using A0P-4.3 with a control
operar.or, the inspector noted.that the procedure caution refers
to the 8094 rod line but the power to flow map with the rod line
is not included with the procedure.
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No guidance for using Select Rod Insert on Unit 2 was provided i
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to the operators, either in procedures or training. The . SRI
button allows, on Unit 2 only, the operator to scram
pre-determined rods to rapidly reduce power. A0P-4.3 instructs
the operator to use SRI if above 5094 power, if desired. 1
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Most operators interviewed did not completely recall the pro-
hibitions in OP-2 not to intentionally enter thermal-hydraulic j
instability regions A&B, J
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1/2-APP-A-06, window 1-7, refers the operator to Technical i
Specifications, but not the AOPs, which require operator actions
sooner than TS.
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c. Instrumentation
The licensee verified that'LPRM/APRM instrumentation had no filtering
that could mask thermal-hydraulic instabilities. All APRM chart
recorders in the control room were checked by the licensee to verify.
.that the full scale deflection setting was one second. Maintenance
did find one recorder set at 5 second ' full scale deflection and
corrected it. The inspector reviewed the procedure . revision request-
88-2094 for new procedure OPIC-UR008, which will incorporate . the
maintenance requirement to verify the setting of recorder response
time.
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The licensee identified no deficiencies- in instrumentation that-
required procedural. compensation.
d. Technical Specifications
The ' licensee addressed thermal-hydraulic instability in TS .3.4.1.1
through amendments 114. and 142.-approved December 30, 1987. Those
amendments incorporated the recommendations of GE Service Information
Letter SIL-380, Rev. 1, dated February 10,.1984. Current procedures.
are more restrictive than the TS, thus the procedures are consistent-
with TS'.
,e. Training Programs
The licensee has integrated thermal-hydraulic instability and the
LaSalle event into their licensed operator training program. The
inspector reviewed updated training materials and observed a
simulator exercise to verify implementation. The simulator staff
demonstrated their simulation of instability using their current BWR
model.during a dual recirculation pump trip. LPRM indication did not
show the swings as soon as expected. APRM response was all in unison
and the indicators moved in a jerky fashion. In spite of the
indi. cation-problems, the inspector believes that the general behavior
of the reactor during conditions of instability was reasonably
demonstrated to the operators. The licensee does not . routinely
demonstrate instability to all operators during training. No
specific training syllabus requires simulation to the operators of
instability. under 2 pump, single pump, and natural circulation
conditions.
The inspector concluded that the licensee's response to the bulletin was
sati sf actory. However, the problems found by the inspector require
resolution by the licensee.
No violations or deviations were identified.
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10. Installation and Testing of Modifications (37828)
The licensee is currently implementing on Unit 1 a HPCI Reliability
Improvement Plant Modification, PM-88-051. The purpose of this
modification is to improve system reliability by: (1) the addition of an
oil bypass line around the Woodward EGR Actuator; (2) rerouting tubing
between the Woodward EGR Actuator and the remote servo; (3) deletion of
the opening rate control valve and bypass tubing on the HPCI Turbine Stop
Valve (E51-V8), and; (4) the addition of a 10 second time delay to the low
suction pressure pump trip.
The EGR bypass portion of this modification allows hydraulic oil pressure
developed from the auxiliary oil pump to move the control valve prior to
HPCI turbine startup. This, in conjunction with a reduced idle voltage
setting on the ramp generator signal converter, will allow the control
valve to open, then partially close prior to the opening of the stop
valve. Thus, this portion of the modification, along with the rerouting ,
of the tubing between the EGR actuator and the remote servo, will allow
the control valve to absorb the majority of the initial steam differential
pressure during the turbine quick start transient, reduce the initial
quick start turbine speed peak, and reduce the turbine exhaust line
pressure transient.
In addition, the licensee, under this modification, installed a 10 second
time delay relay in the low pressure pump suction logic. The intention of l
this delay is to prevent the pump from tripping due to pressure spikes
experienced during pump startup.
The licensee had confirmed that a low suction pressure trip was the cause
of a Unit 2 HPCI turbine trip on November 16, 1988. (see inspection
report 88-39), by conducting a full flow injection test on January 28,
1989. The test showed that a turbine low suction pressure alarm occurred
upon initial HPCI injection into the reactor vessel . Since the low
suction pressure trip had been previously bypassed, HPCI did not trip.
The. inspector reviewed the licensee's HPCI Reliability Improvement Plant
Modification, verified that the specified suction pressure trip time delay
relay was installed and wired into the HPCI logic in accordance with the
drawings and instructions provided in the modification package, and
confirmed that Acceptance Test No. 6 of the PM properly tested the changes
to the suction pressure trip logic. However, the inspector found that the
PM did not identify that u revision to MST-HPCI41R was required.
Currently MST-HPCI41R, Revision 5, Section 7.0, Step 7.8.124 tests the low
pressure suction trip function. However, the procedure was not revised to
test and calibrate the time delay function of the circuit. The licensee
said they will issue a field revision to the PM to include a draf t
revision to MST-HPCI41R.
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In addition, the licensee plans to perform a HPCI vessel injection test )
upon Unit I restart to evaluate the improvements in system reliability. l
The test results, the licensee's evaluation of these test results, and the i
overall assessment of the improvements in reliability will be evaluated
during a subsequent NRC inspection.
No violations or deviations were identified.
11. Drawing System Verification (71707) a
1
The inspector conducted a review of the licensee's drawing control in the
control room arid Technical Support Center. The review attempted to
determine whether the licensee's drawing control efforts and programs
satisfactorily supported operators in a meaningful way. The inspection
included review and verification of a biased sample of drawings. The
inspector reviewed about 30 control room / operations aperture cards and
drawings, over 30 hard copy Unit 1 P& ids, and about 30 aperture cards in
the TSC. That review included verification of:
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Drawings present where distribution required.
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Drawing or aperture card legibility.
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Drawing list revision number matched drawing revision.
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No outstanding plant modifications against the drawing that made the
true status of a system difficult to determine.
The inspector found:
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Six missing drawings:
FP-55109, SH 1, 7, 8, Primary Containment Isolation System
elementary logic, located in the Operations aperture collection
in the back panel area of the control room. (Those same
drawings were in the control room aperture card file.)
FP-F5109, SH 12, PCIS elementary logic, located in the control
room aperture collection.
FP-50015 SH 1, Reactor Protection System, Unit 2, in the TSC.
D2020, SH 1, a Unit i hard copy drawing that was non-safety
related.
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FP-55109, SH 12, Operations - was difficult to read. (Note that the
j same sheet was missing from the control room.)
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D-7029, SH 2A, Unit 2 Instrument Air System P&ID, was still stamped
as requiring an update per PM-82-288FF. The inspector and an
operator walked through the drawing verification process using this
drawing. The drawing had already been updated and thus was
incorrectly marked.
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Two binders of hard copy P& ids were in the training library. The i
library becomes part of the TSC when an alert or higher is declared.
The Accident Assessment Team uses the information in the library to
evaluate an event. No uncontrolled documents should be available for
their use.
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Less than 1% of hard copy P& ids for Unit I had outstanding plant
modifications against them, thus requiring little additional work by
the operators.
Other observations:
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Per 0I-29, Operations Internal Audit, the licensee had just completed
(early 1989) a complete inventory of all control room operations
aperture cards and hard copy P& ids. Several lists of missing
drawings were sent to document control to complete the control room
collection. The licensee had not, by the close of the inspection,
verified whether the missing drawings identified by the inspector had
also been identified by the operations staff.
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The inspector also found that certain System Descriptions, or SDs,
had too many plant modifications not incorporated in the document.
Specifically, 50-18, Rev. 12, Core Spray System, had 8 plant
modifications not incorporated and SD-19, Rev. 12, HPCI System, had 5
plant modifications not incorporated. While the SDs are not
operating procedures, they do describe the system and are available
in the control room.
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The licensee corrects drawings using ENP-25, Rev. 6, Plant Drawing
Correction Procedure. The procedure controls any corrections to
drawings and requires a technical review of the drawing change with
project engineer approval. The appropriate engineering document for
safety reviews, an EER, is referenced in ENP-25.
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A previous audit by a third party found that as-built P& ids had not
been available to operations prior to, nor at the time the plant ]
modification was declared operable. It took about two weeks before 1
the updated aperture card was transmitted and made available to {
operations. QA issued SFR-88-042 on September 26, 1988, to track the l
resolution of the issue. By meno, on March 14, 1989, the licensee ]
intends to issue a second " original" aperture card drawing directly
to operations as an advance copy prior to declaration of operability.
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A P&ID comparison was made with the as-built plant condition as part.
of module 71710 (see paragraph 7 of this inspection report for Core
Spray and paragraph 6 in inspection report' 88-38 for RHR). The plant.
configuration matched the P& ids. However, as noted, the operating
procedure did not- match the P&ID indicated position , in rare
instances. The OP governs valve position at Brunswick. However, the
licensee still plans to correct the drawings.
The . inspectors concluded . that -the system for maintaining control room
drawings was satisfactory and usable.
No violations or deviations were identified.
12. Action on Previous Inspection Findings (92701) (92702)
a. (CLOSED) Violation 325/86-11-03 and 324/86-12-03, Failure to Install
Standby: Liquid Control Relief Valves With Discharge . Flooded. The
licensee. has co'mpleted a plant modification that installed vent
valves in the SLC relief valve discharge piping. Appropriate changes
were made to, operating procedure OP-5, SLC System, to provide for-
filling and venting the discharge piping. The inspector reviewed the
procedure and inspected the vent valves. They cbtermined to be y
adequate .to ensure' that the discharge piping is flooded to prevent i
boron precipitation within the valves, as . committed" to in FSAR !
Section 9.3.4.2. Additionally, the licensee reviewed the i FSAR - to I
-ensure that plant procedures properly implement other =FSAR ;
commitments for the SLC system. No additional discrepancies were .i
found. I
b. (CLOSED)- Violation (325/87-02-05 and 324/87-02-05), Failure to
Follow Maintenance Procedure When Installing Motor-0perated Valve
Anti-Rotation Devices. The inspector reviewed the results .of; the
licensee's anti-rotation device inspection which they . conducted .in'
response to this violation. This inspection was conducted under 4
Special . Procedure SP-87-002, . Inspection of Anchor Darling i
Anti-Rotation Devices. The licensee inspected 41 pressure seal-globe '
valves on Units 1 and 2. They found six valves with problems
associated with the installation / maintenance of the anti-rotation
device. Based on this review, the inspector determined that the 1
licensee's assessment as to the cause of this violation is correct. I
To prevent recurrence, the licensee revised the applicable procedure
to require that the lead mechanic sign off on the data sheet that the
work has been done properly. The inspector. reviewed corrective
procedure CM-VGB509, " Anchor Darling Pressure Seal Globe Valves",
Revision 0, dated September 27, 1988, and verified that section 7.9.2'
and 7.9.3 requires that the lead mechanic verify and sign off on the
data sheet that the anti-rotation device installation / maintenance
work activities were performed in accordance with the procedure.
This had also been inspected in inspection report 88-01.
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-c. (CLOSED)- Violation 325/88-14-03, ~ Failure to Perform 10 CFR 50.59
.
Evaluation on~ Service Water System. .The inspector. reviewed the
circumstances of the event and the licensee's response-to the. Notice
of.' Violation dated June 3,1988. The inspector verified that the
actions committed to by the licensee were' accomplished. The
inspector did note that the licensee missed' the commitment date of .
September 1,1988, for the. development 'of improved policy guidance
concerning conditions which constitute-potential deviations from the
facility as described in the FSAR. The. failure to meet this
commitment date was identified by .the licensee and result.ed in the
issuance.of an.NCR. The guidance was subsequently provided. in .a
memorandum dated September 7, 1988.'
d .' -(CLOSED) Unresolved- Item 325/87-36-05 and 324/87-37-05.- MSIV Pit
Openings Not on Q-List; Reactor Building EQ Envelope May be Affected.
This issue involved the potential for unsealed penetrations from'the'
MSIV pit'to the Reactor Building which, in the event of a MSLB in the .
pit, could possibly result.in higher peak temperatures and pressures l
in the. Reactor Building than previously. analyzed in the licensee's EQ ,
program. The largest of the penetrations, one ventilation exhaust .
line and two ventilation supply lin~ es, are designed to automatically
close in the event of a MSLB due to the pressure surge. However,
.these' dampers are not on the Q-List and, therefore, no credit can be
taken for them to perform their safety function.
