IR 05000423/1989008
| ML20246P215 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 07/11/1989 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20246P203 | List: |
| References | |
| 50-423-89-08, 50-423-89-8, GL-88-17, NUDOCS 8907200133 | |
| Download: ML20246P215 (29) | |
Text
.
' _;
_- -._
-. _.
__
_
_
_ _ _.
-
- - -
,
_-
-
y
,
,
^
,
3.g :.
~
, h h,
- 8; t
e 0*
'.
.'
,
V
'
U.S. NUCLEAR REGULATORY L
REGION I
,
'
Report No.
50-423/89-08-Docket No.
50-423 License No.
,,
. Licens'ee:
Northeast' Nuclear Energy Company P.O. Box 270 Hartford, CT 06101-0270
' Facility Name:. Millstone Nuclear Power Station, Unit 3 Inspection At:.Waterford, Connecticut
'
Inspection Conducted:' 'May 15 to June 12, 1989 Reporting Inspector:
W. J. Raymond, Senior Resident Inspector-Inspectors:
W. Raymond, Senior Resident Inspector F. Crescenzo,. Senior Resident Inspector, Shoreham D. Jaffee,' Project Manager, NRR
'G. Garten, Project Engineer, N.RR A. Asars, Resident Inspector, Haddam Neck A. Krasopoulos, Reactor Engineer
.
S. Barr, Reactor Engineer Approved by:
ESA C.
d>".
'7 /fl[F1
E. C. McCabe, Chief, Reactor Projects Section IB Date Inspection Summary: Inspection'on 5/15/89 - 6/12/89 Areas Inspected:
Routine onsite inspection (232 hours0.00269 days <br />0.0644 hours <br />3.835979e-4 weeks <br />8.8276e-5 months <br />) of plant operations, Unresolved Item (50-423/87-12-01), previous inspection findings, Plant Incident Reports, Incore Thimble degradation,' safety evaluations performed per.10 CFR 50.59, licensee actions in response to Generic Letter 88-17, procedures for reduced inventory and ott 'r actions for Generic Letter 88-17, design change training for operators, mxiifications reviews, refueling operations, mainten-ance, surveillance, and Licensee Event Reports.
.Results:
No violations or unsafe conditions were identified.
Licensee and NRC follow-up of tagging operations is warranted to assure the correct control of safety-related systems (see Section 5.2).
Licensee actions in response to Generic Letter 88-17 and preparations for operation with reduced RCS inventory were acceptable (see Sections 8.0 and 9.0).
8'907200133 890711ADDCK 05000423{;
PDR O
PNV g
_-
_ _ _ _ _ - - - _ _ _ _ _ _ - _ - _ _ _ _ _ _ - _ - - _ _ _ _ _ _ _ _ _ _ _ -_
_-
T, __. -
- - - - - - _ -
- - - - - - - - - -.
--
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
-
- - - - - - - -
- - - -
.
.
k
..c i. 5 ' *
.
..
L
,
,
,
,
l I'
L.
l TABLE OF CONTENTS PAGE'
1.0 Persons Contacted.....................................................
I 2.0 S umma ry o f Fa ci l i ty Act i v i t i e s.......................................
3.0 Status of Previous Inspection Findings...............................
3.1 (Closed) Unresolved Item (50-423/87-12-01), Inadvertent Actuation of the Carbon Dioxide System During Testing.........
4.0 Review of Facility Activities.......................
................
4.1 Service Water System Leakage....................................
4.2 Charging Pump / Lube 011 Pump Coupling............................
5.0. Plant Operational Status Reviews.....................................
5.1 Review of Plant Incident Reports (PIRs)........................
5.2 Tag-out Error and "B" Diesel Generator Maintenance..............
6.0 Incore Thimble Degradation.........................................
7.0 Audit of Safety Evaluations Performed per 10 CFR 50.59 for 1988 (37700)............................................................
8.0 Review of Licensee Actions in Response to Generic Letter 88-17, Loss of Decay Heat Removal (TI 2515/101)................................
8.1 Redefinition of Reduced Inventory...............................
9.0 Review of Procedures for Reduced Inventory and Other Actions for Gene ri c Lette r 88-17 (TI 2515/101)................................,
9.1 OP 3270, Reduced Reactor Coolant system Inventory Operation.....
9.2' OP 3301E, Draining the Reactor Coolant System Drain.............
9.3 E0P 3505, Loss of Shutdown Cooling..............................
9.4 Plant Design Change Record MP3-89-008...........................
9.5 Training........................................................
9.6 Containment C1osure.............................................
9.7 Reactor Coolant System Temperature..............................
9.8 Reactor Coolant System Water Leve1..............................
9.9 Reactor Coolant System Perturbations...........................
9.10 Alternate Sources of Reactor Coolant System Inventory...........
9.11 Control of Reactor Coolant System Loop Stop Valves..............
9.12 Conclusion......................................................
i
_ - -
. _ _ _ _ _ _ _ _ _
. _ - _ _ _ _ _. _ _ _ _ _ _ _ _ _ - _ _ - _ - _ _ _ _
[.
.
C.
.
,
..
.
.
.
Table of Contents PAGE-l 10.0 Design Change Training for 0perators................
................
11.0 Modification Reviews (37828, 37700, 71711)...........................
11.1 Annunciator Reduction Modi ficat ion (Blackboard).................
11.2 Electrical Protection Relay Modifications " Generator Coastdown"............................
.......................
.
12.0 Refueling Operations (71707, 60710, 60705, 71711)....................
1 l
l 13.0 Maintenance.....................................
....................
13.1 MSIV Control Solenoid Seat Cracks................................
13.2 MSS Safety Valve Setpoint Drift.................................
13.3 Loop Isolation Valve Body-Bonnet Leakage........................
13.4 Accumulator Level Indications Out of Calibration................
13.5 Litton-Veam Connectors......................................... 24 14.0 Surveillt.nce (61726)..................................................
-15.0 Review of Licensee Event Reports ( LERs).............................. 26 16.0 Management Meetings..................................................
ii
_ _ _ _ - _ _ - _ _ _ _ - _ _.
_ _ _
_ _ _ _ _ _ - -. _ _ _ - _ _ - _ _. - _ _ _
__
-
-
_
_ _ _
.
_. _ -
,
ll (Y
.
,'a.
..
@
./ --
.,
.,
.
,
DETAILS 1.0 Persons Contacted'
Inspection findings were discussed periodically with the supervisory and-management personnel identified below:
S. Scace, Station Superintendent C. Clement, Unit Superintendent,: Unit 3 M. Gentry, Operations. Supervisor R. Rothgeb, Maintenance Supervisor K.l Burton, Staff Assistant to Unit Superintendent J. Harris, Engineering Supervisor D.' McDaniel, Reactor Engineer, R. Satchatello, Health Physics Supervisor
!
M. Pearson, Operations Assistant H. Covin, Operations Assistant R. Enoch, I&C Supervisor 2.0 Sum. mary of Facility Activities l
The plant was in cold shutdown at the start of the inspection period and in day 6 of a scheduled 52 day refueling and maintenance outage.
Major, activities for Refueling Outage.42 included installation of reactor level instrumentation for mid-loop operation,. installation of an ATWS mitigation. system, ISI weld inspections, steam generator tube eddy current testing, vessel refueling and inspection of core components, vessel ex-aminations, and service water system inspections and repairs.
The plant remained shutdown for the refueling outage at the.end of the inspection period, with fuel shuffle activitie's complete and testing of
.the 'A' train engineered safety features components in progress.
3.0 Status of Previous Inspection Findings 3.1 (Closed) Unresolved Item (50-423/87-12-01), Inadvertent Actuation of the Carbon Dioxide System During Testing The licensee, while performing a surveillance of the fire detection system in the East MCC/RCA area, accidentally caused a Carbon Dioxide system actuation and discharge. The cause of this event was an in-adequate procedure and lack of adequate training of the operators performing the surveillance.
The licensee addressed these problems as follows:
-
_ - _ _ _ _
_ _ - _ _ -
_. - _ _
_ _
_ - _ _ _
_ - _
_ - _ _ _ _ _ - _ _ _ _ - -
_ - _ _ _ _ --
_
- c.
, '.
,
'
(1) The detection system surveillance procedure, SP36410.3, was re-vised to include the precaution that gaseous suppression systems (Carbon Dioxide and Halon) must be isolated prior to performing any tests on systems that could activate the Carbon Dioxide or
,.
Halon system.
l l
(2) Operators and other plant personnel are being given additional l
training to increase awareness of gaseous fire suppression sys-tem hazards.
(3) The licensee has implemented a new procedure, OP3341E, controll-ing access and work in areas prctected by a Carbon Dioxide sup-pression system. This procedure also requires Carbon Dioxide system isolation when work is being performed in these areas.
The above activities address the NRC cor.cerns in this area and re-solve this item.
4.0 Review of Facility Activities (71707)
The inspector reviewed plant operations from the control room and reviewed the operational status of plant safety systems to verify safe operation of the plant in accordance with the requirements of the technical specifi-cations and plant operating procedures. This review included periodic verification that Technical Specification 3.4.1.4.2 and 3.4.9.3 require-ments for reactor shutdown cooling and vessel overpressure protection were met.
Plant logs and control room indicators were reviewed to identify changes in plant operational status since the last review and to verify that changes in the status of plant equipment was properly communicated in the logs and records. Control room instruments were observed for correlation between channels, proper functioning and conformance with technical speci-fications.
Alarm conditions in effect were reviesed with control room operators to verify proper response to off-normal conditions and to verify operators were knowledgeable of plant status. Operators were found to be cognizant of control room indications and plant status.
Control room manning and shift staffing were reviewed and compared to technical specification re-quirements.
No inadequacies were identified.
4.1 Service Water System Leakage The Millstone Unit 3 Service Water System (SWS) supplies salt water cooling to various safety and non-safety related components.
The service water system supplies filtered water for lubrication of the
_ _ - - _
_ - _ - - _ - - _ _ _ _ - _ _ _ - _ - _ _ _ _ - _ _ - _ - _ _ _ _ - _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ - _ _ _ - - _ - _ _ _ _ - _ _ _ _ _ - - _ _ _ _ -
_ _ _ _ - - - _ _
,
_ _.
. _ _
_
_
_ _ _ _ _ _,
_ _ _ _ _ _. _ _ _ _ _
'
,'.
,-
.
-
"
circulation and service water pump bearings and also serves as' a backup source of water (emergency) for the spent fuel pool, for auxiliary feedwater, and for control building chilled water makeup.
Since 1987, the Service Water System has experienced minor chronic leakage. The licensee described his program for addressing service
.,
water system leatage in a letter to the iiRC dated April 28, 1989.
Previous NRC review of this area is described in Inspection Report 89-04 During this inspection, the Production Maintenance Management System (PMMS) was queried as to the number of Automated Work Orders (AUDs)
that were issued to repair Service Water leakage. The PMMS printouts indicated that one AWO was issued in 1987, a total of 17 AW0s were.
issued in 1988 and, as of June 1, 1989, 10 AW0s had been issued.
During the outsge,, the Service Water System was inspected and the licensee's repair program was discussed with licensee perscnnel. The following observations were made:
Many of the Service Water leaks have occurr.d in small/ medium
--
bore Copper / Nickel pipe. The leaks seem to occur near pipe
"Ts", elbows or reducers. The licensee has, where possible, replaced elbows with wide radius sweeps to decrease erosion.
The licensee has also replaced some Copper / Nickel pipe fittings with Monel fittings which the licensee expects will increase corrosion resistan:e.
A few Service Water leaks have occurred in large bore pipe, in-
--
cluding leaks at the SWS outlet from the "A" Reactor Plant Com-ponent Cooling Water Heat Exchanger, and from the SWS supply to the turbine plant heat loads.
At least one Service Water System leak was caused by poor mate-
--
rial selection. The large bore pipe between the "B" Diesel Generator Intercooier and Jacket Cooler developed a leak and was subsequently identified as unlined carbon steel.
This material is unsuitable for salt water service. During the present re-fueling outage, the subject pipe and the corresponding pipe at the "A" Diesel Generator will be replaced with lined stainless
steel pipe.
Licensee actions completed during the outage included the com-
--
l pletion of repairs to the service water leaks on large bore piping in the vicinity of valves V35, V71A and V718.
The in-
'
spector reviewed work activities in progress to weld repair the piping wall defects and to apply Balzona as a corrosion protec-i l
tion layer.
l
l
__-______ ___-_ - __-_ - __ - -_- - _
-
M _g.
-
,.
---
w ? K: ]..5 E ~. {
Ei'
-
,
,
y,, r
_q d-p n.
c.,
'
lll *
'
,
_
'
g pt.
-
^
The inspector.noted,.by visual inspection of the pipe sections-with the through-wall defects, that the ;orrosion was highly
. localized in the affectad areas. No inadequacies were identi-'
fied in the repair efforts.
'
.
The inspector had no furth'er questions regarding the sal't water cor-
'rosion/ erosion problem associated with'the Service Water System at'
'the.present time.
Inspection item 50n423/89-04-01 tracks additional NRC follow-up of this issue.
Licensee actions'in this area will be.
reviewed further on subsequent routine inspections.
'4.2 Charging' Pump / Lube Oil Pump Coupling Westinghouse: Technical Bulletin NSID-TB-85-19,-dated September 24, 1985, addresses a. wear problem in the coupling ~b + een the charging
,
'
pump speed increaser and the associated luba oil pump.
Failure of this: coupling occurred at D.C. Cook Unit 1 and Almaraz Unit 1.
West-inghouse recommends tnat the coupling be. inspected during each re-fueling outage.
The inspector was present when the "B" charging pump (3CH5*P38) was undergoing maintenance during the refueling outage..~When the subject ~
coupling was removed for inspection, wear was clearly visible on both u
pins and both holes. The design pin diameter is 0.50 inches and minimum pin-diameter was 0.47 inches on each pin. The design hole diameter is 0.56 inches and the maximum hole diameter was 0.60 inches on each hole. The acceptance criteria in NSID-TB-85-19 are a minimum
'
pin diameter of 0.375 inches and a maximum hole diameter of 0.750 inches.
Based upon the Westinghouse acceptance criteria and consultation with Westinghouse, the licensee feels that the coupling will be acceptable for a number of refueling cycles and should be reinstalled "as is."
Replacement parts will be obtained as a precaution. The licensee's Nonconformance Report 389-127 documents the acceptance of the coup-.
t ling wear.
No inadequacies were identified in the licensee's evaluations or cor-
rective actions.
5.0. Plant Operational Status Reviews (7170_7,J 5.1 Review of Plant incident Reports The plant incident reports (PIRs) listed below were reviewed to (i) determine the significance of the events; (ii) review the licen-see'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 in accordance with applicable requirements, if required. The PIRs reviewed were: 76-89, 63-89, 62-89 and 73-8,,
__
___
_.-_ -_ __
h
..
u ( ' J..
-n
[ < kh
>
,
.
\\,
- PIR 73-89 regarding'setpoint drift problems with 14 of.20 main steam M
safety valves warranted inspect. ion followup and is discussed further
-
'
'in'Section 13.2'of this' report.
~
di
.5.2 Tag-out. Error During "B" Diesel Generator Maintenance x
During inspection.of "B" Diesel Generator maintenance, the associated Tag out 3-3880-89, was checked for correct implementation'. Two items,. Tag 26 (Jacket Water' Circulation Pump Switch - 3EGS*P2B) and Tag 28 (Generator Space. Heater Switch -- 3EGS*H28) were incorrectly set. iThe tag log-sheet for. 3-3880-89 shows 3EGS*P2B and 3EGS*HEB in the "off" position (both switches were found to be in.the "on" posi-tion).
The circuti breakers'for 3EGS*P2B and 3EGS*H2B were verified.
to be in ' the correct '.'of f". position.
The licensee promptly restored 3EGS*P2B and 3EGS*H2B to their. correct
"
'loff" position and generate.c PIR 76-89.
Licensen review of the cause
,
of the subject switch misalignment problem will be completed as part of the PIR evaluation and will be reviewed on a subsequent routine NRC inspection.
The inspector noted that the safety significance of the tagging error
'was minimal.dnce personnel and equipment protection was provided by the upstream breakers.
Further, the inspector noted that this may be
- .an isolated example of a problem with correct performance of tagging operations at Millstone 3.
This item is unresolved pending NRC re-view of the licensee's PIR evaluation and pending further inspection of tagging (UNR 89-08-01).
6.0 Incore Thimble Degradation (71707)
The licensee performed eddy currant testing (ECT) during the refueling outage on the incore instrumentation thimbles to determine the degradation
.of the thimble tube wall thickness. The ECT was ' performed as a result-of
'inforsnation Notice 87-44 and as a follow-up to ECT performed in the first refueling outage (see Inspection Report 87-33). The results of the first ECT were reviewed by Westinghouse, where it was subsequently recommended '
that thimbles with a wall thickness diminished by greater than-SO% should be either repositioned or capped off.
In addition, Westinghouse concluded that thimble tubee. with 60% material wear loss over e length of 1/2 inch are structurally adcquate to withstand RCS pressurest During the last outage, six thimbles were determined to have a wall loss in excess of 25%
and were subsequently retracted 1.25 inches. One thimble (tube no. 41-N-4) was found to have a wall loss of approximately 38% and was capped off and left in place for future degradation measurements.
The remaining thimble tubes had either no wall loss or had wall loss of le$s than 25%
and no corrective actions were taken.
- - - _ -
_ - - _ _ _
_ - _
_ _ _ _ _
'
+._
.
,
-
.
Of the six thimble tubes that were previously retracted, one (tube no.
45-P-4) displayed wall loss in the newly exposed area. This tube will be retracted an additional 1.X inches.
It had initially been thought that the maximum amount that any thimble tube could be withdrawn was 2 inches.
However, subsequent review has shown that a thimble tube can be retracted by as much as 4 inches.
The licensee has determined that the additional axial retraction will have no adverse impact on incore flux readings.
In addition, a second thimble tube, one not previously retracted, will also be retracted 1.25 inches. The thimble that had previously been capped off has shown an additional wall loss of approximately 5%.
This subsequent degradation will be noted for future reference in an effort to develop a curve displaying wall thickness degradation rates. Another thimble, tube no. 45-N-13, showed approximately 58% wall loss and will also be capped off.
The licensee is obtaining additional information on whether or not areas that had been previously retracted (not exposed during last cycle)
have shown any new wall loss.
The licensee's approach to monitoring, capping and retracting tubes was found consistent with recommendations from Westinghouse and similar re-pairs at other plants as noted in Information Notice 87-44.
Furthermore, the licensee is considering a Westinghouse magnr. tic isolation valve as a means by which a leaking thimble can automatically be isolated. Follow-up ECT is to be performed during the next outage to identify the need for i.Jditional correcthe action and possiole long-term solutir,ns to the wall loss problem.
No inadequacies were identified.
The inspector had no furth r questions.
7.0 Audit of Safaty Evaluations Performed per 10 CFR 50.59 for 1988 (37700)
The licensee's procedure ACP QA-3.26, "PDCR Evaluation," requires that changes to the facility be evaluated for safety significance.
Those changes which could impact plant safety are designated wi'a a plant design change records (PDCR) number and evaluated per NE0 3.03, " Preparation, Review, and Disposition of Plant Design Change Records." The requirements of NEO 3.03 include the need for a safety evaluation.
Table 1 (at the end of this report) lists PDCRs selected from the PDCRs in the licensee's 1988 Annual Report.
These PDCRs were selected for ieview since they involve " safety-related" systems.
Each PDCR reviewed contained a safety evaluation (Safety Evaluation and/or Safety Evaluation Worksheet and/or Integrated Safety Evaluation in accordance with NEO 3.12, " Safety Evaluation.") For each of the PDCRs in Table 1, the safety evaluation was reviewed and found to meet the safety evaluation requirements of 10 CFR 50.59 (b)(1) in that the PDCRs "... include a written safety evaluation I
which provides the bases for the determination that the change, test, or l
experiment does not involve an unreviewed safety question."
_ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ -
_ _ - - - _ _ _ _ - - - - _
_. - - _ _ _ _ - _ _ - _ _ _ _ _ - - _ _ _ - _ - - - _ - _ _ - _
-
-
W yQ f:
.
~
- dy
~
J For plant changes which are judged.to be minor, the change can'be imple-mented within the controis specified by ACP QA-3.26. Thetsafety evalu-ation requirements of QA-3.26 allow either a written safety evaluation per NEO 3.12 or certification that no safety evaluation is required.'.Two
-
plant design change record evaluations (PDCEs) reported in the 1988 Annual-Report were evaluated'regarding 10 CFR 50.59, as shown in Table 1.
Both of-these PDCEs (MP3-88-022 and MP-3-88-059) involve' systems described in-the FSAR (Auxiliary Feedwater Pumps and Reactor. Coolant Pumps, respec-tively) but neither of these PDCEs contains a written safety evaluation-.
This situation was; judged to be acceptable in that the changes did not affect the safety function of the subject component / system and.thus did not' represent ' changes to the. facility as described in the FSAR.
Table 2 also at the end of this report, is a' summary 6f other activities,.
reported in the'1988 Annual Report,.which are subject to.the licensee's 10 CFR 50.59 review process.
In those cases.where'a safety evaluation was:
. prepared, the safety evaluation was found to be adequate to meet 10 CFR 50.59 (b)(1)
'In the case of 3-87-023 and 3-87-014,. no rafety evaluations were provided. This situation was judged to be acceptable in that.the subject procedural changes did not change the safety function of'any com-ponent or system credited in the FSAR.
The descriptive and safety evaluation material in the 1988 Annual Report was reviewed for -those activities listed in Tables 1 and 2.
It was con-cluded that material required to be submitted in the Annual. Report per 10 CFR 50.59(b)(2) meets the requirements of the rule with regard to the de-scription of the activities and a summary of the associated-safety.evalu-ations.
Based upon tht above, the licensee met the requirements of 10 CFR 50.59.
Areas that we e-acceptable included maintenance of records for facility changes ( procedure changes, and tests including safety evaluations as ap-propriate, and reporting of these activities. No inadequacies were iden-tified.
8.0 Review -of Licensee Actions in Response to Generic letter 88-17, Loss of Decay-Heat Removal (TI 2515/101)
Loss of decay heat removal during nonpower operation and the accompanying consequences have received increased attention in the nuclear industry during the last several years.
Recent events at nuclear plants have in-creased the awareness of and insight into these events.
In response, NRC issued Generic Letter (GL) 88-17, Loss of Decay Heat Removal, on October 17, 1988.
The GL identifies deficiencies in procedures, equipment, and training in the areas of accident prevention, accident mitigation and the control of radioactive materials in the event of core damage following a loss of de-L cay heat removal capability. Accordingly, licensees were asked to imple-i ment expeditious actions and program enhancements to improve procedures,
,
-
_. -. - - ~ ~ _. ~
-.. _ _ _. - _ _. - _
_ _ _ _ _ __ _
s.
.
'O e
'
equipment, and training in this area. The expeditious actions were to be completed prior to entering reduced inventory operations.
The program
- enhancements are to be completed prior to startup from the second refuel-ing outage after issuance of the GL.
The licensee responded to this GL by letters' dated December 23,'1988 and Janua ry 31, 1989.
These letters described the actions to be taken in ac-cordance with GL 88-17. The inspector reviewed these responses and con-ducted an inspection of the implementation of the expeditious actions.
The program enhancements will be reviewed during a future inspection.
During February 1989, the licensee experienced an unplanned shutdown for repair of a hot leg loop stop valve leak.
This repair required mid-loop operation. Special procedures were prepared and operator training was conducted prior to mid-loop operation.
The repair effort and mid-loop operation are described in NRC Inspection Report 50-423/89-02.
The licensee will operate with reduced inventory and at mid-loop during the current refueling outage. Operation in this condition is required for Inservice Inspection of eight pressure isolation check valves in the Low Pressure Safety Injection and Safety Injection Accumulator discharge flow paths and to perform maintenance on the eight loep stop valves.
8.1 Redefinition of Reduced Inventory The expeditious actions identified by the GL are to be implemented prior to entering into reduced inventory operations.
Reduced inven-tory operations occur whenever the reactor vessel water level is more than three feet below the reactor vessel flange.
Millstone Unit 3 has elected to redefine the minimum reactor vessel level for reduced inventory operations from three feet to five feet below the reactor vessel flange. This is because of the inverted
" top hat" design of the reactor upper internals package.
The upper internals sit lower in the reactor vessel than in the standard design considered by the GL. The redefinition of reduced inventory will prevent overflow and possible introduction of debris and contaminants into the reactor vessel flange and stud holes when the upper inter-nals re placed in the vessel.
The licensee elected to use two methods for determination of the minimum height at which air entrainment into the RHR (Residual Heat Removal) system can be avoided: the Harleman Equation and a scale model test.
The Harleman Equation calculates the minimum reactor water level as a function of RHR flow velocity and system dimensions. The licensee determined, based on this calculation, that a minimum water level of 19' 6" with the normal RHR flow of 4000 gpm would be sufficient to avoid air entrainment.
l l
l l
_ _ _ - - _ - _ _ _ _ - _ _ - _ _ _ - - _
-_
- _ - - __ __-
._
q-
.-
,
<>
.
-
yl~
j'
^
+;
- {
.
,,[
'
-
s
,
A: scale model test of the Millstone 3 Reactor Coolant' System'(RCS).
during mid-loop operation was conducted by Westinghouse Electric-Co.
i The. experiment concluded that a water level of at least 17! 6" is.
!
necessary to avoid RHR air entrainment.
The'-licensee elected to use the more conservativellevel (19' 6") as
-
tha redefined l reduced inventory level. This is e~quivalen.t to.five-feet below the reactor' vessel-flange.
The' inspector reviewed the calculation assumptions and results'and
~
the modell test results.
No discrepancies were' identified. Addi-tionally, the' acceptability of redefinition ofLreduced inventory was-discussed with the technical contact for this Generic Letter in NRC-Headquarters. The inspector was informed that this is acceptable and that other sites with reactor upper internals designs similar to Millstone 3.were also redefining reduced inventory. levels.
No inadequacies were identified. 'The inspector had no further ques-tions regarding the definition of reduced inventory operations as.it related to the GL guidance. NRC review of other licensee actions in response to GL 88-17 are discussed further below.
9.0 Review of Procedures for Reduced Inventory Operation and Other Actions for Generic Letter 88-17 (TI 2515/101)
The following three procedures are in effect for draining the RCS, operat-ing with the reduced inventory, and recovering from a loss of-shutdown cooling. The inspector reviewed the. revisions in'effect and discussed with the licensee = several inadequacies. and areas for improvement. At the close.of' the inspection period, the licensee was evaluating changes to
. improve the procedures. The inspector noted that these procedures were used without incident during the mid-loop operations in February,1989.
9.1 OP 3270,~ Reduced Reactor Coolant System Inventory Operation This procedure was initially written to support mid-loop operations-for February, 1989.
Its objective is to provide guidance and direc-tion for RCS operation at reduced inventory and mid-loop ' levels.
The inspector reviewed Revision 1 which eas scheduled for Plant i
Operation Review Committee (PORC) review during the inspection. The
following areas for improvement were noted:
j Minimum RCS venting requirements to prevent pressurization were
--
not specified.
i
--
Reference points for vessel water level varied, potentially creating confusion.
..
_ _____-___-___ _____- - -_
A
'
-
- _.
.
!
.
.
..
I
^
10-i RHR flow limits were not specified for operation when in reduced
--
inventory conditions.
There was.no prerequisite for operable gravity flow paths from
--
the Refueling Water Storage Tank (RWST).
'here was no prerequisite that RWST level be greater than 90% of-
--
the Technical Specification requirement for mode 1,2 and 3 in accordance with the assumptions of the calculations to support gravity feed of the RWST to the vessel.
,
There was no prerequisite specifying the condition of the un-
--
isolated steam generators, specifically, full and indicating on the narrow range level instrumentation.
These items were discussed with Operations and Engineerir g personnel and at the close of the inspection were under licensee review for incorporation into the procedure.
9.2 OP 3301E, Draining the Reactor Coolant System Drain OP 3310E provides for draining of the RCS and maintaining RCS level below seven percent in the pressurizer.. The inspector reviewed Re-vision 2, effective April 20, 1989, and noted the following:
The precaution statement requiring a seven square inch vent path
--
is not consistent with the 20.43 square inch vent path assumed by the calculations to support gravity feed from the RWST.
Figure 10.2, Duties and Responsibilities of Reactor Vessel Level
--
Watch, is not consistent with current operational practices and commitments.
These items are also under licensee review.
9.3 E0P 3505, Loss of Shutdown Cooling E0P 3505 is an Abnormal Operating Procedure newly written in the Westinghouse Emergency Response Guideline format.
Each step has an action / expected response and response not obtained column.
Concurrent with the inspection, during procedure review for lesson plan preparation Operator Trainug oersonnel identified discrepan-cies which were being incorporated as e revision to the procedure.
The inspector nuestioned whether Revision 2 to E0P 3505 had been validated on the simulator or through walkdown. Since this procedure is an Abnormal Operating Procedure versus an Emergency Operating
_
- _ _ _ - _ _ _ - _ _ _ _ _ _ - _ _ _ - _ _ _ _ - _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ _ - - - _ _ _ _ _ _ _
. _ _ _ _
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _.
_ _ _ _ _ _ _ _ - - - _
_____
l
- -
.
~
Procedure, the validation process ca'. be waived as it was in this ex-ample.
Nonetheless, had this procedure been validated, it is likely that the deficiencies would have been identified earlier.
9.4 Plant Design Change Record MP3-89-008 PDCR (Plant Design Change Record) MP3-89-008, Control Room Shutdown Level Indication and RHR Perf.ae:nc9 Monitoring, was initiated during this refueling outage.
The modif1 ation alters the monitoring of RCS level, RCS temperature, and RHR performance during cold shutdown and mid-loop operation in the following four ways.
1.
Video monitoring is to be installed to monitor tygon tube vessel level indication directly from the control room.
2.
Three level transmitters installed in the RHR pump suction and RCS letdown lines continuously monitor RCS level from the vessel flange to the bottom of the hot leg.
3.
Operating procedures were modified to ensure that the vessel head is in place, the RVLIS (Reactor Vessel Level Indication System) probes are in operation, and at least two Core Exit Thermocouple (CETs) are operational prior to entering reduced inventory conditions.
4.
An RHR Performance Monitoring software package, using new level i
transmitters and already existing instrumentation, was installed
'
in the Millstone 3 process computer to monitor and trend RHR performance.
The video monitoring in the control room will not be installed during this outage.
In the interim, a locally stationed vessel level watch will be in constant communication with the control room and record vessel level every fifteen minutes.
The inspector reviewed the PDCR package and observed portions of the l
level transmitter installation. The operating procedure changes were
!
also reviewed to verify that necessary changes were incorporated.
l Additionally, the inspector reviewed the draft post-modification test for the level transmitters and the performance software package, IST 3-89-005, Reactor Coolant System Level Monitoring.
No deficiencies were identified.
9.5 Training
!
GL 88-17 specifies that training be provided to the appropriate plant personnel, including discussion of the Diablo Canyon event, related l
events, lessons learned, and the implications of these events.
The training is to be provided shortly before entering a reduced inven-tory condition.
!
I
___m.,#_____m_._m
___--_
___
- _ _.. _ _ _ _
., t.
,l.
.
'
.. >
The inspector met with Operator Training personnel and reviewed the lesson plan for the training which was conducted in February,1989 prior to mid-loop operations. The training was conducted on a pre-shift basis for all licensed on-shift operators and all plant equip-ment operators.
The agenda included a review of the mid-loop opera-lon procedures, operation of the RHR system, and the Diablo Canyon event.
The discussion also included emphasis on ways in which the RCS can be perturbed and symptoms of air entrainment in the RHR sys-tem.
On May 24, the inspector attended the first of the training sessions to be conducted prior to entering mid-loop conditions during this outage.
The discussion of mid-loop operation lasted approximately 30 minutes. PDCR MP3-89-008 was described as well as the applicable operating procedures and highlights of the Diablo Canyon event.
During this session, cperators identified an apparent conflict be-tween OP 3208, Plant Cooldown. Revision 3, and OP 3270.
Procedure Change 4 was issued to OP 3208 on February 23, 1989 to mitigate an overpressure incident due to a safety in,Jection while the RCS is solid.
This change requires that the charging pump discharge motor-operated valves be closed, red tagged, and the breakers be racked out whenever that RCS temperature is less than 200 degrees F.
This is in conflict with Op 3270 which requires operable flow paths from the RWST for a gravity feed to the RCS in the event the RHR pumps are inoperable.
The licensee is evaluating methods to resolve this con-flict.
The inspector also discussed mid-loop operations training for Health physics, Maintenance, and Instrumentation and Control Personnel.
Health Physics rarson:1el receive radiological system training on a two year cych. This training includes detailed review of the RHR system and the Diablo Canycn event. The Millstone 3 training on loss of RHR was conducted during the first several months of 1989.
Maintenance and Instrumentation and Controls personnel received training on the sensitivities associated with mid-loop operations i
during department meetings in March and May, respectively. The
'
agendas included discussion of GL 88-17, previous loss of RHR events,
!
and prevention and consequences of RCS perturbations during mid-loop operations.
I No deficiencies were identified in these training programs.
i l
__
--
-_. ____ __ __ --_ -._-_ _- _-_
- -_
_ _ - _ _ _
s fpL i,
- e.,
<
e.
e a
.13 9.6-Containment Closure Containment closure is defined by GL 88-17 as a containment,andition where at least one integral barrier to the release of radioactive materials is_provided.
Containment closure must be achieved prior to the. time at.which a core uncovery could result..from a loss of RHR coupled with an inability to initiate alternate cooling or addition -
'
'of water to the RCS.
The licensee has committed to maintain containment closure during reduced inventory operations with' one' exception. A containrrent bar-rier may be open-during reduced inventory with prior approval by PORC.
These barriers must be closed prior to projected core uncovery
-
and are controlled by 0P 3270. Additionally, the licensee 'ias evalu--
ated the equipment hatch cloture requirements and provided guidance for the number of bolts, bolting pattern, and bolt tension.
'
9.7 Reactor Coolant System Temperature G'. 88-17 specifies at least two independent sontinuous temperature indications that are representative of the Lore exit conditions
.whenever the RCS.is in a mid-loop condition ana the reactor ver,sel head is in place. Temperature indications are to be periodically checked and recorded or automatically and continuously monitored and~
alarmed.. Temperature monitoring should be performed by an. operator.
in the control room or from a location outside of the containment bu;1 ding with provision for providing immediate temperature values to the control room should any significant changes occur.
The licensee has committed to maintaining two operable CETs with the ability to monitor RCS temperature on the plant process computer.
This ' monitoring capability is being incorporated into the RHR Per-formance Monitoring software package.
The inspector verified that the CETs are required to be operable per OP 3270, in accordance with the GL.
It was also noted that the RHR'
Performance monitoring software package did not provide an alarm for high temperature indication by the CETs.
However, OP 3270 will in-clude a periodic log of temperature when the RCS is in a reduced in-ventory condition.
9.8 Reactor Coolant System Water Level At least two independent, continuous RCS water level indications are specified whenever the RCS is in a reduced inventory condition.
Water level should be periodically checked and recorded or continu-ously monitored and alarmed. Water level should be monitored by an operator in the control room or from a location with provision for
_ - - ___-____
_ - _ - - _ _
_ _
- _ _
_ - _
- - _ _ _ _ _._
- .
-
'
providing immediate water level values to the control room should significant changes occur. Observations should be recorded at in-tervals no greater than fifteen minutes.
Millstone 3 installed three independent RCS water level transmitters in the RHR pump suction and RCS letdown lines by PDCR MP3-89-008.
This PDCR is discussed in Detail 9.3 of this report. Additionally, the RVLIS system will be operational and monitored by the plant pro-l cess computer.
The inspector reviewed the PDCR and associated procedural controls.
It was noted that the RHR performance software package also does not provide for an alarm for the RVLIS indication.
However, provisions for a periodic log of water level while the RCS is a reduced inven-tory condition are contained in OP 3270.
9.9 Reactor Coolant System Perturbations GL 88-17 requires that procedures and administrative controls be im-plemented that generally avoid operations that deliberately lead to perturbations to the RCS and other systems needed to maintain the RCS in a stable and controlled condition while the RCS is in reduced in-ventory conditions.
OP 3270 and 3301E provide for the control of plant systems and con-figurations while in a reduced inventory condition. These procedures are discussed in Detail 9.2 of this report. Additionally, the possi-bility and consequences of RCS perturbations were discussed in the pre-mid-loop training for the Millstone 3 staff.
9.10 Alternate Sources of Reactor Coolant System Inventory At least two available or operable means of adding inventory to the RCS, in addition to pumps that are part of the normal RHR systems, are specified. These should include at least one high pressure in-jection pump.
The water addition rate capable of being provided by each of these means should be at least sufficient to keep the core covered.
Procedures should be provided for these water seurces.
The licensee has provided for forced flow paths from the RWST through the charging, safety injection, and recirculation spray pumps. Ad-ditionally, a path for gravity feed from the RWST through the rh eg-ing and safety injection systems is to be operable.
The inspector reviewed the proposed flow paths and calculations to support the gravity feed from the RWST with Operations, Site Engi-neering, and Corporate Engineering personnel.
The gravity feed cal-culation assumes that a vent path exists which is equivalent to one pressurizer safety valve removed (20.43 square inches). The inspec-tor noted that provisions for an adequate vent path, to ensure that
_ - _ - _ - - -
. _.
_
.-
.
-
, _ _ _ _ - _ - _ - _ - _ _
_-
+'
4.
.
A g3
_a..
.
'
- a;,
l
.
15-
J the proposed forced and gravity. feed ~ flow paths are operable, and-that the.RWST contained the inventory assumed for the. gravity feed calculations were not contained in the associated operating proce-u
'"
dures. These were discussed with the licensee and are.to be evalu-ated for. incorporation in the procedure' revisions.
9.11 Control of Reactor Coolant System Loop Stop Valves Administrative procedures and. controls shall be implemented.to assure
-
that all RCS hot legs are not' blocked simultaneously by closed loop:
stop valves.unless a vent path large enough to prevent pressurization.-
is provided or unless the RCS configuration prevents water loss if l
pressurization should occur.
-OP 3270 requires that at least.one RCS loop be operable when in re-duced. inventory conditions and no more than two RCS loop will be
-
isolated at one time. Additionally, it was.noted that Mil'Istone 3 has loop stop valve interlocks which prevent opening of the cold. leg u
. loop stop valves unless the~ hot leg loop stop in the'same loop is open.
The inspector verified that OP 3270 did include these provisions.
No deficiencies were identified.
9.12 Conclusion The. inspector concluded that Millstone 3 has adequately met the re-quired expeditious actions of GL 88-17.
Items were noted by the in-spector for evaluation and possible incorporation in the operations
' procedures to strengthen the ' procedures and controls for ' operation under reduced inventory conditi-ons.
- 10.0 Design Change Training for Operators q
On May 24, the inspector attended the first session of outage modification
. training for licensed and.non-licensed operators. The training is being conducted for operators following shift turnovers and lasts approximately one hour.
.The agenda included changes to Technical Specifications (TSs), plant modifications, and a discussion of operations with reduced inventory conditions as required by NRC Generic Letter 8817.
The session included detailed discussions of the modifications and associ-ated operational implications and procedure changes. Operators were in-quisitive and made comments on apparent conflicts between new procedures
,
and existing procedures-A handout had been prepared which describes in
.
detail each modification and associated TS and procedure changes.
The inspector found the training to be adequate and identified no con-cerns.
_ _. - _
_ _ - _ _ - - -
- .,
.
.
'
s 11.0 Modifications Reviews (37828, 37700)
Plant modifications performed to meet regulatory commitments were selected for review as discussed below. Modifications performed in response to generic letter 88-17 were also reviewed as discussed in Section 9.4 above.
- 11.1 Annunciator Reduction Modification (Blackboard)
The inspector reviewed Plant Design Change Record (PDCR) MP3-88-013 Revision 1, which reduces the number of unnecessarily lighted an-nunciator windows in the main control room.
This represents " phase:
II" of a program implemented to comply with a commitment to achieve a
" blackboard" on the main control board.
The procedure provides instructions to revise logic schemes such that annunciator windows will not be illuminated when the associated sys-tems are not in service. Three annunciators were modified:
Auxiliary Feedwater Pump "A" Lube Oil Pressure Low.
--
--
Auxiliary Feedwater Pump "B" Lube Oil Pressure Low.
--
Turbine Plant Component Cooling Water Heat Exchanger Service Water Outlet Pressure Low.
The auxiliary feedwater (AFW) lube oil pumps are shaft driven off the main AFW pump.
Currently, the AFW low lube oil annunciators are needlessly illuminated whenever the main AFW pumps are not operating.
The modification will interlock the annunciators with AFW pump
switchgear such that the annunciator will illuminate only when the pump is operating and the alarm condition exists (low lube oil pres-sure).
I The Turbine Plant Component Cooling Water (TPCCW) heat exchanger ser-vice water low pres:ure annunciator illuminates whenever a low ser-vice water pressure condition exists in one of the three TPCCW heat exchanger. The TPCCW heat exchangers are each designed to handle 50%
rated load.
Under normal conditions, one of the three will be out of service causi:ng the alarm condition. The modification will interlock the annunciator with the discharge valve on each heat exchanger.
When the valve is closed, the annunciator logic associated with that heat exchanger will be disabled.
The inspector reviewed the PDCR package for compliance with Station Procedure ACP-QA-3.10, Preparation, Review and Disposition of Plant Design Change Records.
The inspector reviewed the technical adequacy of the PDCR as well as the adequacy of the 10 CFR 50.59 Safety As-j sessment.
The inspector noted that Plant Operations Review Committee
(PORC) approval for implementation had not yet been obtained.
'
l
_ _ _ _ _ _ _ _ _
- _
I
.,
-
_
- -_. -
h
, y,f.
4.1 p
LSeveral other minor administrative items were also missing-. LThe'in--
spector verified,ithrough discussion with the' cognizant plant engi-
.
neer, that this was' consistent with ACP-QA-3.10... All required ap-
+
- provals, including PORC, could be deferred until the' package was re---
leased to the field. Minor " Pre-construction" items had been're-
' leased for work. These were properly approved and released. The technical aspects and safety evaluation were found to be adequate.
The inspector had no further questions.
11.2 Electric.nl proteition Relay Modifications " Generator Coastdown"'
The inspector i a1twed PDCR MP3-89-010 to accomplish modifications-to electrical promt lon relaying schemes that were required (in p' art)
to correct a design deficiency described in LER 88-26.
Four separate modifications were included in the package.
These were:
,
Revision of the fast transfer' scheme on the 4KV buses to block a
--
sustained undervoltage condition on the 4KV bus from initiating a fast transfer from the Normal Station Service Transformer (NSST) to the Reserve Station Service Transformer (RSST).
For. the 4KV system, the opening of the NSST supply breaker (other than control switch operation) will initiate a transfer to the l'SST.
The fast transfer time is short enough (several cycies) to~ ensure that decaying residual voltage on the 4KV bus, and Rn T voltage, are not out of synchronization (sync). A fast transfer is blocked after this time frame. All trips of the NSST are for fault corW tions except for sustained undervoltage on the 4KV bus or manual emergency trip.
To allow a fast trans-fer initiated by unoervoltage deviates from the assumption that NSST voltage is in synchronization with RSST voltage prior to the transfer occurring.
Such a transfer could be out of syn-chronization with RSST power, possibly causing damage to elec-trical equipment connected to the 4KV bus. The modification blocks a fast transfer from occurring on an undervoltage trip of the NSST, The slow transfer scheme (which utilizes a synchron1-zation check) is not affected by this modification.
Revision of electrical protective circuits such that, whenever
--
switchyard breakers 15G-13T-2 and 15G-14T-2 are open, the main generator output breaker and the NSST supply breakers will trip causing a fast transfer to the RSST. This modification also prevents out of synchronization fast transfers from the NSST to the RSST.
The 15G breakers connect the main generator and NSST to respec-tive offsite AC power sources.
If both ISG breakers were to open at power levels below 40%, and the main generator breaker remained closed, the plant auxiliary buses would remain con-nected to the generator through the NSST supply breakers. The
!
_- -
. _ _ - _. -_ _
,
__
_ _. - - _ _ _
_
y 4,.
.
t
'
,
resulting electrical transient would be-an i_nitial overvoltage and overfrequency followed by an exponential decay of these parameters during generator coastdown.
During coastdown, several actions could result in a fast transfer to the RSST.
In H
certain circumstances, this fast transfer would be out of syn-
)-
chronization in phase and voltage.
This could damage the elec-l l
trical loads connected to the auxiliary buses.
The. modification L
will initiate tripping of the generator output breaker and NSST
'
supply breakers whenever both 15G breakers are open. Thus, dur-ing coastdown, the generator will not remain connected to the plant' auxiliary buses.
The above modifications were made in response to a design in-adequacy discovered by the licensee and detailed in Licer see Event Report (LER)88-026.
Revision of the directional relays on the 4KV emergency buses
--
such that the, Emergency Diesel Generators (EDGs) can be exer-cised with either the NSST or'RSST supplying plant loads.
Trie NSST supplies the emergency bus through a non-emergency bus and a tie breaker.
The RSST supplies the emergency bus directly-through its supply breaker.
Reverse current flow from the emer-gency bus through the tie breaker is limited to 1120 amps by a directional overcurrent trip of the tie breaker. This trip is designed to protect the emergency bus and EDG from external faults when the EDG is in parallel with either the NSST or the RSST. With the RSST supplying plant loads (tie breaker closed, NSST supply breaker open) and the EDG in parallel, during normal operation the current flow through the tie breaker is greater than the 1120 ampere setpoint.
The directional overcurrent trip will thus prevent exercising the EDG in parallel with the RSST even though no fault existi, on the 4KV buses.
This problem contributed to a plant trip which was described in LER 88-028.
The modified configuration will subtract current sensed at the RSST supply breaker from the directional overcurrent trip of the
!
4KV tie breaker. The trip setpoint of this modified parameter will remain at 1120 aiaps.
In this fashion, the original design basis for the tie breaker reverse overcurrent trip will be main-tained while accounting for current flow from the RSST.
This will allow the EDG to be exercised in parallel with the RSST during normal operations.
k'dition of a more sensitive high current detector for the 4KV
--
emergency bus differential relays into the protective scheme.
This change will provide the differential relays a uniform re-sponse time for all levels of fault current.
Previously, the current sensing unit could sense all levels of fault current but was more sersitive to low level faults than to higher level
__
_ _ _ _ _ _ _ _ _ _ - - - - - _ - _ _ _ _ _ _ - - - - - _ - _ _ -
_
- - - _ - -
-
-
- -
d
- _ _ - _ _ _ -
,l-l*
'
faults.
The new current sensing unit provides added protection and sensitivity at high fault levels. The use of this unit was originally deleted because of seismic concerns.
Subsequent lic-ensee evaluation qualified the units for Unit 3 seismic design parameters.
The inspector reviewed the PDCR package for compliance with procedure
.ACP-QA-3.10.
The inspector also reviewed the technical adequacy as well as the 10 CFR 50.59 Safety Assessment. No discrepancies were noted.
l 12.0 Refueling Operations (71707, 60710, 60705, 62703)
The inspector verified fuel movements within the reactor cavity and spent fuel building were conducted in accordance with Technical Specifications and Station Procedure EN 31007, " Refueling Operations." No significant personnel or procedural inadequacies were noted. A communications error of minor significance nearly resulted in violation of procedural require-ments to maintain fuel building integrity during fuel movements in the spent fuel building.
It was suggested to licensee management that stric-
ter communication controls be considered during fuel 'novements in the
'
spent fuel building.
A number of equipment failures or problems of minor or no safety signi-ficance were identified by the licensee during the refueiing operations.
Five Rod Cluster Control Assemblies (RCCAs) were replaced following Eddy Current Testing..Four RCCAs were rejected due to indications of rod guide wear.
The fifth RCCA was rejected due to evidence of hafnium hydriding.
All five RCCAs were replaced in accordance with PDCR-MP3-89-012.
Two fuel element defects were identified via ultrasonic test (UT) inspec-tion. The licensee had detected indications of failed fuel elements dur-ing the previous cycle via isotopic analysis of coolant samples. These indications suggested there were very small leaks in a small number of
"once burned" fuel elements. At no time during'the cycle were technical specifications for coolant activity exceeded. All eighty-nine "once burned" fuel assemblies were UT inspected. Two assemblies were found to contain leaking elements.
The two assemblies were located * corner to corner" to each other during the last cycle.
For this reason, the licen-see UT inspected the two, "twice bor.ied" assemblies which had been adja-cent to the leaking assemilies.
Two other "twice burned" assemblies were UT inspected for unrelateo easons.
No leaking elements were identified in these additional inspec. tons. No other assemblies were UT inspected.
Both leaking assemblies * ere replaced in the core.
The inspector discussed this finding with the Unit 3 Reactor Engineer and verified the licensee's actions were in accordance with POCR MP3-89-012.
The inspector also reviewed the coolant analysis trending for the previous cycle. With the exception of periods following plant trips, dose equiva-lent iodine (DEI) 131 :evels remained at approximately 1.0E-02 uCi/gm. On
,
_...______._____________J
--
- -
-
-
--
_
4,..,
,
Jn'
A
'
at least three occasions during the cycle, DEI levels approached, but did
'
.not exceed,Lthe technical specification limit of l'0 uti/gm..These
.
'" spikes"'were short lived. The' inspector had'no further questi_ons.
A fuel assembly grid strap was found broken during the core offload. The-broken segment was retrieved from the core. area without incident. The licensee is designing a shield to allow removal and disposition of the-strap.
Preliminary-indications suggest the strap was broken during the previous core load..This is based on observed oxidation on the fuel as--
sembly where the strap should'have been. Also, reload records from the-last refueling outage revealed two under-load trips of the SIGMA refueling.
r"ichine during reload of the affected fuel assembly. The lice :see is con-
~
tinuing their analysis of the circumstances. The. inspector has no further.
questions at this time.
Fuel movements were delayed for approximately 3.6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> due to poor water clarity.in both the spent fuel pit and reactor cavity..The poor water clarity interfered with the refueling apparatus operator's vision into the-pool areas. Chemistry analysis confirmed the clarity problem was caused by iron oxide.. The licensee suspects the iron oxide came from the "B" train of Residual Heat Removal (RHR) which had recently been restored to service following a period of dry layup and maintenance. The licensee restored pool clarity by using temporary filter sMds and by increasing' purifica-tion flow.
The inspector had no further questions.
The inspector found the licensee's actions to address these technical problen,s to be adequate.
13.0 Maintenance An NRC inspection team completed a programmatic review of the maintenance
. area for all Millstone units during.the period of Nay 30 - June 16, The review was completed per the requirements of TI 2515/97 and the results
.
are described in Inspection Report 50-423/89-80.
Resident inspector ob-
'
- ,ervations and findings as part of that effort are provided in the Main-tenance Team report.
The inspector observed and reviewed selected portions of preventive and corrective maintenance to verify compliance with regulations, use of ad-ministrative and maintenance procedures, compliance with codes and stand-ards,' proper QA/QC involvement, use of bypass jumpers and safety tegs, personnel protection, and equipment alignment and retest.
No inadequacies were identified.
13.1 MSIV Control Solenoid Seat Cracks l
During the inspection and service of the MSIV 3 MSS *CTV27B, the licen-l see discovered a small crack and a diminished height in the seat of j
control solenoid 3 MSS *SV2728.
This solenoid is one of two redundant l
solenoids that will deenergize to open and allow steam into the upper
- _ _ _ _ _
_ _
_ - -
_ _ _ _ _ _ - _
_ -
. _
__ ____ -- __ _____ _ _
_ _ _ _ _ _ _ -
__
_ _ _ _
_ _ - - _ _ _ _ -
.. j 9,94,
,
.$
' '
'
'
'
~
'
'n y
M piston chamber to close the MSIV. The two solenoids work.in con-junction with two' vent solenoids that must also close so that suf-
'
ficient steam pressure will build in the' upper piston chamber to close the. main valve.
Of the two redundant solenoids that allow steam into the upper piston chamber, only one is needed.to provide.
p enough steam to close the valve.
- The solenoid valve seat is. welded into 'a control bloc'k (manifold) and
. cannot readily be removed. Therefore, the licensee decided to repair the valve' seat in place.
Since.the valve seat has been lapped in
-
previous ~ valve servicing', it has become necessary to build the sole-noid valve seat'up to maintain the valve: stroke within its-required limits. To build up the seat height, the licensee will be using an electrochemical metalizing process.
The metalizing procedure can be found under special procedure 89-3-8.
The' process will be bonding a stronger nickel-based compound to the valve seat..The tensile strength of the bond is 12,000 psi which should be-strong enough to resist any peeling.
The meta 11 ting process is not expected to fill the crack but will maintain the existing crack width and size. After-completing the metalizing process, the valve seat will be lapped so
'
that the-valve disk has 100% contact seating.while maintaining the
. required seat height. The metalizing process has been performed pre-viously on a feedwater valve from Millstone Unit 1.
Although this valve has not yet been disassembled for reexamination, the licensee has determined t'is. type of repair to be permanent. As a follow-up, n
automatic work order AWO MP3-89-10096 will require a follow-up in-spection and repair (if needed) to be performed at the next outage.
Although the crack will not be repaired by the metalizing process, the licensee has determined that the crack will have no adverse im-pact on the safety function of the MSIV (closure-isolation).
The crack in the seat begins at the seat surface and extends down the length of the seat base. The crack in the seat face will allow steam to' escape through the solenoid causing additional scoring in the valve seat and allowing steam to enter the upper piston chamber.
With the vent valves (IA, IB) open, the steam pressure in the upper piston chamber will not be sufficient to cause the MSIV to inadvert-antly close.
Should the seat fail completely, a 9.5 mm built in ori-fice will restrict steam flow into the upper piston chamber. With the vents open and at a design operating pressure of 1185 psi, ap-proximately 144 psi can be expected in the upper piston chamber.
This is insufficient to cause the MSIV to close, thereby preventing inadvertent plant transients from resulting in a MSIV closure.
Since the purpose of this solenoid is to allow steam into the upper piston chamber for MSIV closure, a failure of the solenoid seat will not prevent the MSIV from performing its designed safety fmetion (clo-sure-isolation).
In addition, a second steam solenoid which performs the same function and offers redundancy in MSIV control.
l
. _ _ _ _ _
X
,&
J
~
"
~
~
~ ~
~
R~ ~- O
,
,
,
9) n
,
';-
,-
,
-
w u
.
Millstone has not experienced this type' of seat cracking _in the past.
This valve is unique in the U.S. and Europe, and there is no history
' of seat failure to draw upon. The. licensee and the manufacturer do not feel that this will be a recurring problem. 'The inspector had no further questions at this time.
iDuring the MSIV inspection and servicing, the licensee discovered that the replacement check valve used in the control block had cracks-
'
in its' machined surfaces.
Since the licensee has additional. replace-ment check _ valves, this discovery will not affect the operation of
'the MSIV at this time. However, the licensee will be looking_into the quality control implications of this discovery. A single defec-tive check valve would not affect the safety function of the MSIV (closure-isolation). There are two separate trains (control' blocks)
of control solenoids that control MSIV operation, with two check
'
valves in each. The check valves maintain a working steam pressure in the control blocks during a main steam line break.(upstream or downstream).
In order for the MSIV not to close, a similarly posi-tioned check valve'from each train would have to fail. The licensee and the manufacturer believe that the probability of failure of two similarly placed check valves is small. This fact, coupled with'the
'
thoroughness of the mechanics installing the replacement parts, sug-
~
gests that the probability of adversely affecting MSIV operation will be small. The inspector agreed but suggested a follow-up in the quality control area and perhaps a check valve installation proce-dural modification to ensure that new components are carefully ex-amined.
No inadequacies were identified in licensee actions to perform valve maintenance, and to identify and correct discrepancies.
13.2 MSS Safety Valve Setpoint Drift l
Plant Incident Report 73-89 dated 5/17/89, documented setpoint drift problems with 14 of 20 Main Steam Safety valves. The problem was identified during a routine surveillance test to check the setpoint l
of the installed valves. Technical specifications allow a +/-1%
l tolerance in the acceptance criteria for the test. Ten of the safety valves exceeded their setpoint by greater than 1%. One of these ex-f ceeded the allowable setpoint by more than 3%.
The remaining fail-ures were greater than 1% below their allowable setpoint.
Thirteen of the 14 safeties were reset within the +/-1% tolerance. Three of the fourteen valves required en adjustment after the initial retest.
These three valves are to be replaced by the licensee. The removed valves will be examined by the vendor (Crosby).
MSS setpoint drift has been a recurring problem at Millstone Unit 3.
Lice,see Event Report (LER) 87-36-00 documented setpoint drift on 11 MSS ulves.
The licensee suspects high drift is caused by sticking
}
l f
!.
-
___
-
_ _ _ _
_
_
_
.
,. ' ( C.
.
'
..
between the valve disc and seat during-the first' lift. This is sug-gested by the generally higher initial lift value for the first lift.
Low setpoint drift may be caused by spring' relaxation over extended periods' of time at elevated temperatures.
The as-found lift settings in May 1989 did not have adverse safety implications:-licensee evaluation concluded the valves lif ted within the low pressure bounds analyzed for a steam generator tube rupture
,
incident,-and within the high pressure bounds of the main steam sys-tem design.
l The licensee is considering a design change to expand the setpoint.
tolerance to +/-3%.
This will require a change to technical speci-fications and a boiler code exception. The licensee does not intend to submit this change before the end of this outage.
The inspector had no further questions.
13.3 Loop Isolation Valve Body-Bonnet Leakage The licensee has discovered that 7 of the 8 main loop isolation valves (LIV's) show indications of leakage at the body to bonnet joint.
The leakage appears to be small; however, leakage at the hot leg valves was more severe based on greater boric acid deposits and contamination levels. The licensee had previously repaired body to
~
bonnet leakage on the "A" and "B" hot leg valves in April 1988-and February 1989. Both these valves show evidence of continued leakage.
The root cause of the chronic leakage is unknown at this time.
The discovery of this problem has added a significant workload to the outage. The licensee had originally intended to lower vessel level to mid-loop for check valve inspections.
LIV work will extend mid-loop operations about 3 days.
Tne licensee is evaluating alternative solutions to correct the problem. These alternatives include a stud stretch evaluation, and/or replacement of the body to bonnet gasket with upgraded Flexicarb gasket materials.
The licensee might choose to forego re-pairs on certain of the valves. The leakage is not considered pres-sure boundary leakage and, as such, can continue without violating technical specifications. (Identified and unidentified leakage rates during the cycle were minimal.) The licensee does intend to perform extensive inspection of one hot leg valve to determine a root cause for the leakage.
The inspector will continue to monitor the licen-see's activities to resolve this issue.
13.4 Accumulator Level Indications Out of Calibration Seven of eight Safety Injection Accumulator level transmitters were found out of calibration during surveillance testing. The detectors are Barton capillary D/P cells with capillary bellows seals separat-ing the process fluid from the detector. Accumulator tank level is
...
....
-___-__ _ _ _ ____--_-_______ -__ - -_- - ___-_______-______-- -_______--___-_ _-_ -_ _ _a
_ __
_ ___
._
__
._.__ _ - _. _ _ _ _ _ _ _ _ _ - - - - _ - _ - _ - - _ _ _ _ _ - -
%- *
.
.
,...
.
.
used to verify compliance with TS 3.5.1, which specifies a level band.
Each of the four accumulators has two redundant level indi-cators.
A' plant incident report (91R) was written to document the failures.
Five le~el instruments were found reading higher than actual; two v
read lower than actual. Two accumulator t.'nks had both. level in-struments reading higher than actual (Tanks "B" and "C").
Tank "A" had diverging errors in both instruments and tank "0" had one in-strument reading low with the other reading within specification.
The licensee is researching operator logs of accumulator tank levels during the last cycle tv c >termine if, given the error as found, the accumulators may have t.
'noperable during the cycle.
PIR 3-89-90 tracks completion of licensee review of this issue, which will de-termine the impact on plant safety from operating with the transmit-ter errors. This item is unresolved pending completion of the licen-see's review and subsequent review by the NRC (UNR 89-08-02).
These level detectors were found out of calibration during the last refueling outage.
The licensee suspects a design problem with the detectors and/or their sensing configuration. The licensee is in-vestigating possible design modifications or operational compensa-tions.
It is not anticipated that the licensee will take actions to modify the indicators during this outage.
The licensee may however, change the alarm setpoints to compensate for anticipated errors through the next cycle.
The inspector had no further questions.
13.5 Litton-Veam Connectors Litton-Veam connectors are used at Millstone Unit 3 to provide an environmentally qualified barrier between an instrument's electrical connections and the exterior environment.
The qualification testing for the Litton-Veam connector is documented in NUSCO Test Reports No.
558-1657A and 16578.
Inspection Report 88-04 describes prior NRC review of this area.
A review of Litton-Veam connector installations indicated that 21 connectors were installed without heat shrink tubing over the con-ductor/ pin interface (see FIR 060-88) and thus were not environ-mentally qualified. Of the 21 installations, only 4 are required to be environmentally qualified per 10 CFR 50.49. An additional 41 Litton-Veam connectors were identified with potential IR leakage problems, within the connector, when exposed to the postulated ac-cident environment. Of these 41 connectors, the licensee determined that 27 were required to be qualified under 10 CFR 50.49.
Based OL the above, a total of 31 Litton-Veam connectors were scheduled for replacement during the refueling outage.
l l
_ _ _ __ _ _ - - _ _ - __-
_ _ _ -
. _ - - _ _ _ _ _
_ _ _.
. _ - _ _ - _ _ _ _.. _ - _
_ _
- _ _ _ _ - _ _ _ _
_
-
.
-
.
_
_
,
I-py
,
c.;,;.
-
.;
.
q
';
,
l
Th'e; inspector viewed the replacement of two Litton-Veam connectors with Rosemount connectors (3RCS*PT49 and_50). The work-packages vere we11' prepared and contained installation directions from both Rose-mount,(Manual 4498, Revision 00) and the licensee.
Installation per-:
sonnel vere found to be. knowledgeable concerning the installation requirements. The installation included appropriate quality _ inspec--
- tor coverage for critical-elements.
One error in _the installation -acceptance criteria was-identified by the NRCl inspector.- - The minimum bend radius for the connector seal-
- cable was established as greater than 1/2' inch by the installation instructions.
The acceptance critaria for the' bend radius, in'the inspection plan, was given as "Not greater than 1/2 inch." After a-N discussion with the licensee, the acceptance criteria.for bend radius
<
was corrected to be "Not less than 1/2 inch."
The same error was.
subsequently corrected in a number of Litton-Veam replacement work packages.
'
Inspector review of this matter with licensee personnel noted that the error did not result in incorrect ~1 installation since workers were
knowledgeable of the correct acceptance criteria. The insp d er had no further questions in this area.,
14.0 Surveillance (61726}
The inspector observed portions of surveillance tests to' assess perform -
ance in accordance with approved proceduret and' Limiting Conditions of Operation, removal and restoration of equipment, and deficiency review and
~
resolution..The inspector monitored: surveillance activities associated with the "B" Train, