ML20246K093
| ML20246K093 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 04/26/1989 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20246K073 | List: |
| References | |
| 50-336-89-05, 50-336-89-5, NUDOCS 8905170239 | |
| Download: ML20246K093 (32) | |
See also: IR 05000336/1989005
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U.S. NUCLEAR REGULATORY COMMISSION
. REGION I
Report No. 50-336/89-05
Docket No. 50-336
License No. DPR-65
Licensee: . Northeast Nuclear Energy Company
P.O. Box 270
Hartford, CT 06101-0270
Facility Name: Millstone Nuclear Power Station, Unit 2
Inspection At: Waterford, Connecticut
Dates: February 11 through March'23, 1989
Reporting
Inspector: P. J. Habighorst, Resident Inspector, Millstone 2
Inspectors: P. J. Habighorst, Resident Inspector, Millstone 2
L. Kolonauski, Resident Inspector,. Millstone 1
W. Oliveira, Reactor Engineer, DRS
W. J. Raymond, Millstone Senior Resident Inspector
T. Rebelowski, Senior Reactor Engineer, DRS
E. Yachimiak, Operations En ineer, DRS
Approved by: b l 2
E. C. McCabe, Chief, Reactor Projects Section 1B Date
Inspection Summary: 2/11/89 - 3/23/89 (Report 50-336/89-05) .
Areas Inspected: Routine NRC resident inspection (277 total hours, including
18 backshift and 6 deep backshift hours) of plant operations, outage activi-
ties, surveillance, maintenance, previously identified items, Plant Incident
Reports (PIRs), allegations, plant design change records (PDCRs), committee
activities, and Licensee Event Reports (LERs).
Results: A violation was identified for removing incore detectors without
establishing containment integrity and Senior Reactor Operator (SRO) coverage.
Otherwise, no unacceptable corditions were identified. One previously iden-
tified item was closed, three licensee-identified items were noted with no
violations issued, and six unresolved items were identified.
~
8905170239 890504
gDR^
ADOCK 05000336
PNU
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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 Previously Identi fi ed Items (92702) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
3.1 (Closed) IFI 50-336/86-04-01: Measurement Control Evaluation -
Nonradiological Chemistry..................................... 1
3.2 (Closed) Maintenance Personnel Training Upgrade................. 2
4.0 Fa c i l i ty To u r s ( 717 0 7 ) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
5.0 Plant Operational Status Reviews (71707/73753)....................... 3
5.1 Review of Plant Incident Reports (PIRs)......................... 3
5.2 Failure of Group 1 Control Element Assemblies (CEAs) to Insert
in Manual Group Mode.......................................... 3
5.3 Reactor Protection System (RPS) Channel "D" High Power Trip. .. . . 4
5.4 Low Pressure (LP) Turbine Rotor Cracki ng. . . . . . . . . . . . . . . . . . . . . . . . 5
5.5 Control Room Ventilation System 0peration....................... 6
5.6 Gamma-Metrics Wide Range Nuclear Instrumentation..... .......... 7
6.0 Control of Outage Activities (60710/37700/71707) . . . . . . . . . . . . . . . . . . . . . 8
7.0 Review of Proficiency Watchstanding Implementation (41701)........... 10
8.0 Observations of Physical Security (81700)............................ 10
8.1 89-004, Safeguards Event Report............. ................... 10
9.0 Plant Design Change Record and Evaluation Programs (37700/37828)..... 12
9.1 PDCR and Evaluation Procedures........................ ......... 12
9.2 PDCR Review and Observations.................................... 13
9.3 PDCREs Reviewed and Observations.......................... ..... 14
9.4 Station Bypass Jumper Contro1................................... 15
9.5 Quality Assurance Interface with PDCR and Evaluation Programs... 15
9.6. Conclusions..................................................... 16
10.0 Defective Steam Generator (SG) Tube Plug (71707/37700). . . . . . . . . . . . . 16
11.0 Incore Instrument Removal Allegation (RI-88-A-0040)
(60710,92701)..................................................... 18
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12.0 Committee Activities (71707)......................................... 25 j
13.0 Licensee Event Report (LER) Review (92700) . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
13.1 LER 89-001-00 "Fi re Barrier Penetration Seal s Inoperable". . . . . . . 25 {
14.0.0bservation of Maintenance (62703)................................... 27
15.0 Observation of Surveillance Testing (61726).......................... 28 {i
16. 0 Pe ri od i c Repo rt s ( 92700) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
17.0 Management Meetings (30703).......................................... 29
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DETAILS
"U 1.0 Persons Contacted i
Inspection findings were discussed periodically with the below listed
supervisors and managers.
S. Scace, Millstone Station Superintendent
,
- J. Keenan, Unit 2 Superintendent
J. Riley, Unit 2 Maintenance Supervisor
F. Dacimo, Unit 2 Engineering Supervisor
D. Kross, Unit 2 Instrument and Controls Supervisor
(= J. Smith, Unit 2 Operations Supervisor
.The inspector.also contacted other members of the Operations, Radiation
Protection, Chemistry, Instrument and Control, Maintenance, Reactor Engi-
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neering, and Security Departments.
2.0 Summary of Facility Activities
Millstone 2 was.in refueling and cold shutdown throughout the inspection
period. The licensee completed refueling operations, service water pipe
replacement, Steam Generator (SG) Eddy Current Testir.g (ECT), and emer-
gency diesel generator overhaul. On March 16, the licensee presented the
results of SG ECT to the NRC staff. On going outage work includes repair
of the low pressure (LP) turbine rotor cracking (Detail 5.4) and of the
defective SG tube plugs (Detail 10.0).
3.0 Previously Identified Items (92702)
3.1 (Closed) IFI 50-336/86-04-01: Measurement Control Evaluation - Non-
radiological Chemistry
The following results were achieved on analyses of water samples by
the licensee and Brookhaven National Laboratory.
Millstone Units 1 and 2 Split Samples
BNL Millstone
Buron (ppm) SBLC-YA 25,400 25,560 +- 112
Ammonia (ppb)
Steam Generator 3A 117 +- 0 110 +- 10
Steam Generator 3B 118 +- 0
Chloride (ppb)
Steam Generator 1A 11.2 19.3 +- 1.72
Steam Generator 1B 10.0
These analytical comparisons are acceptable.
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3.2 (0 pen) Maintenance Personnel Training Upgrade
At the licensee's request, the inspector met with the Nuclear Train-
.ing Department concerning the present inspection and to clarify NRC
Inspection 50-336/88-28, Detail.7.7. Previous review.of. Individual
Qualification Matrices (IQMs) led the inspector to conclude that the
number.of personnel completing training courses and On-the-Job Train-
ing was minimal. Subsequently, the licensee showed that a signifi-
cant amount of training had in fact been conducted. Cost containment
actions had reduced clerical support and resulted in delays in docu-
mentation. Nonetheless, the inspector concluded that the program is
sound and that quality training is being conducted.
Previously, it was also noted that a few individuals did not obtain
acceptable grades in classroom examinations. These individuals had
participated in an initial presentation of administrative indoctrina-
tion training aimed at a target audience of combined mechanical,
electrical, instrumentation and control, and production personnel. 1
The' material met the needs of all personnel in attendance but, due to l
the way the material was presented, some individuals were held re-' f
sponsible for material that exceeded their job requirements. Based
on the feedback process defined in the Nuclear Training Manual, NTM-
2.05, " Training Program Effectiveness," it was dedM to rewrite the
course changing the focus to a job applications base and to re-struc-
ture the material presentation sequence prior to subsequenu presen-
tations. The individuals _ who failed are being required to attend the
rewritten course in its entirety.
4.0 Facility Tours (71707)
The inspector observed plant operations during regular and backshift tours
of the following areas:
Control Room Containment
Vital Switchgear Room Diesel Generator Room
Turbine Buf1 ding Intake Structure
Enclosure Building
Control room instruments were observed for correlation between channels,
proper functioning, and conformance with Technical Specifications. Alarms
in effect were discussed with operators. The inspector periodically re-
viewed the night order log, tagout log, Plant Incident Report (PIR) log,
key log, and bypass jumper log. Each of the respective logs was discussed
with the operations department staff. No inadequacies were noted.
During plant tours, logs and records were reviewed to ensure compliance
with station procedures, to determine if entries were correctly made, and
to verify correct communication and equipment status. No inadequacies
were noted.
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r .The inspector verifiel proper contro! room manning and found the operators
to be cognizant of plant conditions and indications. Also, the inspector
observed prompt and appropriate operator response to changes in plant' con-
ditions. Shift turnovers were found to be thorough and in conformance
with ACP 6.12, " Shift Relief Procedure." Operating logs and Plant Inci-
dent 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. No inadequacies were
identified.
The inspectors conducted backshift inspections of the control room and
found all shift personnel to be alert and attentive to their duties. No
unacceptable conditions were identified.
5.0 Plant Operational Status Reviews (71707/73753)
5.1 Review of Plant Incident Reports (PIRs)
The following plant incident reports (PIRs) were reviewed to (1) de-
termine the significance of the events, (ii) review the licensee's
evaluation of the events, (iii) verify the licensee's response and
corrective actions were proper,' and (iv) verify that the licensee
reported the events as required. The PIRs reviewed were: 89-03,
89-08 and 89-11 thru 89-22. The following PIRs warranted inspector
follow-up:
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PIR 89-08 " Failure of Group 1 CEA's to Insert in Manual Group
Mode" (Detail 5.2)
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PIR 89-03 " Reactor Protection System (RPS) Channel 'D' High
Power Trip" (Detail 5.3)
5.2 Failure of Group 1 Control Element Assemblies (CEAs) to Insert in
Manual Group Mode
On February 4,1989 at approximately 6:00 a.m. , the licensee was
commencing a reactor shutdown for the scheduled refueling outage.
During insertion of the control element assemblies (CEAs) in the
manual sequential mode, Groups 1 and 2 failed to insert upon demand.
The licensee further identified that Groups 1 and 2 would not insert
in the manual group mode, and that Group 1 CEAs would insert in the
manual individual mode.
Licensee procedure OP 2206, " Reactor Shutdown," requires the regu-
t lating CEA groups (groups 1-7) to be inserted in the manual sequen-
l tial mode if the process computer is available, or in manual group
l mode in accordance with CEA sequence steps in procedure OP 2202A.
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i The licensee initiated an authorized work order (AWO) M2-89-01485 to
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troubleshoot the CEA logic circuit. The inspector observed the
, troubleshooting. Maintenance did not identify the cause. At ap-
l proximately 10:04 a.m., the licensee manually tripped the remaining
CEA groups (Shutdown Groups A & B, Regulating Groups 1 & 2). All
CEAs inserted into the core.
Further licensee investigation determined the cause was failure of
two +15VDC power supplies for the Group 1 CEAs. Failure of the power
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supplies resulted in the logic going to a failed state'for the Group
1 CEA programmer. That made the CEA group control mode inoperable.
The +15VDC power supplies were replaced and retested per AWO M2-89- ;
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01662 on February 6. '
The licensee's action to prevent recurrence, based on the Plant
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Operations Review Committee (PORC) meeting 2-89-46 close-out of PIR
89-08, is to add the CEA logic power supplies to the Instrument and
Control (I&C) preventive maintenance replacement program. The pro-
gram's replacement frequency had not been determined by the licensee
at the end of the inspection period. The licensee's corrective ac- .
tions should identify the cause of both power supplies failing and !
ensure against recurrence.
5.3 Reactor Protection System (RPS) Channel "D" High Power Trip
On January 21 at approximately 3:45 p.m., the licensee documented an
RPS Channel "D' High Power trip (PIR 89-03). The unit was at full
power at the time. Initial licensee actions were to bypass Channel
'D,' enter TS action statement 3.3.1.1, and initiate a trouble report
to determine the cause of the high power trip signed. The TS action
statement requires three out of four high power trips to be operable
(Table 3.3-1). The licensee reported the Channel 'D' high power trip
was caused by erratic trip setpoint fluctuations.
Licensee troubleshooting per AWO M2-89-00790 on January 21 determined
the cause of the erratic setpoint to be a failed 5 VDC detector power
supply.
The licensee refurbished the 5 VDC detector power supply on January
23 by replacing, one-for-one, two electrolytic capacitors, two tran-
sistors, and an integrated circuit (IC) regulator with commercial
parts. The inspector reviewed the associated standard form (SF) 499,
" Commercial Commodity Evaluation / Dedication Form." The licensee's
evaluation considered: applicable code certification (ASME, IEEE,
ANSI, etc.), environmental and seismic qualification, and whether the
item required documentation or special purchase requirements. No
inadequacies were noted. The parts were replaced per AWO M2-89-00790
and soldered per licensee procedure I/C 24378.
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The inspector reviewed the satisfactory retest and functional test of 1
the RPS channel 'D' high power trip per procedures SP 2401L, I/C i
2417F, SP 2401K and SP 2401F. No inadequacies were noted. !
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The licensee's long-term corrective actions include preparation of a l
Plant Design Change Evaluation (PDCE) for alternate power supplies, ;
and replacement of the four RPS channel +5VDC detector power supplies
prior to power operation after the current refueling outage. ]
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5.4 Low Pressure (LP) Turbine Rotor Cracking
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On March 3, the licensee informed the inspector about routine ultra- i
sonic examinations (Wheelosonic) on the "B" LP turbine. The exami-
nations indicated defects on the 10th stage rotor dovetail lands in
the notch bucket region. The dovetail lands connect the rotor and
the blades of the turbine. The notch bucket region is the location
on the turbine rotor where blades are installed and removed.
The licensee, based on recommendations from the turoine vendor
(General Electric), removed the notch bucket blades for both the
generator and turbine end 10th stage. Magnetic particle examinations
(Magna glo) revealed several indications on the dovetail lands for
both stages.
The licensee expanded the inspection scope to 100% magnetic particle
examination on the generator and turbine 10th rotor stages for the
"B" LP turbine, exploratory evacuation of the indications to deter-
mine depth, and glass bead blasting and shot peening the dovetail
regions to alleviate residual stresses.
The licensee reported the following crack and depth profiles on the
turbine generator end 10th stage to the vendor on March 14.
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LP "B" 10th stage turbine end: 25 indications; total circumfer-
ential length on all three dovetail lands - 74.75 inches; depth
ranging from 0.010 inch to 0.340 inch.
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LP "B" 10th stage generator end: 14 indications; total circum-
ferential length on all three dovetail lands - 34 inches; and
depth ranging from 0.05 inch to 0.40 inch.
Based on the indications on the 10th stage of the "B" LP turbine, the
licensee expanded the examinations to include the 9th and lith stages
and 10th stage on the "A" LP turbine. At the end of the inspection
period, the licensee was evaluating the results of the expanded
examination.
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On March 16, the licensee presented information on the LP turbine
dovetail cracking to the. NRC/NRR staff. The rotor dovetail. land
cracks could cause turbine failure if a bucket dislodged from-the
rotor dovetail'section.
The vendor's recommended corrective modification is a titanium ' dove-
tail block installed in the notch region and 180 degrees away. At
the end of the. inspection, the vendor was-manufacturing the titanium 1
blocks and the licensee was-reinstalling the turbine buckets. 1
5.5 Control Room Ventilation System Operation
On February 27, at 10:26 p.m. , the licensee entered TS action state-
ment 3;7.6.1.a for the Facility I control room emergency ventilation
system. The Facility I' control room emergency ventilation system was
inoperable due'to maintenance on its emergency power source ("A"
emergency diesel generator). .The action statement requires restora-
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tion of the inoperable system within seven days or operation of the
remaining system in the recirculation mode. Control room (CR) ven-
tilation is designed to limit exposure to operators to 5 rem or less
whole body exposure in the event of an accident' .
At 12:25 a.m. on February 28, the licensee logged out 'of TS action
statement.3.7.6.1.a. The-justification was TS 3.05, which states
that, when a system is declared inoperable solely because its emer-
gency power supply source or its normal power source is inoperable,.
it may be considered operable if the normal or emerger:cy power source q
is operable and all redundant systems are operable.
TS 3.05 is not applicable in Mode 5 (Cold S/D) and 6 (refueling).
The plant was in Mode 6 (refueling) on February 28. The control room
operators did not take into account the mode applicability for TS 3.05. This was a violation of TS 3.7.6.1.a, in that the licensee did
not have the operable control room ventilation system (Facility II)
in the recirculation mode for approximately 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> during inoper-
ability of facility I control room ventilation system. The violation
was licensee-identified. The licensee re-entered TS 3.7.6.1.a at
4:31 p.m. on February 28.
The inspector reviewed the safety significance of the non-compliance
with TS 3.7.6.1.a. The facility II control room emergency ventila-
tion system was able to respond, with emergency power available, to
the Auxiliary Exhaust Actuation Signal (AEAS) and the Enclosure
Building Filtration Actuation Signal (EBFAS). TS 3.7.6.1.b requires
suspension of all core alterations or positive reactivity changes
when both facilities of CR emergency ventilation systems are inoper- >
able. Based on control room log entries and discussions with the
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operations department, no core alterations took place in the 16-hour
period of interest. Therefore, the plant conditions met the TS ac-
tion statement for both CR ventilation systems being inoperable. The
licensee plans to submit a change to TS 3.7.6.1.b for operational
Modes 5 and 6. Because'this item was licensee-identified,- of minor
safety significance, appropriately reported and corrected, and not a ' i
matter which should have been prevented by action on a previous vio-
lation, no Notice of Violation was issued (NV-89-05-02).
5.6 Gamma-Metrics Wide Range Nuclear Instrumentation
In routine inspection report 50-336/88-13, the licensee notified the
inspector that solder connections on Gamma-Metrics (G-M) cable as-
semblies may be susceptible to moisture intrusion during a design
basis accident (DBA). ' A G-M -10 CFR 21 report to the NRC on February
19, 1988 identified environmental qualification test failures. These
were attributed to a G-M cable assembly metal hose solder joint that
failed to hold pressure at elevated temperatures. The licensee was
notified of this problem by letter from G-M on February 22, 1988.
G-M also provided, in a letter to the licensee on.May 10, 1988,
guidance for inspection of neutron flux monitor cabling and evalu-
ation of a retrofit to provide additional sealing of the metal hose
at specific connections to prevent moisture intrusion. The vendor
reported the item as a safety issue since the G-M neutron. flux moni-
tor and cabling assemblies are used to provide the operator with neu-
tron flux indication from the source range to 150% power in post-
accident monitoring environments in accordance with Regulatory Guide
1.97.
On May 27, 1988, the licensee completed an environmental qualifica-
tion (EQ) evaluation of G-M Wide Range Nuclear Instrumentation.
According to a May 10, 1988 letter from the vendor to the licensee,
moisture intrusion was detected in submergence testing at 60 psig.
The problem, as determined by the vendor, is in-containment cable
assembly solder joint voids that allow moisture'to migrate to various
cable connectors. Failure results in arcing between the conductors,
which carry 800 volts. The arcing causes electrical noise which is
seen as an increase in neutron flux. The licensee noted that G-M had
changed their shop fabrication procedure for pre-tinning the solder '
joints in question. prior to 1984, a solder pot dip process was
used, and was tested in the original qualification testing. The
latest qualification testing was done on cable assemblies fabricated 1
using an iron-applied tinning. G-M further noted that they have
compared finished solder joints fabricated using both methods, and
have observed voids similar to the failed cable assemblies only in
those samples using iron-applied tinning.
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On February 14, 1989, the licensee implemented vendor (G-M) procedure
060001, " Test Procedure, Field Service System Pressure Test for Neu-
tron Flux Monitoring System." The test acceptance criteria for three
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pressure drop tests (system, detector and detector cable, and in-
containment cable) is to maintain a nitrogen pressure of 60 psig +/-
0.5 psig such that the pressure drop for each test does not exceed 1
psig in 10 minutes.
The inspector reviewed the results of the vendor service test. 'All
four wide-range channeh failed the pressure drop test. The system
pressure drop ranged from 0.825 psig/ min (Channel C) to 7 psig/ min
(Channel A). .The licensee generated four non-conformance reports
(NCRs) for each wide-range channel based on unsuccessful test re-
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suits. At the close of.the inspection report, the licensee was pre-
paring a justification for continued operation (JCO) prior to re-
start from the refueling outage. The inspector will review the JC0
prior to re-start, the licensee's deportability evaluation, and the
new G-M configuration qualification report. This is an unresolved
item pending assessment of the affect upon wide-range nuclear in-
strument operability (UG 89-05-02).
6.0 Control of Outage Activities-(60710/30700)
6.1 Entry into Technical Specification Action Statements
During a review of plant status on March 1, the inspector noted that
plant operators had voluntarily entered a number of Technical Speci-
fication action statements as of 7:33 a.m., when actions were taken
to remove the Facility II service water system from service along
with the "B" EDG (emergency diesel generator). This action was part
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of the planned restoration from a service water (SW) system outage
after replacement of system piping. The "B" EDG was inoperable due
to a lack of cooling water. The Facility II outage was planned to
last for about 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> while workers removed a blank flange pre-
viously installed to separate the service water headers, and to re-
.. install a spool piece to restore the normal piping configuration.
Normal SW lineup was restored by 4:00 p.m. on 3/1.
As a result of the Facility II outage, the following Technical Speci-
fication action statements were in effect.
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TS 3.8.1.2.b, " Electrical Power Sources - Shutdown."
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TS 3.8.2.2, " Electrical Power Systems."
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TS 3.9.8.1, " Shutdown Cooling Loop Operation."
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TS 3.1.2.1, "Boration Sy:tems - Shutdown."
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TS 3.1.2.3, " Charging Pump - Shutdown."
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TS 3.7.6.1, " Control Room Emergency Ventilation System."
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TS 3.1.2.5, " Boric Acid Pumps - Shutdown." i
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Power for onsite 4KV normal-and emergency busses was provided from
the Normal Station Service Transformer (NSST). Unit power from the
. Reserve Station Service Transformer (RSST) was not immediately avail-
l able due to an RSST outage for preventive maintenance. Since the "A"
EDG was still inoperable for planned preventive maintenance, there
was no backup onsite emergency power supply available for Unit 2
other than the Millstone 1 cross-tie. Inspector review of plant
status confirmed the licensee was meeting the requirements of the
l applicable TS action statements. -While the TS permit this plant con-
figuration, the inspector questioned the management planning that
resulted in no backup emergency diesel generator supply. This matter
was discussed with the Unit 2 Superintendent on March 1 and 2.
The manageinent decision was made based on a 3:30 p.m. February 28
schedule which showed that work on Facility I, including the "A" EDG,
was not going to be completed until March 8, or 8 days later than
completion of the service water pipe replacement work. Thus, as of
February 28, the option of waiting 1 day for the "A" EDG to be me-
chanically operable before restoring the service water headers to
their normal configuration was not apparent. Further, even though
redundancy in the SW system already existed, it was deemed prudent to
increase redundancy further (and thereby enhance safety) by making
all service water components available for operation as soon as poss-
ible. This action would further support optimizing equipment avail-
ability to meet requirements for redundant shutdown cooling systems
when the reactor head was installed on March 2. The decision was
made to proceed after concluding the evolution could be done safely.
Additional safety assurance was provided by restricting activities
that could generate a radiological source term (i.e. core altera-
tions, reactivity changes, etc.), and assuring the availability of
the backup 4KV power supply from Unit 1 by using the Bus 24G cross-
tie.
After consideration of the above, the inspector concluded that licen-
see management discretion was exercised with regard for plant safety
in this case.
6.2 Refueling Controls
The inspector witnessed refueling activities at the spent fuel pool,
control roon, and the reactor cavity. Licensee reactor engineers in
the control room were maintaining 1/M plots. For transfer of fuel
assemblies, there were communications between the s, pent fuel pool and
reactor cavity and senior reactor operator. overview. Containment
integrity was established during core alterations. No inadequacies
were noted.
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7.0 Review of Proficiency Watchstanding Implementation (41701)
Operations Department control of watchstanding proficiency was reviewed to
verify that there wis a mechanism in place to ensure licensed shift per-
sonnel were maintained in an " active" status in accordance with 10 CFR
Part 55.53(e). Di,cussions with the Operations Supervisor primarily
focused around the guidance contained in a March 25, 1988 memo, MP-2-0186.
This memo provided all Shift Supervisors (SSs) with information and guide-
lines for controlling licensed operator watchstanding proficiency. Dis-
cussions with available SSs revealed that all licensed operators are
tracked to ensure the minimum time-on-shift requirement is being met.
Formal record keeping is not required. One SS did keep a personal log of
his crew's watchstanding times. Other SSs formulated their shift crew .
"
members' schedules in 'a manner which ensures the minimum time requirements
are met prior to the end of each calendar quarter. At the end of each ,
calendar quarter, the Operations Supervisor issues a memo listing the i
" active" and " inactive" status of all license holders. No inadequacies '
were noted in the licensee's control of proficiency watchstanding.
8.0 Observation of. Physical Security (81700)
Selected aspects of site security were reviewed, including site access
controls, personnel searches, personnel monitoring, placement of physical
barriers, compensatory measures, guard force staffing, and response to !
alarms and degraded conditions. The following item warranted inspector
followup.
8.1 89-004, Safeguards Event Report
On Feoruary 14, 1989, the licensee's security department identified
an access pathway between the protected area and two vital areas.
The pathway, established during service water pipe replacement, was a
small opening to a service water header. The' licensee notified the
NRC at 12:10 a.m. on February 15 per 10 CFR 73.71(c), Appendix G.
The inspector reviewed applicable requirements, security effective-
ness implications, the licensee's investigation results, and correc-
tive actions for the identified event.
Applicable requirements are in the Physical Security Plan, Revision
5, Section 5.3.1, " Units 1 and 2 Vital Area Barriers", and Technical
Specification 6.8.1, " Procedures". The security plan requires vital
area openings which exceed certain dimensions and are less than a
certain height above base level to be appropriately secured. If a
reduction in effectiveness of a vital area barrier occurs, compen-
satory measures are to be taken per Section 5.3.3 of the security
plan. According to the licensee's investigation, uncompensated vital
area barrier openings from the protected area existed for approxi-
mately 4.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.
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TS 6.8.1 requires the licensee to implement applicable procedures !
recommended in Appendix "A" of Regulatory Guide 1.33, February 1978.
Procedures for component replacement and modifications are included l
in Regulatory Guide 1.33. Licensee procedure ACP-QA 3.10, Prepara- '
tion, Review and Dispositioning of Plant Design Change Records
(PDCRs) requires an evaluation of the security impact of the PDCR.
The inspector reviewed PDCR 2-30-88, Service Water Modifications.
PDCR 2-30-88 did require security support, but the specific openings l
requiring compensatory measures were not identified.
The distance from the opening in the protected area to one of the
Unit 2 vital areas was several hundred feet, and over one hundred
feet to the other vital area. The access path was the service water
pipe. The licensee's chemistry department concluded that a potential
hazardous environment might exist inside that service water pipe due
to decaying organic matter.
The inspector reviewed the security vulnerability created by the
breach between protected and vital areas for potential exploitabil-
ity. The total time lapse between protected and vital area opening
and licensee compensatory measures was approximately four and one-
half hours. The licensee reported that the accesses into the pro-
tected and vital areas were continually occupied by contractor per-
sonnel, with licensee supervision touring the work areas periodic-
ally. The protected area opening was covered with plywood. The in-
spector toured the affected area and determined the opening was not
in a normally travelled pathway. The breach in one vital area was a
ten foot vertical drop to structural members.
The inspector questioned the licensee on the plant effects of a loss
of the cooling water systems in this area. The licensee concluded
that the consequences would be minimal. The inspector reviewed the
licensee procedure which addresses maintaining shutdown (Mode 6)
plant conditions with a loss of cooling water. That procedure allows
removal of cooling water for up to eight hours. - -
Inspector review of associated procedures and the information pro-
vided by the licensee concluded t'at exploitability of the security
breach was minimal.
The inspector reviewed an assessment of the event by the licensee's
Human Performance Evaluation System (HPES) organization. The HPES
evaluation determined the root cause of the event was failure of the
engineering review to identify the potential for breach of a vital
area boundary. The inspector concurred with that determination.
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The licensee's corrective actions included: completion of the service
water modification and restoration of the original security configu-
ration; revision of ACP-QA-3.10 to improve security evaluations of
plant modification process by May 16, 1989; and an interim memoran-
dum, dated March 15, to all Millstone units requiring review of open
PDCRs for adequacy of security evaluations. Inspector review noted
no inadequacies.
In this case, the violation (NV 89-05-04) was identified by the lic-
ensee, the event was appropriately reported ti the NRC (SER 89-004),
the condition was corrected, including actions tc prevent recurrence,
and the violation was not found to be reasonably preventable by cor-
rective action on a previous violation. Enforcement action awaits
completion of NRC review of the security significance of the
violation.
9.0 Plant Design Change Record and Evaluation Programs (37700/37828)
The Plant Design Change Record (PDCR) Program and the PDCR Evaluation
(PDCRE) Program was reviewed for conformance with the Technical Specifi-
cations (TS) and licensee commitments. These included: Regulatory Guide
(RG) 1.33, Revision 2, Quality Assurance Program Program Requirements; and
RG 1.64, Revision 2, Quality Assurance Requirements for the Design of
Nuclear Power Plants. The inspector also reviewed four PDCRs, three
PDCREs; ACP-QA-3.10, Revision 2, Preparation, Review, and Disposition of
Plant Design Change Records; and ACP-QA-3.26, Revision 3, PDCR Evaluation.
In addition, the inspector observed field work on three of the four PDCRs
and one of the three PDCREs. Discussions were conducted with engineering,
craft, operations, and Quality Control (QC) inspection personnel and super-
visors. The personnel were found qualified and knowledgeable.
9.1 PDCR and Evaluation Procedures
The PDCR procedure deals with the processing of major design changes.
PDCREs are for defining, controlling, and specifying review of minor
changes and directing replacement of components or parts in a manner
that ensures: conformity with design intent; operability; and plant
and personnel safety. Processing a design change is much the same
for a PDCR and PDCRE. Administrative Impact questions are not for-
mally documented for PDCREs. Administrative Impact questions in-
clude: the update of procedures, drawings, parts lists, Final Safety
Analysis Report (FSAR), and the In-service Inspection (ISI) program.
Also, PDCREs not requiring a safety evaluation may be implemented
prior to PDRC/SORC review.
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9.2 PDCR Review and Observations
Each of the PDCRs reviewed was prepared to ACP-QA-3.10 and approved
by the Plant Operations Review Committee (PORC)._ The PDCR packages
included: . design details, safety evaluations, unreviewed safety ques-
tion determinations, unreviewed environmental impact assessments,
automated work orders (AW0s),'and tests. ,
PDCR 2-011-88, Secondary Side SRV Position Indication. The inspector
observed the relocation of 4 of 16 flow sensors 'on the vertical rise
of the 18 inch vent line. The relocation was made at the request of '
the Instrument and Control (I&C) group to reduce ALARA time during
repair,. troubleshooting, surveillance and tests.
PDCR 2-014-88, Containment Sump Discharge Pipe Strainer. This change
installed a strainer to prevent entrapment of debris in the seat area-
of containment isolation valves 2-SSP-16.1 and 2-SPP-16.2. The in-
spector verified that Control Room Drawing 25203-26024 was " red-
lined" to document the PDCR changes until the drawing is revised. He
~
also verified that Operations Procedure OP-2336A, Revision 10, "Sta--
tion Pump and Drains," was revised and PORC approved.
PDCR 2-025-88, Millstone 2 Transfer Canal Tube Quick Opening Flange.
This PDCR was developed to reduce the time to install / remove the
Transfer' Canal flange in the high radiation area in the refuel pool.
Flange manufacturers had proposed complex modifications to quickly
open, remove, and reinstall the flange. Licensee engineers designed
a simpler means of quick opening the flange and tested it on a full
size model. The model has been given to the Training Center for
future training.
PDCR 2-037-88, Containment Equipment Hatch-External Bolting Attach-
ments. . This PDCR was implemented to satisfy Generic Letter (GL) 88-17, Loss of Decay Heat Removal. The original hatch was designed
to close from inside the containment. In case of loss of decay heat
removal capability, closure must be accomplished within two hours.
An external means of closing the hatch was needed to avoid sending
personnel into a hazardous environment to satisfy GL 88-17 and Pri-
mary Containment Integrity Technical Specification (TS) 3.6.1.1. The
modification and the addition of quick disconnects for utilities that
run through the equipment hatch comply with GL 88-17 and the Tech-
nical Specifications. The inspector conducted an onsite verification
of the hatch modification and the equipment hardware, and reviewed
the following documentation:
--
Changes to the FSAR and Abnormal Operating Procedure (AOP) 2572,
Revision 1, Loss of Shutdown Cooling. ,
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The new maintenance procedure MP 2704S1, Containment Equipment
Hatch Emergency Closing. MP 2704S1 includes a requirement for
training and qualifying teams for hatch closure.
PDCR 2-27-87, MP-2 Anticipated Transient Without Scram (ATWS), was
implemented to satisfy 10 CFR 50.62. The design change installed
equipment to automatically initiate the auxiliary feedwater system
and initiate a turbine trip under conditions indicative of an ATWS.
The requirement was addressed through the installation of a Diverse
Scram System (DSS) and ATWS Mitigating System Actuating Circuitry
(AMSAC).
The DSS is activiated at 2400 psi by output from four reactor pres-
sure sensors combined in a two-out-of-four logic matrix. Signals ,
from the excore power range nuclear instrumentation are used to de- '
tect a failure of the reactor protection svstem (RPS) and to initiate
redundant Auxiliary Feedwater (AFW) by AMSAC 10 seconds after a fail-
ure to scram. The design change involved installation of signal con-
ditioning electronics, keylock bypass switches, two timing relays,
two auxiliary relays (94A/ DSS and 94B/ DSS), and interconnecting wir- j
ing.
NRC inspection included review of the PDCR 2-27-87 detailed design
and safety evaluation, and review of implementing automated work
orders M2-88-10617 (Installation of Cable and Conduit), M2-88-11222
(Installation of Electrical Devices and Wiring in Electrical Panels),
and M2-87-01786 (Final Termination and Retest). Inspector review
found installation of electrical devices per the PDCR and post-
installation testing which assured that the circuit wiring was cor-
rect, that the circuits were free of shorts and grounds, and that the
Agastat relay timer setpoints were proper. No inadequacies were
identified.
An integrated preoperational test of the DSS and AMSAC was scheduled
for completion after the end of this inspection period.
9.3 PDCREs Reviewed and Observations
The inspector noted compliance with procedure ACP-QA-3.26 for each
PDCRE reviewed. These PDCREs included completion of standard form
(SF) 359, PDCR Evaluation, to determine whether the a PDCRE should be
upgraded to a PDCR. The following PDCREs were reviewed.
PDCRE MP2-88-045, Annunciator Voltage Balance Relay Operation This
change provides an annunciator to alert the operators in the Control l
Room of a transformer trouble condition upon operation of the main I
generator / transformer voltage balance relay 60/2U.
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PDCRE MP2-88-085, RCS Sample Line PMW (Primary Makeup Water) removal,
was initiated by PIR 87-67. Contaminated resin was reported to have
leaked through check valve 2-S-36 and contaminated the lower PMW sys-
tem. The inspector. verified that removal of the sample line was per-
formed in accordance with Engineering Request Form (ERF) 8/88.
PDCRE MP2-89-028, Replacement of CPC 5 volt Logic Card Power Sup-
plies. The failed cards will be replaced by Category 1 (safety re-
lated) equipment. An evaluation of the PDCRE by the plant engineer
indicated.that a safety evaluation was required. The inspector re-
viewed the plant engineer's submittal of the PDCRE and safety evalu-
ation to PORC. No inadequacies were identified.
9.4 Station Bypass Jumper Control
Procedure ACP-QA-2.068, Revision 8, Station Bypass Jumper Control
governs- the control of temporary modifications such as jumpers,
lifted leads, and bypasses. To determine whether the procedure was
satisfactorily implemented, the inspector reviewed the Bypass Jumper
Log in the Control Room with emphasis on the PDCRs and PDCREs dis-
cussed in the preceding paragraphs. Operations personnel record log
entries, maintain the log current, and verify all close-outs. Engi- i
neering reviews the log semi-annually and provides management with !
the status of bypass jumpers installed for over six months. Engi-
neering provided the inspector with an update of their October 17, l
1988 status report. No inadequacies were noted in the implementation
of procedure ACP-QA-2.06.
9.5 QA Interface with PDCR and Evaluation Programs
Surveillance Report (SR) SS-101 dated December 4, 1987 identified
problems with Revision 2 of procedure ACP-QA-3.26 for the PDCRE pro-
g ram. The SR was upgraded to a Corrective Action Request (CAR) on
November 18, 1988, and the procedure was revised and effective on
January 1,1989. Quality Assurance (QA) agreed that an audit should
be scheduled to evaluate the effectiveness of the recently revised
procedure.
Quality Control coverage was evident in inspections and reviews of
the documentation in the PDCR and PDCRE packages. Documentation in-
cluded automated work orders (AW0s), Inspection Plans, Weld History
and Non-destructive Testing records, Material Receipt Inspection and
Issue / Return Reports, and follow-up on Non-conformance Report (NCR)
289-506 for defective bolting for PDCR 2-025-88. The inspector also
reviewed the QC personnel qualification records and found them to be
current. No inadequacies were identified.
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9.6 Conclusions
No unacceptable conditions were identified. The procedures for the l
PDCR, PDCRE, and the Station Bypass Jumpers programs are being imple-
mented satisfactorily by qualified personnel. PDCRE Procedure ACP- ;
QA-3.26 was revised in January 1989 and needs to be surveilled and
audited to ensure that the procedure is effective.
10.0 Defective Steam Generator (SG) Tube Plug (71707/93702)
The licensee informed the inspector on March 21 of a significant defi-
ciency identified during the March 20 testing of one of four tube plugs
installed in the #2 SG. The licensee reviewed steam generator plugs in
response to the February 25 steam generator tube leak at the North Anna
facility. Representatives from the licensee's corporate engineering or-
ganization visited North Anna to observe the tube plug stress corrosion
cracking identified there. As part of the evaluation of the Westinghouse
mechanical tube plugs defects and the potential impact on Millstone 2
steam generators, the licensee selected 4 plugs installed during the
1985-1988 time period for removal and examination.
Based on information from the plug vendor, Westinghouse, the licensee de-
termined that plugs manufactured in the 1984 time period from Heats 3962,
3279 and 3513 were susceptible to intergranular stress corrosion cracking.
The first time suspect plugs could have been used at Millstone 2 was in
1985. Using Westinghouse information on suspect heat numbers, the licen-
see eliminated the 63 plugs installed during 1985 as not suspect. There
WPre a total of 842 susceptible plugs in Millstone 2, 446 in the hot leg
siae of the steam generators and 396 in the cold leg water boxes, with the
following distribution for the hot legs:
Total Hot Leg Tubes with Suspect Plugs
Year SG-1 SG-2 Total
1986 8 18 26
1987 53 18 71
1988 186 163 349
247 199 446
The vendor recommended that only the plugs in the hot legs be addressed,
since plugs subject to the lower cold leg temperatures (550F versus about
600F for the hot legs) were less susceptible to stress corrosion cracking.
The licensee selected three plugs installed in 1986 and one installed in
1988 for examination. The four plugs selected were also chosen on the
basis of evidence of leakage (dripping or staining on the tube sheet)
noted during visual inspections inside the hot leg water box (reference:
licensee Plant Incident Report 89-27).
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The first three plugs examined showed no evidence of stress corrosion
cracking, although the first one' removed did break and had .to be drilled
out. The fourth plug (in location 78-74) also broke and had to be drilled
out; during drilling and prior to the bit reaching the plug cap, the cap
, fell off. Licensee examination concluded the plug failed in place during
.
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removal due to a nearly 100% through wall, circumferential stress corro-
sion type crack in the plug wall just below the second land. The licensee
concluded the defect was of the same type identified at North Anna. The
7/8 inch Inconel 600 plug was from heat number 2513; the defective plug
that failed at North Anna was from heat number 3962. (There are no known
failures of plugs from the other suspect heat, 3279.) The cracked plug
did not come from a location that had evidence of leakage. The licensee
concluded that the leakage indications resulted from slight ovality in the
steam generator tubes, are self limiting, and do not indicate degraded
plugs.
The defective plug was sent to Westinghouse for follow-up evaluation which
included visual examination and chemical etching. Preliminary results
from the vendor confirmed that the crack was an existing flaw based on the
oxide film and discoloration around the break area.
The licensee plans to modify suspect plugs in the Millstone 2 SGs prior to
startup from the present refueling outage by installing a seal plug to
form a secondary leakage barrier. Licensee review to establish the full
scope of the repair effort and engineering evaluations of the repair op-
tions is in progress. Preliminary licensee estimates are that plug re-
pair will take about 4 weeks.
The licensee reported this item per 10 CFR 50.72(b)(2)(1) at 10:30 a.m. on
3/20 as a defect discovered while shutdown that, if the unit had been
operating, would have resulted in a degraded barrier that could have rig-
nificantly compromised safety.
The licensee reported that 8 man-Rem were expended to obtain the four
plugs discussed above. The preliminary estimate for repairing 446 plugs
was about 170 man-Rem. Licensee reviews are in progress to revise in-
sta11ation methods to reduce the proScted exposures. The licensee's
plans and reviews to keep exposures for the repeir as low as reasonably.
achievable will be reviewed subsequently.
Inspector follow-up of this issue will consider: the vendor's bases for
limiting the suspect tube plugs to heats 3513, 3279 and 3962; the 11cen-
see's bases for selecting the scope of plugs to be addressed and, in par-
ticular, for deferring action on the cold leg plugs; the bases for use of
the Arrhenius method to predict crack propagation rates; review of the
engir.eering design and installation procedure for the plug chosen as the
repair; and the bases for' excluding plugs installed in 1985.
This item is unresolved pending completion of licensee evaluations and
corrective actions, and subsequent review by the NRC (UNR 89-05-06).
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11.0 Incore Instrument Removal Allegation (RI-88-A-0040)
On February 23, an I&C technician informed the resident inspector of con-
cerns identified during' participation in a work party to remove incore
instruments (ICIs) from the reactor on February 22. The ICI job chron-
ology is listed below. The alleger had four separate concerns; each is
, addressed after the chronology.
2/21/89, 10:30 p.m. ICI removal starts with the first crew.
2/22/89, 3:00 a.m. The electric hoist fails; ICI removal continues
without the hoist but with the main crane and the load
cell in place.
2/22/89, 4:00 a.m. The second ICI crew reports and ICI removal continues.
2/22/89, 5:00 a.m. The job is interrupted when the Safety Department
identifies a concern associated with the'I&C worif.rs
climbing down to the Upper Guide Structure (UGS)
platform.
2/22/89, 10:00 a.m. A safety meeting is conducted with.I&C, Safety, He'alth
,
Physics, and Millstone 2 management.
2/22/89, 1:00 p.m. ICI removal resumes following a full crew briefirg and
with a new electric hoist and with a portable Area
Radiation Monitor (ARM) installed on the refueling
bridge by HP personnel. There is no licensed senior
reactor operator coverage.
(1) The alleger stated that, when he started the ICI removal job at ap-
proximately 4:00 a.m. on Wednesday, February 22, an SRO was present.
He stated that, to his recollection, an SR0 had always been present
during past ICI removal jobs. When the job was restarted after 1:00
p.m. on February 22, the alleger noted that an SRO was not present.
The alleger further questioned whether primary containment integrity
was required to be maintained during ICI removal, and. stated that the
personnel airlock was open during ICI removal on the afternoon of
February 22.
Inspect,r review found that the licensee had provided SRO coverage
durinj i ae initial phase of the ICI job, but decided to remove it
after '.Pe 10:00 a.m. safety meeting. Licensee management concluded
that ICI removal was not a " core alteration" and that the initial SR0
coverage was a conservative measure. The licensee stated during fol-
low-up interviewc with the inspector that a similar position was
taken in the past, as recently as the 1988 refueling outage. The
licensee deemed this action to be fully consistent with the intent of
the Technical Specifications (TS), after determination that movement
of ICI detectors themselves created an insignificant' reactivity
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change and the ICI removal process could not create the potential for
>
inadvertent removal of fuel or control assemblies. The bases for the
licensee's determinations were provided in writing at the inspector's
request and were summarized in a February 25 memorandum from the Unit
2 Reactor Engineer to the Unit 2 superintendent. The inspector's
-technical review of the licensee's evaluation identified no safety
- .. inadequacies.
The inspector reviewed shift operating logs and determined that con-
tainment integrity requirements were relaxed sometime on February 22
and were not met for the remainder of the ICI removal. Containment
integrity was relaxed to the extent that the personnel hatch was left
in the access mode with both inner and outer doors open (to facili- '4
tate personnel movement and to lessen duty cycles on the door oper-
ating mechanism). Shift logs show that integrity was established at
8:37 a.m.' on February 21 for installation of the upper guide struc-
ture in the reactor. There is no entry in the shift log for when
containment integrity was relaxed, but it was established again at
6:30 a.m. on February 25. Licensee management stated that the de-
cision to relax containment integrity followed from the decision that
the ICI removal activity was not a core alteration.
NRC regulations'in 10 CFR 50.54(m) require a licensed senior reactor
operator (SRO)< to be present during refueling activities. Millstone
Two TS 6.2.2.e requires that an SR0 with no concurrent' duties be
present during core alterations to supervise the activity. Li kewi se,
TS 3.9.4 specifies requirements for containment integrity during core
alterations. TS 1.12 defines core alteration as "...the movement or
manipulation of any component within the reactor pressure. vessel with
the reactor head removed and fuel in the vessel". TS bases state
that the SR0 and containment integrity requirements protect against
the adverse consequences of an accident source term being generated
during movement of fuel or control assemblies.
h The TS definition of " core alteration" results in imposing contain-
ment integrity and SRO coverage for a wide range of activities. That
is appropriate for activities which can cause significant reactivity
changes or fuel damage (e.g., movement of control rods or fuel). But
the definition also encompasses activities such as installation of
reactor vessel lighting and ICI removal; these activities cannot
cause significant reactivity changes or radiation releases.
L Licensee enluation of ICI removal concluded that the activity was
adequately controlled by an approved procedure, that there would be
negligible impact on core reactivity, that the ICIs could not in-
advertently affect control assemblies due to design of the UGS and
the ICI plate / thimble tube, and that the refueling boron concentra-
tion assured that the core would remain subcritical even without the
control rods inserted.
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Inspector review concluded that ICI removal posed much less risk than
activities which could cause significant changes to core reactivity
or core damage. However, ICI removal is a radiation hazard if the
ICI tips became unshielded; the activity requires experienced per-
sonnel, and appropriate procedures and supervision.
Other than the failure to recognize ICI removal as a core alteration,
no inadequacies were identified in the licensee technical evaluations !
and safety conclusions for this specific instance. After review of
this matter with NRC management, the inspector informed the Unit 2
Superintendent in a meeting on February 24 that the Technical Speci-
fication should be implemented literally until the definition could
be revised by the amendment process. The inspector noted the ICI
removal activities had already been completed by February 24. The
licensee acknowledged the inspector's comments, stated that this ap-
proach would be taken for subsequent in-vessel work that meets the
literal TS definition of a core alteration, and expressed the intent
to request a Technical Specification change.
NRC review concluded that ICI removal meets the TS definition of a
core alteration. The associated failure to provide SR0 coverage and
maintain containment integrity in accordance with Technical Speci-
fications 6.2.2.e and 3.9.4 is unresolved pending resolution of the
TS change planned by the: licensee (UNR 50-336/89-05-07),
(2) The alleger said that no pre-job briefing was conducted. The inspec-
tors reviewed the job and questioned the HP and I&C departments and
learned that the HP department conducted pre-job briefings and that
an off going I&C technician conducted on-station turnovers and con-
firmed that each individual understood his responsibilities after
turnover. The alleger confirmed that these briefings did in fact
occur, but he was concerned that a pre-job group briefing was not
conducted by the I&C department. The inspector confirmed that a pre-
job group briefing was conducted by the I&C supervisor during the
evening of February 21 for the first ICI removal crew. Th alleger
said that the members of the second crew would have benefs.ted from a
group briefing and indicated that the contractor personnel were un-
familiar with the job and the radiation hazards involved. He also
stated that the NNECo personnel were uncomfortable with the contrac-
tor personnel, pointing to a specific example where a NNECo load
director would not take direction from a contractor and the alleger
himself was repositioned to communicate with the load director.
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The inspector spoke with the members from the first and second crews ;
and concluded that a pre-job brief at 4:00 a.m. on February 22 would
not have substantially improved the job. Although not required by
the ICI removal procedure, the first crew was given a briefing on the
procedures and individual duties prior to the start of the evolution.
That same supervisor concluded that an on-station turnover was suf-
ficient to assure the 4:00 a.m. relief crew was adequately familiar
.
with the task and their individual responsibilities. The inspector
1
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t _ __ - _ _ _ __--___ __ _ ___ _ _ _ _ o
__-_ _ _ _______- - _ _ _ - _ - _ - _ _ _ _ _ - _ _ _ - _ - _ _ _ _ _ _ - _ _ _- _ _ - _ _ .-_-
I*' * +-
21
noted further that there was an additional full crew briefing con-
ducted during the 10:00 a.m. meeting on February 22 for all I&C per-
sonnel that coulo subsequently be affiliated with the job.
The alleger also stated that the lack of a pre-job briefing caused
two or three crew members to give directions to the crane operator.
When interviewed by the inspector, the load director stated that only
he could talk to the crane operator by using headset communications,
due to the distances involved. Further, the load director stated he
was not affected by the " speakers" as he stood next to the load cell
spotter, watched the load cell himself and would have directed the
crane operator to stop the upward motion if the 250 pound load limit
was approached. The load director also stated that he did not want
to use a contractor as a load cell spotter because that would be in-
conflict with (undocumented) routine maintenance practices on the
control of loads. The load director stated that he had confidence
in the capability of contractor personnel to adequately perform the-
work.
'While all second crew workers contacted appeared somewhat uncomfort-
able with the la::k of supervision present, there were no adverse con-
sequences. -The inspector concluded that the presence of I&C-supervi-
sion during ICI removal would have been beneficial to coordination
'
among crew members. However, while no pre-job group briefing was
conducted for the second crew, the inspector concluded that pre-job
briefing would not have substantially improved the conduct of ICI
removal in this case, and was not required.
(3) The alleger stated that he encountered the first line I&C supervisor )
'
for the first shift of ICI removal prior to shift turnover. The
supervisor stated that the electric winch had failed and that he
chose to delete the winch and perform the pulls with the main hoist
alone. The alleger questioned this practice and the supervisor
stated that he considered it an equivalent if not better method.
The alleger brought up two concerns on this issue:
--
The electric hoist allows the person who is observing the load
cell to stop the lift if load reaches the 250 pound limit speci-
fied in the procedure, IC 2419A. The person watching the load
cell has to notify the load director, who notifies the crane
operator. The alleger feels that lifting with the main hoist
alone is less safe because communication is more difficult and
indirect.
--
The alleger stated that, because the electric winch was not
used, the procedure was violated and an interim p ocedure change
had not been prepared.
_ - _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - _ _ _ - - _ - _ _ _ _ - _ _ _ _ -
_ - _ - _ _ _ _ - - - _ - - - - - - - - - - --
[b i
V . , . ,.
22
The job began by using both the electric hoist and the polar crane
! auxiliary hoist as specified by procedure step 5.2.17. When the
electric hoist failed, the I&C job supervisor decided to continue
with the ICI pulls with the main hoist alone until an alternate hoist
could be obtained. The procedure requires that the electric hoist be
used to pull the ICI as far as the hoist chain will allow while ob-
serving the spring scale and guide tube. Step 5.2.18 allows use of
the auxiliary crane hoist .to continue to pull the ICI clear of the
guide tube. The procedure does not specify the electric hoist chain
length. In the past, the licensee has used electric hoists with
either 20 feet or 40 feet of chain length; a 40 foot hoist was used
during the first part of the job on February 22. The polar crane
hoist would be used depending on which electric hoist was available
and the individual ICI length. The longest ICI must~be pu'11ed at
least 30 feet to clear the guide tube. A total of two to six ICIs
were removed without the electric hoist between 3:00 and 5:00 a.m. on
February 22.
The inspector reviewed the configuration without the electric hoist
and concluded that it is a safe way to conduct ICI pulls. While the
pathway to stopping a pull is less direct, it is acceptable because
the load cell observer stands next to the load director, who uses a
head set to maintain constant communication with the crane operator.
The safety of the method is further supported by the fact that the
crane speed used, S1, is slower than the electric winch speed. In
addition, IC 2419A specifically allows ICI pulls with the crane when
the electric winch runs out of chain length. The inspector concluded
that any additional time delay in stopping an ICI pull had a negli-
gible effect.
After discussions with several crew members, the inspector concluded
that they had differing views on the best way to conduct ICI removal
(that is, with or without the winch). The alleger also stated that
modifications to the ICI removal equipment (such as the installation
of a remote load cell readout for the crane operator and mechanical
interlocks to prevent pulling the rhodium detectors out of the water)
would improve the safety of the job. The inspector concluded that
the current method is acceptable and that the job was conducted
safely on February 22,
As for changing the ICI removal method without making an interim
change to the procedure, licensee management and the I&C first line
supervisor stated that, because the method was equivalent if not
better than the original method and the intent of the procedure was
met, it was within the authority of the supervisor to continue with
the revised method without changing the procedure. The licensee in-
formed the inspector of a previously established licensee position on
the authority of supervisors and test directors to proceed with jobs
if certain procedure steps do not apply because system conditions are
off-normal. The supervisors may then determine that the intended
- _ _ _ - - _ _ _ _ _ _ _ _ _ - _ _ _ _ - _ - _ _ - _ - _ _ _ _ - _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - . _ _ _ _ _
_
_ - _ _ _ _ _ - _ _ - . _ _ _. _ _ _ . _ _ _
l . >
.,e,,
23
1
system condition is satisfactory and that no procedure change is
necessary prior to continuing with subsequent steps. This position
was developed in proposed Revision 44 to ACP 3.02. The SORC (Station
Operations Review Committee) approved the proposed changes in SORC
Meeting 88-43 on December 20, 1988 and made them effective for im-
plementation on March 10, 1989. Within the above framework, ACP Rev
44 Section G.6.2 establishes limited criteria which, if met, allow
certain procedure deviations that do not require a procedure change.
!
Review of ACP 3.02, " Station Procedures and Forms," and discussions
with the licensee addressed how the administrative procedure provides
criteria for use by plant personnel on compliance with written pro-
cedures. As a station administrative procedure, ACP 3.02 applies to
all three Millstone units and establishes procedures as the primary
job aid for performing work at Millstone. The provisions in ACP 3.02
include: use of temporary or substitute instrumentation; definition
of when a support system is considered available; guidance on how to
resolve conflicts in approved procedures; conditions under which de-
viations from system valve lineups and checklists are allowable; per-
forming steps concurrently; not completing a procedure; when to make
formal changes (i.e. either pre-approved by PORC or SRO approval with i
follow-up PORC review); and actions allowed in the event of emergency
'
conditions.
The following excerpts from ACP 3.02 delineate management's expec-
tations on procedure adherence. Procedures support maintenance, j
modification, surveillance and operation by providing detailed in-
formation to the user that should contribute to job efficiency, per-
sonnel safety, error minimization and radiation exposure reduction.
Procedural detail must be sufficient for a knowledgeable user to per- ,
form the evolution correctly. A successful task is the sum of moti- i
vated and qualified personnel in addition to the tools at their dis-
posal. Training and experience directly contribute to qualifications
while procedures complement the tools. The expectation on the use of
procedures is for workers to review the procedure prior to start of
work; review all steps, notes and cautions prior to start of work,
and if not understood, obtain clarification from a qualified indi-
vidual; follow the procedures explicitly in the order written unless
the procedure allows exception or the provisions defined in ACP 3,02
section 6.6.2 apply; and correct any procedural deficiencies upon
identification, including stoppage of work activities to formally
change the procedures if necessary. The need to formally change the
procedure is defined to exist when the procedure will not work as
written and the suggested changes will be permanent.
Upon review of proposed Revision 44 to ACP 3.02, the inspectors iden-
tified several open issues which include: the need to clarify the
criteria, the adequacy of the criteria in view of TS 6.8.1, speci-
fication of the minimum level of qualification or supervision needed
to implement such procedure changes, and the need to document the
i
_ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - _ _ _ _ _ _ _ - _ _ _
- - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ - - _
7
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24
bases for such changes. The inspector presented these concerns
during a March 9 meeting with the Station Superintendent. The lic-
ensee deferred Revision 44 implementation pending further review and
clarification of the intended changes.
In summary, NRC inspection of the alleger's two concerns related to
implementr. tion of IC 2419A concluded: (1) actions to pull ICIs with-
out an ciectric winch were a deviation from the method prescribed by
IC CGA, but met the intent of the procedure and constituted a safe,
acceptable method of removing ICIs; and (ii) the job supervisors
acted in accordance with management expectations as contained in
existing and/or pending administration procedures. Adequacy of and
licensee actions to clarify and revise ACP 3.02 will be reviewed on a
subsequent routine inspection (UNR 89-05-08).
(4) The alleger stated the #2 Safety Injection Tank (SIT) area radiation
monitor (ARM 7891) was out of service for calibration, He noted that
the HP (health physics) department was not aware of its unavailability
and indicated that there was a lack of coordination between depart-
ments. The alleger said that he questioned the absence of an ARM and
that a portable ARM was Sstalled after he raised the concern to an
HP technician during the 5:00 a.m. to 1:00 p.m. break.
The inspector investigated the HP coverage for the job and concluded
that the protection afforded by the alarming dositecs (digital alarm-
ing dosimeters) affixed to each worker and an HP technician's use of
a teletector was adequate to ensure personnel safety. The ARM would
only have provided more defense in depth. The inspector spoke with
the HP technician who confirmed that the alleger informed him of the
absent ARM, and stated that the decision to place a portable ARM had
been reached at a prior HP planning meeting and that HP was late in
placing the ARM on the refueling bridge.
The alleger also stated that he thought that the ARM was supposed to
undergo a setpoint change for refueling conditions and that he sus-
pected that this had not been done. The inspector reviewed the set-
point change issue with the Operations and I&C departments, who
stated that the ARM does not undergo a setpoint change for refueling
operations.
The inspector questioned the licensee's delay in calibrating the #2
SIT ARM, which was removed from service on February 28. The inspec- l
tor noted that it is the closest normally-available ARM. The I&C
technician responsible for calibration of the ARM stated that there
were numerous detector wiring problems that delayed its return to
service until March 1, 1989. The licensee stated that ARM unavail-
ability will be added to the outage critique list and they are consi-
dering the purchase of a replacement ARM which would be calibrated
- . _ . _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ - _ _ _ _ . _ _ _ -_ _ _ -
_ _ _ _ - _ _ - -_ - - _ - _ - - - - - - - - - _ _ - _ - . _ --- _ _ _ _ - - - _ _ - - _ _ ---------_ _ _ _ _ _ _ _ _ _ _ _ __
.. . ,
25
prior to the next outage and placed in service so that the normally-
available ARM coverage is maintained. The inspector will follow the
licensee's resolution of this issue during routine inspections.
12.0 Committee Activities (71707)
The inspector attended Plant Operations Review Committee (PORC) meetings
2-89-22, 2-89-28, 2-89-29, 2-89-30, 2-89-35, 2-89-46, 2-89-48, 2-89-54,
and 2-89-56 on 2/10, 2/15, 2/15, 2/16, 2/20, 2/27, 3/1, 3/10, and 3/13.
Committee administrative requirements were met for the meetings, and the
committee discharged its functions in accordance with regulatory require-
ments. The inspector observed a thorough discussion of matters before the
PORC and a good regard for safety. No inadequacies were identified.
The inspector also attended meetings of the PORC (2-89-37) and the Nuclear
Review Board (2-89-3) on 2/22, held to review a proposed change to Tech-
nical Specification 3.9.3.2 requirements on spent fuel pool cooling. The
reviews by both committees were thorough and technically sound. The pro- ,
posed technical specification request was subsequently not submitted due
to a change in plant conditions. No inadequacies were identified.
13.0 Licensee Event Report (LER) Review (92700)
Licensee event reports submitted during the period were reviewed to assess
LER accuracy, the adequacy of corrective actions and compliance with 10
CFR 73 reporting requirements, and to determine if there were any generic
implications or if further information was required. The LERs reviewed
were:
--
LER 89-001-00 " Fire Barrier Penetration Seels Inoperable"
--
LER 89-002-00 Main Steam Safety Valve Setpoint Drift Uncovered ,
During As-Found Simmer Test" '
--
LER 89-003-00 " Combined Leakage Rate Exceeded"
No unacceptable conditions were identified. LER 89-001 review is ad-
dressed in Detail 12.1, and LER 89-002 is considered in Inspection Report
50-336/89-03.
13.1 LER 89-001-00, " Fire Barrier Penetration Seals Inoperable"
)
On February 2, at approximately 5:00 p.m. , the licensee determined
that two fire barrier cable penetration seals were inoperable. The ,
cable penetrations were identified as numbers 108 and 109, located '
between the main cable vault and east electrical penetration room.
The inspector reviewed the following documents in follow-up of LER
89-001-00:
!
l l
i
i
I
_ - _ _ - - _ . _ - - _ _ - _ - . _ _ _ __ _ _ - _ - _ _ _ - _ . . _ _ . -_
l
F (.:,n, o,
26
1
'
,
--
Authorized Work Orders (AW0s) M2-89-01394, M2-89-12525, and
l M2-88-12705
--
MP 272IN, " Sealing and Seal Repair of Electrical Cable and
Piping Penetrations"
---
PIR (Plant 1Information Report) 89-07
--
Nonconformance Report (NCR) 289-005
--
Millstone 2 Fire Hazard Analysis
l
--
Technical Specification 3.7.10
--
Control Room Shift Turnover Logs
The cable penetrations were opened on December 28, 1988 (#108) and
January 3,1989(#109) to pull electrical cables for the steam reiief
position indicator and reactor c alant pump seal modifications. The-
licensee entered applicable TS action statement 3.7.10.a.3.
On January 26, the licensee permanently sealed the two penetrations
using Dow Corning 795 buildins sealant. Licensee procedure MP2721
step 3.2 specifies Dow Corning 96-081 RTV adhesive / sealant as an ac-
ceptable material per specification SP-EE076. The materf al order
request used t) procure the sealant from the warehouse requested ;
" Silicon Caulk-Black." Procedure'MP2721 step 5.11.2 requires the 1
recording of the batch-number of the adhesive / sealant on form 2721N1.
The quality control (QC) inspector reviewed the sealing process and -
questioned the required shelf life information for the Dow Corning 1
795 sealant. The QC inspector did not initially recognize the wrong ;
sealant material was used during installation on January 26; however,
.
.he did identify the material procured was QC Category I. The QC in-
spector, after questioning the shelf life information on the sealant,
contacted the licensee's corporate ' reliability engineering and fire
protection engineer. On January 31, the QC inspector concluded the
permanent sealant was the wrong material. On February 2, the QC in-
spector initiated NCR 289-005 to document the fire sealant material
discrepancy. Licensee immediate action on February 2 was to declare
the fire penetration seals inoperable at 5:00 p.m. and commence a '
roving hourly fire watch per TS 3.7.10.a.1. The fire seals were re- ;
sealed and declared operable on February 2 at 11:45 p.m.
The cause of the event was personnel error in not adhering to proce-
dure MP272IN; specifically, step 3.2 of MP272IN on acquiring /and in-
stalling the approved fire barrier sealant.
w
_ - - _ __ - _ _ - - - _ _ _ _ - _ _ - - _ _ - _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - _ _ - _ - _ _ _ _
.. . - . . , .
L.
27
The inspector asses: the safety significance of this event. For
fire area A-10, the. re three ionization smoke detectors and
alarms, and a hose ai.o portable fire extinguisher. Fire area A-24
has an early warning ionization smoke detector, fire temperature and
heat rate-of-rise detection and a manually operated deluge system, a
wet sprinkler system, and a portable extinguisher. According to LER
89-001, the affected areas were monitored and protected by an oper-
able fire detection and suppression system during the time of the
inoperable fire seal.
The total time period the penetration was inoperable until an hourly
fire watch was established was approximately seven days (January 26 -
February 2).
The inspector interviewed the QC inspector on actions taken after
irproper seal installation on January 26. On January 27, the QC in-
spector discussed the lack of shelf-life expiration date for the
building sealant with the licensee's procurement department at the
storage warehouse and the fire protection engineer in the corporate
office. According to the QC inspector, on January 31 corporate engi-
neering personnel concluded the sealant used was incorrect.
On February 2 an NCR and Plant Incident Report (PIR) 89-07 was pre-
pared by the licensee to identify the incorrect sealant material.
Inspector review of LERs for the previous year concluded that no pre-
vious corrective actions should have prevented this event from occur-
ring.
The inspector verified entrance into TS action statement 3.7.10.a.1
on February 2, and penetration repairs per AWO M289-01394, and re-
storation of the seal. Further licens4e actions included counseling
the crew supervisor on material specification as stated in procedure
and other wurkers involved. This is a licensee identified violation
per 10 CFR 2, Appendix C (NV 89-05-01).
The inspector discussed with licensee management the time interval
between identification of the wrong sealant material and the TS ac- !
tion statement being entered. Adequacy of contractor supervision and
of QC notification of the plant staff about fire penetration seal
operability are unresolved (UNR 89-05-09) pending licensee evaluation
and NRC review.
14.0 Observation of Maintenance (62703)
The inspector observed and reviewed selected portions of preventive and
corrective maintenance to verify compliance with regulations, use of
administrative and maintenance procedures, compliance with codes and
)
_ _ _ - _ _ _ _ _ - _ _ _ - _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ _
-_ __ . _ _ _ - __
._ . _ _ _ .. _ _ - - _ _ - _ _ _ - . _ - _ _ _ _ _
-
, - ,..-. . e . ; . I
!
28
.
,. standards, proper QA/QC involvement, use of bypass ~umpers and safety
1
tags, personnel protection, and equipment alignmer and retest. The fol-
lowing activities were included:
--
Reactor Vessel' Head Installation e 'oa
--
AWO M2-89-01485, " Troubleshoot the CEA. Logic Circuit."'
--
Repairs to 6.9 kV cable between the NSST and Bus 25A on 3/7/89. 1
No inadequacies were identified.
15.0 Observation of Surveillance Testing (61726)
The inspector observed portions and review of completed surveillance tests
to as:,ess performance in accordance with approved procedures and Limiting
Conditions of Operation, removal and restoration of equipment, and de-
ficiency review and resolution. The following tests were reviewed:
--
Fuel movement for fuel assemblies M-44 and L-64 on 2/14/89
--
0F 2316C and OP 2316B restoration of EDG lineup.
No inadequacies were noted.
16.0 Periodic Reports (92700)
Upon receipt, a periodic report submitted pursuant to Technical Specifi-
cations was reviewed. This review verified that the reported information
was valid and included the NRC required data, and that the test results ,
cnd supporting information were consistent with design predictions and '
performance specifications. The inspector also ascertained whether any
reported information should be classified as an abnormal occurrence. The
following reports were reviewed:
--
Monthly Operating Report for Millstone 2 for December, 1988.
--
Monthly Operating Report for Millstone 2 for January,1989. l
--
Monthly Operating Report for Millstone 2 for February,1989.
The inspr.ctor noted a minor administrative discrepancy ;n the cover sheet
for the monthly operating reports. The licensee docume ..rd the report in
'accordance with Technical Specification (TS) section 6.L.I.3. The correct i
TS section is 6.9.1.6 for TS amendment no. 132 dated September 28, 1988. ;
The inspector discussed the above discrepancy with the licensee. The lic- !
ensee committed to correct this discrepancy on the next monthly operating ;
report (March, 1989). The inspector had no further questions. i
_ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ - _ --- _ __- _ __ ________ _ _ _ -
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p. 1
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29
17.0 Management Meetings (30703)
Periodic meetings were held with station nianagement to discuss inspection
findings during the inspection period. A summary of findings was also
discussed at the conclusion of the inspection. No proprietary information
was covered within the scope of the inspection. No written material was
given to the licensee during the inspection period.
i
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