The licensee performed an initial assessment - of the issue and
concluded that continued operation of both units was justified. This
conclusion was reached principally upon a comparison of the energy
releases into the general areas of the Reactor Building associated
with the previously analysed 10" HPCI DEGB versus that from the
various postulated short lived MSL critical crack / double ended ..
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guillotine scenarios. Subsequent to the initial assessment, the
licensee has performed additional analysis to show that the harsh
environment in the Reactor Building (excluding the MSIV pit) due to a ,
MSLB in the pit, is bounded by their previous Reactor Building j
analysis.
The additional analysis was presented in EER 89-0020, dated
January 24, 1989. The evaluation uses Reactor Building temperature /
pressure response data from UE&C Study Report 7992-303-S-W-048, dated
January 31, 1989. The report evaluated certain break sizes, time
response and damper positions, and the effect on the EQ envelope. '
The evaluation further states that a DEGB was not considered because
stress analysis results and the configuration of pipe whip restraints
preclude an assumption of a DEGB in the pit
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,The. pressure and ' temperature transients resulting from. each of the -
cases examined, show that'the licensee's previous Reactor Building-
environmental profile is still the limiting case for'all-' areas in the
Reactor Building except for: the MSIV. pit. 'The previous MSIV peak-
temperature was '297 degrees F. The 'new profile, based on case 1
above, . shows a peak temperature of ' 375 degrees. F. The licensee
evaluated this condition and concluded that this profile did not
, impact on the qualification of FQ equipment' installed in the MSIV
pit. This conclusion was based on the short lived nature of the
profile and that the EQ equipment located in the pit had been
previously -qualified for conditions ' representative of drywell
accident environments. Although the licensee considers this new
profile to be acceptable for existing equipment in the pit, they will
update their Reactor Building environmental report to snow these new
parameters.
e. (CLOSED) Unresolved Item 325/88-18-06 and 324/88-18-06, Control Room
Fire Detectors' Affect on CBEAF Operability. In response to the
inspection item, the licensee re-examined the operability' of CBEAF
with the loss of the automatic initiation function due to smoke
detection in the control room area. The licensee determined that the
smoke detection function was required for. the CBEAF system to be
considered operable. To clarify this information for the operators,
a Memorandum, BSEP/89-0110, was sent to the operations manager
explaining - the requirement for the . smoke detection function for
CBEAF. In addition, the licensee has modified PT-34.4.1.3 Control
Building Fire Detection Instrumentation Operability Test, .to
discontinue the use of the disconnect switch.
The inspector then reviewed completed copies of PT-34.4.1.3, to
determine if any violations of the plant's TS occurred. The time
that' the disconnect switch for the alarm panel was taken to
disconnect was not recorded during the performance of the test,
however, a caution was placed in the procedure which requires that
the system be aligned for normal operation if a break of greater than
15 minutes were to oct.ur during the performance of the test. Based
on this information and the inspector's observation during the
performance of the test, the TS time limit was not exceeded.
f. (OPEN) Unresolved Item 325/88-38-02 and 324/88-38-02, Failure to
Include All LPCI and Suppression Pool Cooling Flow Path Boundary
Valves in Their Surveillance Program. Further questions were raised
by the inspectors concerning flow path boundary valves and the
necessity to verify their valve position as part of the required
monthly surveillance check. Specifically, the core spray minimum
l flow valve, F031A/B, is not checked monthly for proper position, The
1 licensee has stated that this valve is not in the flow path when core
spray would be performina its safety function, namely, injecting
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water to the reactor vessel. This' item will remain unresolved- i
pending Region /NRR response to clari.fy requirement to check flow path
boundary valves. (See paragraph 5.b.)
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g. '(CLOSED) . Unresolved Item 325/89-02-03, Inadvertent Draining' of SLC
Tank. The inspector reviewed the' licensee's operability assessment
of the -SLC system during the inadvertent draining event. The
licensee concludedLin their evaluation that the SLC remained operable
during the' time that water Ws inadvertent 1y' drained from the SLC
tank through the F010/F014 valve bonnets. The licensee's conclu,lon
was based on the volume / concentration of the tank at the time of toe
event, the leak rate caused by the work, the injection requirements
of SLC had it been required, and the NPSH'available to'the SLC pumps.
The inspector had no other questions concerning the operability of
the SLC system.
, As noted in inspection report 89-02, the lean from the SLC tank
resulted from inadequate clearance / work control:,. The work involved
repairs to valves .the F010 and F014 which were contributing to
demineralized water leakage into the SLC tank. The-clearance which
established the work boundaries was not adequate for work on the F010
and F014 valves. Even if the work had been only on the F010 valve as
thought-by the SF authorizing the clearance, the boundary still would'
not .have been sufficient; however, no leakage would have occurred.
Maintenance personnel also removed the locking devices'-from both the
valves (with operation's permission), operated the' valves, and then
proceeded to loosen the bonnet bolts. The manipulation of valves by
maintenance personnel is permitted by- plant procedures proviaed the
~ valves are within the established work boundaries and the valves are
listed in Attachment C, BSEP. Clearance Tag Sheet. Attachment C of
clearance 1-189A,. which established the boundaries, did not list the
F010 or .the F014 as valves to be manipulated. The inspector also
noted that the maintenance personnel had accepted clearance 1-189A,
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signifying that they agreed the clearance was adequate for the work.
I The failure of plant personnel to follow plant procedures concerning
equipment clearances. is listed as a Violation: Failure to Follow
Equipment Clearance Procedures (325/89-05-01).
One violation was identified,
l 13. Exit Interview (30703)
The inspection scope and findings were summarized on March 15, 1989, with
those persons indicated in paragraph 1. The inspectors described the i
areas inspected and discussed in detail the inspection findings listed '
below and those addressed in the report summary. Dissenting comments were
l not received from-the licensee. Proprietary information is not contained
in this report.
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-Item Number Description / Reference Paragraph
325/89-05-01 VIOLATION - Failure to Follow Equipment
Clearance Procedures, (paragraph 12.g).
324/89-05-02 VIOLATION - Failure to Complete Valve / Breaker
Exception Form for an Unlocked Valve,
(paragraph 4.c).
324/89-05-03 ;IOLATION - Inadequate Surveillance of Stored
Pressure Dry Chemical Fire Extinguishers,
(paragraph 4.b).
325, 324/89-05-04 IFI - Submission and Approval of Clarification
of SDM and Core Alterations, (paragraph 4.a).
14. List of Abbreviations for Unit 1 and 2
AI Administrative; Instruction
A0 Auxiliary Operator
AOP Abnormal Operating Procedure
APRM Average Power Range Monitor
ASME American Society for Mechanical Engineers
BSEP Brunswick Steam Electric Plant
BWR Boiling Water Reactor
CBEAF Control Building Emergency Air Filtration
C0 Control Operator
CP Corrective Procedure
CR Control Room I
CRD Control Rod Drive
DEGB Double Ended Guillotine Break
DG Diesel' Generator
EDG Emergency Diesel Generator
EER Engineering Evaluation Report
ENP Engineering Procedure
EQ Environmental Qualification
ESF Engineered Safety Feature
F Degrees Fahrenheit
FSAR Final Safety Analysis Report
HP Health Physics
HPCI High Pressure Coolant Injection
I&C Instrumentation and Control
IFI Inspector Followup Item
IPBS Integrated Planning Budget System
LER Licensee Event Report
LPRM Local Power Range Monitor
MSIV Main Steam Isolation Valve
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23
MSLB Main Steamline Break-
MST' Maintenance Surveillance Test
.NCR. .Non-Conformance Report
NPSH- Net. Positive Suction Head-
'NRC Nuclear Regulatory Commission
0I Operating Instruction
0F Operating Procedure-
OWP Operations Work Permit
P&ID Piping & Instrumentation Data
PA Protected Area
PCIS Primary Containment Isolatien System
'PM . Plant Modification
PNSC : Plant Nuclear Safety Committee
PT- ' Periodic Test
-QAL . Quality Assurance
QC- Quality Control
RSCS Rod Sequence Contro1' System
'RTGB Reactor Turbine Gauge Board
SD System Description
SDM' _ Shutdown. Margin
SF Shift Foreman
SIL Service Information Letter
SRI Select Rod Insert
SRM Source Range Monitor.
STAE Shift Technica1' Advisor
ETI . Temporary Instruction
TS Technical Specification
TSC . Technical Support Center
UF&C United Engineers & Constructors
.URI' Unresolved Item
VDC Volts Direct Current
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