ML20236A036
| ML20236A036 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 03/06/1989 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20236A031 | List: |
| References | |
| TASK-06-04, TASK-6-4, TASK-RR 50-245-89-02, 50-245-89-2, GL-88-14, IEB-83-06, IEB-83-6, IEB-87-002, IEB-87-2, NUDOCS 8903160286 | |
| Download: ML20236A036 (21) | |
See also: IR 05000245/1989002
Text
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No. 50-245/89-02
' Docket No. 50-245 License No. DPR-21
Licensee: Northeast Nuclear Energy Company
Facility: Millstone Nuclear Power Station, Unit 1
-Inspection At: Waterford, Connecticut
Dates: January 10 through February 13, 1989
Inspectors: William Raymond, Senior Resident Inspector
Lynn Kolonauski, Resident Inspector, MP-1 (Reporting Inspector)
Peter Habighorst, Resident Inspector, MP-2
Scott Barber, Resident Inspector, MP-3
Approved by: N b. N j r. 3/ 6/87
E. C. McCabe, Chief, Reactor Projects Section IB Date
Inspection Summary:' Inspection from January 10 to February 13, 1989 (Report No.
50-245/89-02)
' Areas Inspected: Previously identified items, plant operations, physical security,
licensee response to a 10 CFR Part 21 report involving Limitorque motor-operators,
post-accident operability of the reactor building to torus vacuum breaker butterfly
valves (1-AC-3A and 38), environmental qualification of Reactor Water Cleanup
isolation valves 1-C0-2 and 3, status of the Revision 2 emergency operating proce-
dures, maintenance and surveillance, licensee event reports and committee activi-
ties.
Results: The inspection identified no unsafe plant conditions. The inspection
involved 177 inspection hours (with 20 backshift hours, including 11 deep backshift
hours). Further follow-up is planned for: (i) the deficiencies identified during
walkdown of the standby liquid control system (Detail 4.3), (ii) issues related
to 1-AC-3A and 3B (Detail 6.0), and (iii) environmental qualification (Detail 7.0).
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8903160286 890308
Q ADOCK 05000245
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TABLE OF CONTENTS
PAGE
1.0 Persons Contacted.................................................... 1
2. 0 - S umma ry o f Fa c i l i ty Ac t i v i t i e s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
' 3.0 Status of Previous Inspection Findings (93702, 71707)................ 1
3.1 (Closed) IFI 87-26-01, "SSSA Training on Wind Direction"........ 1 ,
3.2 (Closed) TI 2500/26, " Fastener Testing to Determine Conformance
with Applicable Material Specifications (NRC Bulletin 87-02)". 1 i
3.3 (Closed) IEB 83-06, " Nonconforming Materials Supplied by the
Tube-Line Corporation"........................................ 2
3.4 (Closed) 88-25 Section 6.2, TI 2515/98, " Containment Temperature
Profiles"..................................................... 2
4.0 Facility Tours and Operational Status Reviews (71707, 71710).......... 3
4,1 Safety System Operability....................................... 3
4.2 Review of. Plant Incident Reports................................ 4
4.3 Engineered Safety Feature - Standby Liquid Control . . . . . . . . . . . . . . 4
5.0 10 CFR 21 Report on' Melamine Torque Switches in Limitorque Motor
Operators (93702).................................................. 5
- 6.0 Post-accident.0perability of Reactor Building to Torus Vacuum Breaker
Butterfly Valves 1-AC-3A and 3B (93702, 71707)..................... 6
7.0 Environmental Qualification of Reactor Water Cleanup Isolation Valves
1-CU-2 and 3 (37700, 37828, 71707)................................. 9
8.0 Emergency Operating Procedures (71707)............................... 11
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9.0 Maintenance (62703).................................................. 16
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10.0 Surveillance (61726)................................................. 18
11. 0 Licen see Event Reports (92700) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
12.0 Plant Operations Review Committee (71707)............................ 18
13.0 Management Mett,ng- (30703).......................................... 19
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DETAILS
1.0 Persons Contacted
J. Stetz, Unit 1 Superintendent
R. Palmieri, Operations Supervisor
P. Prezkop, Instrumentation and Controls Supervisor
N. Bergh, Maintenance Supervisor
W. Vogel, Engineering Supervisor
M. Brennan, Health Physics Supervisor
The inspectors also contacted other members of the Operations, Instrumentation
and Control, Maintenance, Engineering, and Health Physics departments.
2.0 Summary of Facility Activities
Millstone 1 operated at full power except for normal power reductions for
routine surveillance and main condenser back-washing. Also, on January 17
at 9:00 p.m., power was reduced to 90% for restart of the "B" condensate
booster pump after replacement of its outboard seal. The unit returned to
full power by 9:30 p.m. on January 17.
3.0 Status of Previous Inspection Findings
3.1 (Closed) IFI 87-26-01, SSSA Training on Wind Direction
This item addressed the incorrect wind directions reported by the Shift
Supervisor Staff Assistant (SSSA) during the October 8,1987 exercise.
NRC combined Inspection Report 50-245/88-23; 50-336/88-26; 50-423/88-20
covered the licensee's annual emergency preparedness exercise conducted
on November 16, 1988 and reported closure of associated inspector fol-
low-up item (IFI) 50-423/87-20-01 after the inspectors verified correct
licensee reporting of wind direction during the 1988 exercise. That re-
port did not close the associated Millstone 1 item, which is hereby
closed.
3.2 (Closed) TI 2500/26, " Fastener Testing to Determine,Conformance with
Applicable Material Specifications (NRC Bulletin 8l_02)"
NRC Bulletin 87-02 asked licensees to review their receipt inspection
requirements for fasteners and to determine through independent testing
whether fasteners in stock met mechanical and chemical specifications.
As reported in NRC Inspection Report (IR) 50-245/88-02, the licensee's
test program identified seven discrepancies out of the 160 fasteners
tested. Of the seven, two were found to be nonconforming and were dis-
positioned for use "as is" because their out-of-tolerance condition did
not significantly affect their strength, ductility, or corrosion resist-
ance. The licensee concluded that no additional action was warranted
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relative to the fasteners in stock. The inspector noted no inadequacies
in the licensee's conclusions and that TI items 5.01 and 5.02 would be
addressed prior to TI closure.
TI items 5.01 and 5.02 specified comparison of the licensee's bulletin
response to the receipt inspection program. The inspector determined
that the response accurately described the contents of the following pro-
cedures: Quality Services Department (QSD) 3.08, " Performance of Receipt
Inspection Activities" and QSD 3.07, " Preparation, Performance and Re-
porting of Source Inspections." The inspector had no further questions.
This TI is closed. i
3.3 (Closed) IEB 83-06, " Nonconforming Materials Supplied by the Tube-Line
Corporation
Power reactor licensees received notification of nonconforming materials
supplied by the Tube-Line (T-L) Corporation through Information Notice
83-07 dated March 7, 1983. The NRC subsequently issued Bulletin 83-06
on July 22, 1983 after NRC inspection of T-L facilities identified the
potential for generic safety implications at plants that either received
direct material shipments from T-L or from sources which incorporated
T-L materials. The licensee responded to Bulletin 83-06 by letter dated
November 7, 1983.
The licensee's review identified no direct T-L shipments to Millstone,
but confirmed the 1982 receipt of 342 QA stainless steel flanges from
Guyon Alloys, Incorporated which were accompanied by T-L documentation.
This transaction was listed in Attachment 3 to IEB 83-06. Licensee re-
view of heat code information supplied by T-L determined that 289 of the
342 flanges lacked annealing heat treatment. The licensee placed the l
341 in-stock flanges in a nonconforming hold status prior to their return
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to Guyon Alloys. The remaining four-inch 150 pound stainless steel blind
flange had been issued and was discarded because it was contaminated.
The licensee concluded that no T-L supplied materials were used in
safety-related applications at Millstone 1 or 2.
The inspector had no further questions.
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3.4 (Closed) 88-25, Section 6.2, TI 2515/98, Containment Temperature Profiles
While conducting TI 2515/98, the inspector noted that drywell temperature
point 17, which is located near 1-IC-1, the normally open isolation con-
denser inlet valve, was recorded at 269 F on June 11, 1988. The inspec-
tor asked about the potential for high temperature-induced damage to the
1-IC-1 Teledyne motor-operator.
Inspector review of drywell temperature data from the summer of 1988
confirmed that the increase was an isolated instance and that point 17
generally indicated about 200 F. The inspector also noted that licensee
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management accepted the completion of surveillance SP 691, "Drywell At-
mosphere Temperature Check," for June 11 without comment; the surveil-
lance acceptance criteria were met in spite of the point 17 increase.
TR-1602-5 recorder traces indicate erratic behavior of point 17 on June
11 and 12, indicating that the temperature reported for June 11 was not
a true measure of area temperature. The inspector also reviewed the most
recent Millstone 1 forced outage work list (issued on February 15,1989)
and noted that repair of point 17 is planned for cold shutdown under work
order 1-88-02123. The inspector had no further concerns.
4.0 Facility Tours and Operational Status Reviews
Control indications were reviewed for proper functioning, correlation between
channels, and conformance with Technical Specifications (TSs). The inspector
verified proper control room manning and discussed alarm conditions with the
operators and found them to be cognizant of plant conditions and indications.
The inspector observed prompt and appropriate operator response to off normal
and changing plant conditions. Shift turnovers were found to be thorough and
in conformance with ACP 6.12, " Shift Relief Procedure." Operating logs and
Plant Incident Reports (PIRs) were reviewed for accuracy and adherence to
station procedures. Posting, control, and the use of personnel monitoring
devices for radiation, contamination, and high radiation areas were inspected
during plant tours. Plant housekeeping controls were observed, including
control of flammable and other hazardous materials. The inspector also veri-
fied proper implementation of selected aspects of the station security program,
including site access controls, personnel searches, compensatory measures,
physical barriers, and guard force response to alarms and degraded conditions.
No inadequacies were identified.
Day and back shift inspections of the control room found all shift personnel
to be alert and attentive to their duties. No unacceptable conditions were
idtatified. The inspectors also addressed the following.
4.1 Safety System Operability
Standby emergency systems were reviewed for operability and readiness
for automatic initiation. The following systems were reviewed: feedwater
coolant injection, automatic pressure relief, low pressure coolant in-
jection, emergency service water, core spray, standby gas treatment, and
standby liquid control. The status of the control rod drive hydraulic
control units, emergency diesel generator, gas turbine, station batteries,
and isolation condenser was also inspected. Inspector review considered
proper positioning of major flow path valves, operable normal and emer-
gency power sources, proper operation of indications and controls, and
proper cooling and lubrication. References included the Updated Final
Safety Analysis Report, system diagrams and operating procedures. No
inadequacies were identified.
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4.2 Plant Incident Reports
Selected plant incident reports (PIRs) were reviewed to (1) determine
the significance of the events, (ii) review the licensee's evaluations,
(iii) assess the licensee's response and corrective actions, and
(iv) verify whether the licensee reported the events as required. The
following PIRs were reviewed: 1-89-1, 1-89-4, 1-89-5 (see Detail 9.0),
1-89-6 and 7 (see Detail 7.0), and 1-89-9. No inadequacies were identi-
fled.
4.3 Engineered Safety Feature Walkdown - Standby Liquid Control (SLC)
On February 13, the inspector walked down the Standby Liquid Control
(SLC) system using the valve lineup (Rev 4 of OPS Form 304-1).after
verifying its accuracy against controlled piping and instrumentation
diagram (P&ID) 25202-26022. All accessible valves were in their proper
position. System tagging was consistent with that of P&ID 25202-26022
and OPS Form 304-1. No inadequacies were identified in the physical
condition of the valves, valve operators, supports, or instrumentation.
The inspector verified the lagging integrity on the heat-traced pump
suction lines and that the SLC pump power supply breakers were positioned
to "0N" at 480 VAC motor control centers (NCCs) F-1 and E-1. Both local
and control room' indications, such as SLC tank level and solution tem-
perature, were as expected for ensuring system standby readiness. No
conditions adverse to system operability were noted.
The inspector identified the following discrepancies to the Operations
Supervisor. These items are unresolved pending.further review for ac-
ceptability (UNR 89-02-01).
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The inspector noted acceptable housekeeping in the SLC area with-
the minor exception of sodium pentaborate crystal buildup in the
interior of both SLC pump casings and on the packing for 1-SL-6,
the normally open outboard combined discharge valve. The buildup
depth was less than one inch and was located on the pump shaft fit-
ting. The buildup did not appear to threaten pump operability.
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The inspector noted that, for system valves 1-SL-27 through 30, the
OPS Form 304-1 architect engineer (AE) numbers did not match those
on P&ID 25202-26022. I
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The inspector also noted that OPS Form 304-1 identifies the normal
position for 1-IA-445 (the sparging air stop valve) as locked open
(LOP); P&ID 25202-26022 identifies the normal valve position as
locked closed (LCL). The inspector observed the valve as locked i
open per OPS Form 304-1; the Operations Supervisor verified that
LOP was the required valve position.
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Figure 10.1, " Blowdown Air Supply Valve," accurately illustrates
the SLC air supply system, but the figure contains no valve numbers.
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5.0 10 CFR 21 Report on Melamine Torque Switches in Limitorque Motor-Operators
Limitorque issued a Part 21 report on November 3,1988 after determining that
certain Melamine torque switches were susceptible to long term post-mold
shrinkage. In this failure mode, the cam becomes bound to the torque switch
shaft and chaft rotation causes the cam to open the contacts at the equivalent
of the first setting position. Thus, if the force required to operate the
valve is greater than is allowed by this setting, the torque switch would
remove motor power before the valve could completely stroke. This could pre-
vent the valve from performing its safety function.
Limitorque examined a torque switch which exhibited cam binding and discovered
that the inside diameter was 0.0004 inches below that allowable. In 1983,
Limitorque changed the SMB-000 toroJe switch from Melamine to Fiberite, which
exhibits a much lower shrinkage rate. For SMB-000 actuators with serial num-
bers lower than 354839 and SMB-00 actuators with serial numbers lower than
233218, Limitorque recommended the replacement of the Melamine torque switches
with environmentally qualified Fiberite.
Millstone I has 33 Limitorque motor-operators installed in safety-related
systems. Of these, six had serial numbers that were either addressed by the
Part 21 report or were undetermined. The licensee inspected these motor
operators for the presence of Melamine torque switches, which are easily
identifiable by their white or gray-colored insulating material. 1-CS-21B,
the normally closed core spray test return to torus valve, was the only ac-
tuator to contain a Melamine torque switch. This valve is normally in its
accident position and is only opened during monthly core spray full flow 1
testing. The inspector agreed that an immediate safety concern did not exist.
SP 621.10, " Core Spray System Operability Test," requires that plant operators
be present at both the motor-operated valve and its associated power supply
breaker to monitor for normal operation. Because the procedure also requires
that the plant operators maintain constant communications with the control
room, there is adequate assurance that, if the 1-CS-218 torque switch failed,
the plant operator in attendance at the valve could manually close it. Addi-
tional monitoring information would be available, as SP 621.10 requires that
clamp-on ammenters be used to monitor AC valve motor current. Even if the
plant operator could not close 1-CS-21B in the event of a reactor building
evacuation due to a simultaneous loss of coolant accident, test line re-
stricting orifice 10-5B would limit the core spray system flow reduction.
The present operating procedures and controls thereby greatly reduce the
potential safety significance of this problem at Millstone 1. Nevertheless,
the licensee conservatively chose to replace the 1-CS-21B torque switch with
a Fiberite one on February 13. The valve was successfully retested and re-
turned to service on February 14.
Seven additional Limitorque operators are stcred in the warehouse awaiting
installation during the April 1989 refueling outage. Their serial numbers
are greater than those specified as suspect by the Part 21 report. The in-
spector had no further questions.
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6.0 Post-Accident Operability of Reactor Building to Torus Vacuum Breaker Butterfly
Valves 1-AC-3A and 3B
While reviewing the instrument air supply to safety-related equipment for'NRC
Generic Letter (GL) 88-14, the Boston Edison Company (BECo) discovered two
design deficiencies at Pilgrim. First, the licensee determined that the air
supply to the secondary containment truck lock inner door seals was not seis-
mically qualified. The railway access door at Millstone 1 has mechanical
seals and this issue therefore does not apply to Millstonc 1. ;
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The second issue does apply to Millstone 1. BECo determined that the air
supply for the reactor building (secondary containment) to torus vacuum
breaker butterfly valve accumulators was not seismically qualified. As such,
the air supply would be lost during an accident and the butterfly valves would
fail open under spring pressure. Primary containment integrity would then
rely on a single vacuum breaker, which does not meet the single failure de-
finitions in 10 CFR 50 Appendix A. Millstone 1 management confirmed that, !
while the Millstone 1 vacuum breaker butterfly valves do not have accumula- l
tors, they would fail open on a loss of air. Inspector review verified that
the Millstone 1 butterfly valves require air pressure to close, and open under
spring pressure on loss of air pressure.
Millstone 1 has two parallel 20" diameter vacuum relief lines. Each contains
a check valve that serves cs the normally closed vacuum breaker (1-AC-2A/B)
and an air-operated butterfly valve that serves as the normally closed block-
ing valve (1-AC-3A/B). The lines join to form a third 20" diameter line that
enters primary containment at penetration X-205. Butterfly valves 1-AC-3A&B
have functions that require opposite valve positions: they open to prevent
excessive vacuum inside primary containment during post-accident conditions;
and they close to provide double containment isolation in combination with
the check valves. Technical Specification 3.7.A.4 (and its bases) define each
check and air-operated butterfly valve combination as a vacuum breaker, and
require that both vacuum breaker systems be operable to assure primary con-
tainment integrity during plant operation.
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FSAR Table 6.2-4 classifies check valves 1-AC-2A/B and butterfly valves AC- .
3A/B as primary containment isolation valves. Categorizing 1-AC-3A&B as con- '
tainment isolation valves (CIVs) is consistent with their inclusion in TS
Table 3.7.1. The licensee stated that these valves were included in TS Table
3.7.1 in response to an NRC concern: the table scope was expanded to include
remote manual valves and check valves that could be opened during power opera-
tion for testing or sampling purposes. The inspectors noted that the basis
l for TS 3.7.1 states that double CIVs are provided on all lines penetrating
Butterfly valves 1-AC-3A/B are Allis Chalmers Model 150 Streamseal valves with
Bettis air operators. The licensee performs local leak rate tests (LLRTs)
for butterfly valves 1-AC-3A&B and check valves 1-AC-2A&B via a test connec-
tion between the valves. Check valves 1-AC-2A&B are thereby tested in their
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isolation position and butterfly valves 1-AC-3A&B are tested in the reverse
direction. Additionally, the 1-AC-2A&B and 1-AC-3A&B valve bodies are seis-
mically qualified.
The inspector presented several questions to the licensee on January 19; the
licensee's written response was received on January 25. The licensee con-
cluded that neither seismic qualification for the 1-AC-3A&B butterfly valves'
air supply nor assurance of redundancy in the isolation function for penetra-
tion X-205 (under assumed accident conditions involving loss of normal AC
power and instrument air) was incorporated in the plant's licensing basis.
Further, the licensee concluded that the valves were operable and that the
plant was in compliance with Techncial Specifications 3.7.A.4 and 3.7.D. The
licensee's position was that no immediate safety concern existed for butterfly
valves 1-AC-3A&B and the potential benefit of maintaining dual containment
isolation would be evaluated under the Integrated Safety Assessment Program
(ISAP) as ISAP topic 1.108. The licensee also concluded that a Justification
for Continued Operation (JCO) was not needed because butterfly valves 1-AC-
3A&B are operable if they can perform their primary safety function of vacuum
relief.
The inspectors questioned the ability to meet Section 6.2.1.1.1 of the Mill-
stone 1 Updated Final Safety Analysis Report (UFSAR), which states that pri-
mary containment can withstand a simultaneous design basis LOCA and earthquake,
loss of offsite power, and a single active failure. Butterfly valves 1-AC-3A
and 3B would fail open due to the earthquake. If check valve 1-AC-2A or 2B
then failed open as a single active failure, primary containment would be
compromised. The licensee position was that they meet the UFSAR because the
failure of check valves 1-AC-2A&B is a passive failure: check valves 1-AC-
2A&B do not change position (i.e., open) during a design basis accident (DBA)
because drywell spray is not utilized and a vacuum therefore does not form
in containment. For beyond design basis events, the current E0Ps allow the
operators to use sprays to depressurize the containment, but limit their use
to pressures between 20 and 35 psig. In addition, the containment spray in-
terlock restricts containment spray operation by closing the spray valves when
containment pressure is below 5 psig.
General Design Criterion (GDC) 56 of 10 CFR 50 Appendix A specifies that isola-
tion valves fail to the position that provides greater safety upon loss of
motive power. The inspectors agreed with the licensee's position that allow-
ing butterfly valves 1-AC-3A&B to fail open to maintain the vacuum relief
function at the cost of the redundant isolation function is consistent with
GDC 56, if drywell sprays will be used to mitigate design basis events, be-
cause spraying could result in subatmospheric containment pressures. In such
scenarios, it is proper for the isolation function to take second priority
because failure of the vacuum relief function could result in gross contain-
ment failure. FSAR Sections 6.2.2.1 and 6.3.2.8 state operator action is
required after 10 minutes following a design basis LOCA to place containment
cooling in operation. That could include use of containment spray. But, the
licensee also stated that, as part of his submittals regarding the environ-
mental qualification of safety-related electrical equipment, the licensing
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basis was changed such that no credit is taken for use of containment spray
to mitigate design basis LOCAs. Such downgrading of the importance of con-
tainment spray raises the question of whether the vacuum relief function
should take second priority to the containment isolation function.
GDC 56 also specifies two isolation valves per line penetrating primary con-
tainment. The licensee position was that the General Design Criteria are not
part of the Millstone 1 licensing basis and are not required to assure an ade-
quate safety margin in this case. The inspector acknowledged that the General
Design Criteria were promulgated after Millstone 1 received its operating
license in October 1970. She also questioned whether Millstone 1 should meet )
the intent of GDC-56 as part of the Systematic Evaluation Program (SEP). The i
intent of the SEP program to evaluate plant design and to assure it meets the
General Design Criteria is stated in the NRC Evaluation Report dated December
9, 1981 for SEP Topic VI-4 on the Containment Isolation System.
In'the UFSAR statement of the containment design basis, the licensee limited
their consideration to failure of active components. In the NRC single fail-
u~e criterion definition provided in the General Design Criteria, active and
passive failures are included. The licensee cited SECY-77-439, " Single Fail-
ure Criterion," dated August 17, 1977 as a reference for his treatment of the
check valves as passive components. SECY-77-439 allows check valves to change
state and still be classified as passive components. The inspector noted that
the 1980 edition of ASME Code Section XI, which is applicable to Millstone
1, defines active valves as those which change state to function and passive
valves as those which do not (Article IWV 2100). If the vacuum relief func-
tion of check valves 1-A-2A&B has occurred during an event, they must then
change state to perform their isolation function. A seismic event also could
necessitate reseating of the check valves.
In summary, the inspectors have questions on the following: the safety / risk
benefit of seismically qualifing the air supply to butterfly valves 1-AC-3A&B;
the need to consider butterfly valves 1-AC-3A&B as containment isolation
valves for normal operation and design basis accidents; the need to meet the
intent of GDC 56 for penetration X-205; consideration of active and passive
failures in the containment design basis; the acceptability of eliminating
containment spray from the licensing basis, and the consequent effect on the
primary safety function of block valves 1-AC-3A&B. This issue remains unre- -
solved pending further licensee and NRC review (UNR 50-245/89-02-02).
In a January 13, 1989 letter, the licensee informed the NRC of their intention
to respond to GL 88-14 Items 1 and 2 by February 18, 1989, which ends the GL's l
l 180 day response period. The licensee stated that his response to GL 88-14
Item 3, which includes the results of verification testing that safety-related
l components will perform as expected in accordance with all design basis events,
l would be deferred until the testing could be completed during the April 1989
refueling outage. The initial licensee response to 6L 88-14 was received
after the end of the period of this report.
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7.0 Environmental Qualification of Reactor Water Cleanuo Isolation Valves
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1-CU-2 and 3
Millstone 1 had been operating under an environmental qualification exemption I
for the Teledyne actuators for the inboard and outboard reactor water cleanup
(RWCU) suction isolation valves (1-CV-2 and 3, respectively) as granted by
the NRC in a June 8, 1987 letter. On January 31, at 1:35 p.m., the licensee
determined that the RWCU isolation function was not assured following a small
break loss of coolant accident (LOCA) in that the motor operators for 1-CV-2
and 3 might be disabled due to the harsh environment induced by the break
,
prior to their receipt of the only RWCU system isolatio, signal which was
low-low reactor vessel water level. The licensee made an ENS (Emergency
Notification System) call per 10 CFR 50.72 (b)(2)(iii) at 2:00 p.m. and
isolated the RWCU system after establishing a continuous reactor water con-
ductivity monitoring method via the recirculation system at 2:50 p.m.
On February 1, the licensee implemented plant design change (PDCR) 1-8-89 to
add the 2 psig high drywell pressure signal to the RWCU isolation function
(i.e. , primary containment group 5, which closed 1-CU-2, 2A, 5 and 28). This
ensures that 1-CU-2 wiil close to maintain RWCU isolation for the full range
of breaks inside containment. To ensure RWCU isolation for breaks outside
containment, the licensee also modified operating procedures to require opera-
tors to manually isolate 1-CV-3 via the control room panel 903 handswitch upon
receipt of the associated high area temperature alarm.
The inspector observed the installation and testing of the RWCU control logic
modification. Two General Electric HFA normally energized control relays and
wiring changes were installed to provide the revised control scheme. A spare
contact from each of the existing high drywell pressure relays was used to
develop the isolation signal for the new RWCU isolation relays. The new
isolation logic incorporates a one-out-of-two-taken-twice scheme to deenergize
the RWCU system isolation relays. The PDCR was approved by the plant opera-
tions review committee (PORC) prior to its implementation.
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The licensee considers the new HFA relays to be seismically qualified per IEEE
Standard 344. PDCR 1-8-89 required the new relays and conduit to be seismic-
ally mounted. The inspector reviewed automated work orders (AW0s) M1-89-945 i
and 964 used in implementing the modification, and identified no inadequacies.
'
The inspector noted an adequate level of quality control (QC) coverage and
proper implementation of the QC verification plan documented on Station Form ;
(SF) 207, which included visual inspections of the relay mounting and terminal ;
connections and verification that the fire barriers breached during installa- '
tion were resealed with fire resistant silicone foam. The inspector also
verified that the required fire watches were present during fire barrier
breaches: the electricians who were installing the modification were fire-
watch qualified. ;
A half-scram occurred at 1:55 a.m. on February 2 during testing verification
of the modification wiring. The inspector observed as the operators imple-
mented their normal alarm response actions, bypassing average power range
_ _ _ _ - _ _ - _ _ _ _ _ _
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l monitor (APRM) Channel 3 in response to its high alarm. The operators ob- i
l served that APRM Channel 3 indicated 100% and had no high local power range !
l monitor (LPRM) high indications; its trip would not reset so the half scram i
would not reset. The licensee later discovered that Production Test personnel I
had slightly moved a wire bundle to relay 590-125A during jumper removal and ;
APRM setdown to 90% had occurred. The APRM setdown was bypassed, the half- l
scram was reset, and APRM Channel 3 was returned to service. The licensee i
determined that relay 590-125A was faulty and repaired it by 8:32 a.m.
The inspector observed as the licensee implemented the modification retest
plan including the as-built verification, continuity checks, and preopera-
tional testing per PORC-approved test procedure T-89-1-2. The inspector noted
the thoroughness of post-installation testing, and noted no inadequacies in
the test procedures, performance, or results. The inspector verified that
the modification met the testing acceptance criteria prior to the RWCU sys-
tem's return to service.
Plant operators received training on the modification through reviewing the
Night Order log book. The inspector verified that the Operations Critical
drawings were modified to reflect the modification.
The RWCU system was filled and vented prior to its return to service by 4:55
a.m. on February 2. Reactor water conductivity had exceeded 1.0 umhc/cm at 1
1:30 a.m., placing Millstone 1 in TS LCO 3.6.C.3.b, but was reduced below 1.0
umho/cm by 6:40 a.m.
The inspector reviewed the PDCR documentation for the design reviews and in-
tegrated safety evaluation ISE/MP1-89-018 and identified no inadequacies.
The inspector agreed with the licensee's determination that an unreviewed '
safety question did not exist. The licensee plans to replace both motor-
operators with environmentally qualified ones during the April 1898 refueling
outage.
Several questions remain unresolved after review of the event:
(1) The licensee stated in their October 15, 1985 exemption request letter
that 1-CV-2 and 3 were exempt because, if a break occurred inside the
containment, the outboard valve would isolate the RWCU system and vice
versa. The licensee's recent actions related to 1-CU-2 and 3 were pre-
dicated on the fact that this arrangement is not single failure proof.
The inspectors questioned whether there are other non-single-failure
proof exemptions in the June 8, 1987 NRC letter.
(2) The licensee's exemption request identified that the RWCU system isolated
on either low-low vessel level or high flow in the RWCU system. The
licensee confirmed that the Millstone 1 RWCU system has never had high
flow as an isolation signal. The NRC:NRR reviewer involved in the ex-
emption request for 1-CU-2 and 3 confirmed that he did consider the
isolation on high flow in his decision to support the exemption for 1-
CU-2 and 3.
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(3) The licensee stated that the errors in the exemption request described
in (1) were noted during licensee reviews for removing the 1-0U-2 and
3 operators from the master EEQ list. The inspectors questioned whether
the licensee's method for exemption request preparation is less rigorous
and thorough than his method for review of the EEQ master list. This
is suggested by the exemption request inaccuracies, as evidenced by the
discussions in (1) and (2) above. The inspector requested the licensee
provide for NRC review a description of the process / criteria used by
engineering personnel to remove items from the EEQ master list.
The inspectors will follow the licensee's resolution of these questions in
a future inspection (UNR 50-245/89-02-03).
8.0 Revision 2 Emergency Operating Procedures
In June 1988, NRC inspection (Report 50-245/88-200) identified weaknesses in
the Millstone 1 Revision 2 Emergency Operating Procedures (EOPs). The in-
spection found the E0Ps to have poor usability, largely due to inadequate
implementation of the Writer's Guide and not using the revised validation and
verification (V&V) procedures to perform a complete review of the E0Ps and
the operating procedures referenced in the E0Ps. The licensee responded to
the inspection findings in letters dated July 29, 1988 and October 28, 1988.
The inspector reviewed the letters and verified implementation of those com-
mitments related to the Revision 2 E0Ps by procedure review or plant walkdown,
as appropriate. The findings are listed below with references to the associ-
ated section of Inspection Report 50-245/88-200.
Findings Related to Usability of the Revision 2 E0Ps
--
(3.3.1) The E0P revisions made effective on October 15, 1988 have been
reviewed using current V&V procedures. Also, Millstone 1 operators
walked down all E0P actions contained in normal operating procedures
(0Ps).
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(3.1.3) At the time of the E0P team inspection, the licensee made interim
changes to the E0Ps by attaching the change to the front of the E0P.
Because the change was only denoted at the applicable E0P step and not
written out there, this increased the difficulty of using the E0Ps. The
inspector verified that the current E0Ps have no outstanding interim
changes. The licensee plans to write all future interim changes into
the Revision 2 E0Ps at the applicable procedure step. The inspector will
verify that the licensee's administrative procedures are revised to re-
flect the new method during routine inspection.
1
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(3.1.4) The inspector verified that an additional copy of the E0Ps for
use by personnel other than the Shift Supervisor (SS) was provided in
the control room.
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[3.3.1(1), 3.3.2(3)] The original E0P steps directing the removal of .
fuses and installation of bypass jumpers were not sufficiently detailed,
i The inspector reviewed the associated procedures and found that detailed
jumper installation directions now exist. The inspector also verified
that the E0P locker located in the main control room contains the neces-
sary tools and jumpers. The jumpers are stored in bags labeled for each
task. In addition, terminals which are more difficult to locate are
labeled at their location.
--
[3.3.1(2),3.3.3] To ensure availability of the above-described jumpers
and other E0P equipment, the licensee has implemented OPS procedure 694.1,
" Staged Equipment Inventory," which requires quarterly verification of
all E0P equipment located throughout the plant.
--
[3.3.1(2)] The inspector verified that the local components associated
with use of OP 303, " Reactor Water Cleanup System," for alternate boron
injection were clearly and accurately labeled and that the outdated
information for heating the sodium pentaborate solution was deleted.
--
[3.3.1(2)] OP 304, " Standby Liquid Control," identifies a method for
alternate boron injection with the RWCU system. The hydrostatic pump,
hoses and connections were not staged at the time of the June 1988 in-
spection. The inspector verified that these components have since been
staged and are included on OPS Form 694.1-1 to ensure their continued
availability.
--
[3.3.1(2)] E0P 578, "RPV Flooding," originally referenced temperature
recorder TR 1602-5 which was incorrect. Table 2 of E0P 578 now lists
each RPV level instrument with its correct recorder reference.
--
[3.3.1(2)] E0P 578 identified the Control Rod Drive (CRD) system as an
alternate method for adding water to the RPV. OP 302, "CRD System," has
been revised to require that the feedwater block valves be closed in
order to maximize CRD flow and prevent backflow to the condenser.
--
[3.3.1(4)] The inspector verified that, with one exception, potentially
confusing references have been adequately modified or deleted. The in-
spector did note that the precaution that preceeds step 3.1.4 in E0P 577,
" Emergency Depressurization," states that defeating isolations may be
required to accomplish the next step, but does not specify that the
primary containment Group 1 isolation signal must be bypassed by the
method given in OP 317, " Main Steam." The inspector discussed this
weakness with the licensee and will follow the licensee's action in a
future inspection. i
--
[3.3.1(5)] This item lists the inadequate or incorrect labeling identi-
fied during the E0P inspection. The inspector verified licensee resolu-
tion of these errors through procedure or labeling changes.
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[3.3.2(1)] The inspector verified the installation of two E0P lockers
near the north and south control rod drive hydraulic control units (HCUs)
on reactor building elevation 14' 6". The lockers contain tools and
safety equipment for venting individual HCUs as directed in E0P 572,
"RPV Power Control." This equipment is also listed in OPS Form 694.1-1
and, as such, its availability will be verified quarterly.
--
[3.3.2(2)] E0P 576, " Level Restoration," listed city /well water as an
alternate injection method, but no city /well water source is available
in the reactor building. This method has been deleted from E0P 576.
--
[3.3.2(2)] Weaknesses were identified in E0P 577, " Emergency RPV Depres-
surization." The inspWitte verified that sufficient jumpers for by-
passing the Maui Steam 'r lation Valve (MSIV) low-low water level trip
are now available in the control room. OP 306, " Reactor Vessel Head
Cooling System," cautioned against exceeding an RPV head to flange dif-
ferential temperature of 145 F. This caution did not apply in emergency
conditions, but it was not procedurally overridden. The caution has been
deleted.
--
(3.3.2) The licensee is replacing all valve locks so that each locked
valve at Millstone 1 can be unlocked with a single key. A copy of this
key is included on all on-shift key rings for the operators and plant
equipment operators.
--
(3.3.3) Local directions for preparation of sodium pentaborate solution
were available during the June 1988 inspection but were uncontrolled.
These directions are now available as Operator Aid 1-88 and are con-
trolled in accordance with OP 261, " Control of Operator Aids," which
requires a monthly audit. They are posted at three separate plant loca-
tions: the RWCU filter precoat tank, the radwaste precoat tank, and in
the sodium pentaborate storage area located in the north crossover on
the third floor of the t eactor building. The E0P team also noted that
a pen and ink change had been made to the reactor building copy of Opera-
tor Aid 1-87, the isolation condenser level meter correction chart. That
change was not made to the control room copy. The inspector verified
the correction of this operator aid.
--
(3.3.4) The licensee replaced the heavy deck plates installed over Emer-
gency Service Water valves 1-LP-19 through 21 with lightweight, hinged
panels with handles to allow easy access.
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[3.4.2(1)] E0P implementation peacekeeping during complicated events was
difficult and operators were not aware of the short verification spaces
provided for peacekeeping. The licensee covered this issue during sub-
sequent licensed operator requalification training. The inspectors ob-
served requalification testing on the Millstone 1 simulator late in 1988
and noted that several shift supervisors effectively used the spaces for
peacekeeping; those that did not were aware of the method, but chose not
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to use it by personal preference. The inspectors verified that the shift
supervisors were able to maintain their place and did not omit any E0P
steps.
--
While reviewing'0P 303, " Reactor Water Cleanup System," the inspector
noted that certain manipulated valves were identified as "A/B". The
inspector could not determine if this meant that the "A" AND "B" valves
were to be operated or if "A" OR "B" was to be operated. The inspector
also observed that "A or B" was used elsewhere in the procedure. This l
has the potential to confuse the operators. The inspector discussed this l
with the licensee and will review resolution in a future inspection. l
Findings Related to the Technical Adequacy of the Revision 2 E0Ps
The E0P inspection team concluded that the Revision 2 E0Ps were technically
accurate with the exception of E0P 580, the containment control procedure. ]
The deficiencies and their resolutions are described below.
--
[3.2.1(1)] No engineering analysis was performed to support the develop-
ment of a Primary Containment Pressure Limit (PCPL) for post-accident
venting of containment. The licensee chose' instead to set the PCPL equal
to the Primary Containment Design Limit (PCDL). Setting these values
equal to each other results in potential operator confusion because the
initiation of reactor pressure vessel (RPV) flooding and drywell and
suppression pool spraying occur at the same pressure. That conflicts
with the E0P strategy which calls for the operator to attempt RPV flood-
ing to stop the primary containment pressure increase prior to spraying
the drywell and suppression pool.
The licensee reevaluated the PCPL utilizing the method described in the
Revision 4 Emergency Procedure Guidelines (EPGs). With this method, the
containment pressure limit is set to maintain the operability of the ;
containment, the safety relief valves (SRVs), the containment vent valves,
and the RPV vent valves. The SRVs are the most limiting component at
Millstone 1. With the containment pneumatic receiver low pressure alarm
setpoint at 97 psig, and a minimum differential pressure for SRV opera-
tion of 35 psid, drywell pressure must be limited to 62 psig to maintain ,
SRV operability. 1
At 62 psig, the PCPL is still about equal to the PCDL. However, the
licensee has revised the sequence of operator actions in E0P 580 to avoid
the potential for operator confusion and provide a hierarchy of actions
per the Revision 2 EPGs. The operator floods the RPV before drywell
pressure reaches the PCPL, initiates torus and drywell sprays (if allowed ,
by their spray initiation curves) when drywell pressure reaches the PCPL, ,
and vents primary containment if drywell pressure exceeds the PCPL. l
--
[3.2.1(2)] No engineering analysis was available to support the use of
primary containment pressure instrumentation to determine primary con-
tainment water level. The plant specific technical guidelines (PSTG)
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use 22.2' as a maximum containment water level because that is the
highest available suppression pool water level indication. In contrast,
the EPGs call for setting the maximum primary containment water level
limit based on the elevation of the highest primary containment vent or
on the water level that imposes a hydrostatic pressure equal to the con-
tainment design pressure, whichever is lower.
The licensee extended the suppression pool water level scale to 27.2',
but limited the maximum level to 24' to maintain operability of the sup-
pression chamber vacuum breakers. While 24' is below the point where
the core would be submerged, RPV flooding is not precluded because E0P
580 allows injection from sources internal to the containment. Because
the low pressure emergency core cooling systems take suction on the sup-
pression pool, they are still available to reflood the RPV.
Millstone 1 has concluded that it is not feasible to use the present
drywell instrumentation to determine drywell water level during flooding,
but plans to install drywell water level indication during the April 1989
refueling outage.
--
[3.2.3(1)] The Pressure Suppression Pressure Limit (PSPL) was calculated
using the suppression chamber pressure instrument, while the E0Ps speci-
fied the use of the drywell pressure instrument as the monitored para-
meter. Because the instruments have separate instrument taps, the PSPL
was incorrect and would have resulted in drywell spray initiation at a
higher pressure than required.
The PSPL curve has been replaced with its single most limiting value of
35 psig. This is consistent with the Revision 2 EPGs.
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[3.2.3(2)] The Primary Containment Design Pressure Limit was calculated
assuming the use of suppression chamber pressure instrument PR 1602-4A,
whose sensing tap is 22.2' above the bottom of the suppression chamber.
E0P 580 directed the operator to use suppression chenber pressure in-
strument PR 1631-C, whose sensing tap is located 2.2' above the bottom
of the suppression chamber. The PCDP Limit of Figure 6 and the PCP Limit
of Figure 7 were then incorrect since the limits were not corrected for
water levels above 2.2'. As a result, the associated E0P steps initiated
RPV flooding, suppression pool spraying, drywell spraying and primary
containment venting at containment pressures below that actually required.
As discussed in the first technical finding listed above, the licensee
has replaced the Primary Containment Design Limit with the revised
Primary Containment Pressure Limit. Because the PCPL uses drywell pres-
sure, the concern with the difference in suppression chamber pressure
tap locations is eliminated.
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[3.2.3(3)] Calculation C17 determines the minimum number of SRVs required
to be opened to ensure that the RPV would depressurize. The inspection
team.found that, while the EPG calculational guideline identified three
SRVs for emergency depressurization, the licensee changed this value to
four with an an' notation of " Loss of Feedwater - small break." Further
licensee action was necessary to document justification of this deviation.
The Millstone 1 small break LOCA analysis determined that the minimum
number of SRVs required for depressurization is four. The licensee has
- modified the calculation record to reflect this change.
The technical procedure revisions described above were completed using the
current Writer's Guide and V&V procedures. The licensee reevaluated the i
calculations applicable to the PSPL, the PCPL, and the minimum SRV number,
and updated the E0P calculation files. The operators received training on
the revised E0Ps and E0P equipment by reviewing the Operations Night Order
log and attending on-shift and requalification training.
Licensee actions on the Revision 4 E0Ps, which include Writer's Guide revi-
sions, V&V of the entire body of E0P procedures, and revisions per the Control
Room Design Review (CRDR) will be inspected as they are completed.
9.0 Maintenance
The inspector observed and reviewed selected aspects of the following safety- i
related maintenance, including procedural adherence, obtaining required ad- l
ministrative approvals and tagouts prior to work initiation, proper quality '
assurance and personnel protection measures, and verification of proper system
restoration and retest prior to its return to service. No inadequacies were i
identified. j
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"B" Condensate Booster Pump Outboard Seal Replacement '
The "B" condensate booster pump was removed from service at 5:00 a.m. on
January 16 for replacement of the leaking outboard seal. The inspector veri- !
fied that the licensee entered a seven day Technical Specification action '
statement per TS 3.5.C.3 for feedwater coolant injection system (FWCI) system 1
inoperability. FWCI provides high pressure makeup to the vessel in the event !
of a small break loss of coolant accident by utilizing either the "A" or "B"
feedwater string. While TS 3.5.C.3 is satisfied with only one operable FWCI
subsystem, and the "A" system components were available, the "A" FWCI string
had been administrative 1y declared inoperable in response to a licensee- l
conducted safety system functional inspection (SSFI). The SSFI team found
that SP 628.1, " Integrated Simulated Automatic Actuation of FWCI," was con-
ducted on only one FWCI string per outage. Since no documentation could be l
located on the performance of SP 628.1 for the "A" FWCI string during the 1987 '
outage, Millstone 1 tagged out the "A" string and selected the "B" string for
automatic FWCI initiation.
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l The inspector observed that the associated AWO M1-89-0064 had been reapproved
l as required for a work scope change when an unsatisfactory shaft sleeve was
I discovered. On January 17 at 9:00 p.m., the licensee reduced power to 90%
for restart of the "B" booster pump. After a satisfactory restart, the "B" '
FWCI string was reselected and TS LC0 3.5.C.3 was exited at 9:12 p.m. The j
unit was returned to full power by 9:30 p.m.
I
Gas Turbine Generator EGR Failures I
On January 29 at 5:15 p.m., the licensee discovered an EGR (Electric Governor
Remote) oil pump motor failure after receiving the associated control room
alarm. The EGR supplies the hydraulic pressure required to operate the speed
governor for the Gas Turbine Generator (GTG), one of the two on-site emergency
AC power sources. The GTG was declared inoperable and a four day TS LC0 was i
entered per TS 3.5.F.3. After completing the EGR pump motor replacement on i
January 30 and prior to system retest, the licensee discovered oil leaking l
from the GTG EGR pump motor due to a failed seal, which was replaced. The -
licensee noted that the original seal was cracked, but that could have oc- ,
curred during seal removal. Subsequent licensee investigation could not con- t
clusively determine the cause of the seal failure. The seal could have been
old, as evidenced by the mechanic's observation that it was less supple than
the replacement seal or the motor could have been misaligned during installa-
tion. The inspector noted the inherent difficulty in aligning the EGR pump
motor because of the interference of several horizontal steel mounting plates
that surround the coupling between the EGR pump and motor.
On January 30, the GTG was retested with a start time of 42.7 seconds, meeting
the 48-second start time required by TS 4.9.A.2.a. The licensee declared the
GTG operable and exited TS LCO 3.5.F.3. On January 31, the GTG started in
47.3 seconds during a second test. Licensee review of the recorder traces
routinely taken during GTG testing noted an abnormality in the GTG fuel supply
trace. Historically, when the fuel supply traces have this characteristic
discrepancy, the licensee has replaced the EGR pump. TS LC0 3.5. F.3 was re-
entered and the EGR pump was replaced. The GTG was retested with a start time
of 41.5 seconds on January 31, ending TS LC0 3.5.F.3. Subsequent GTG tests ;
on February 1, 2, and 9, posted start times of 41.7, 41.5, and 41.4 seconds, !
respectively. The inspector had no further questions.
The present EGR governor system will be replaced during the April 1989 re-
fueling outage with an electronic system which should eliminate the current
system problems.
10.0 Surveillance
The inspector observed and reviewed selected aspects of the following sur-
veillances for conduct in accordance with current approved procedures, for
test result compliance with administrative requirements and technical speci-
fications, and for deficiency correction in accordance with administrative
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requirements. The inspector noted that the surveillance teams displayed
thorough coordination and adherence to procedures. No inadequacies were
identified.
1
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SP 408P, " Scram Air Header Low Pressure Functional Test" on January 17.
--
RWCU Isolation Logic Modification Testing on February 4 (See Detail 7.0).
--
Shutdown Cooling System Hydrostatic Test on February 8.
11.0 Licensee Event Reports
The following Licensee Event Reports (LERs) were reviewed to assess LER ac-
curacy, the adequacy of corrective actions, compliance with reporting require-
ments and to determine if there were generic implications or if further in-
formation was required. No inadequacies were noted.
LER 88-09-00: "ATWS Division 1 Initiation"
This LER described a November 14, 1987 event which was reviewed by the in-
spector at that time (see NRC Inspection Report 50-245/88-21). .The LER was
accurate in describing the inadvertent ATWS (anticipated transient without
a scram) Initiation during a transfer of ATWS power supplies.
The inspector reviewed the licensee's corrective actions which included re-
vision of operations procedure OP 344A, "125 VDC Electrical System," and the i
addition of caution tags on the ATWS power supply breakers for main DC bus
101A, bus 1018, and control room switchboard DC-11A-1. Change 2 to Revision
19 of OP 344A dated December 12, 1988 cautioned the operator to clear sub-
channel trips per procedure IC 409A prior to swapping power supplies. The
corrective actions were completed as described in the LER and were appropriate
to prevent recurrence. No inadequacies were identified.
LER 88-13-01: " Inadequate Seismic Anchorage of Bus 14D"
The purpose of this LER supplement was to identify the LER title which was
omitted in the initial LER submittal. The inspector had no further comment;
inspector review of LER 88-13 is documented in Inspection Report 50-245/88-21. i
12.0 Plant Operations Review Committee i
The inspector attended several Plant Operations Review Committee (PORC) meet-
ings and verified that Technical Specification 6.5.1 requirements for commit-
tee quorum were met. The meeting agenda included reviews of plant incident
reports, plant design modifications, procedure revisions, and new procedures.
The inspector noted that the committee discharged their functions in accord-
ance with TS 6.5.1 and that frank discussion and probing questions were en-
couraged. No inadequacies were identified.
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13.0 Management Meetings
Periodic meetings were held with station management to discuss inspection
findings during the inspection period. A summary of findings was also dis-
cussed at the cu elasion of the inspection. No proprietary information was
covered within the scope of the inspection. With the exception of the Part
21 report discussed in Section 5.0, the inspectors provided no written mate-
rial to the licensee.
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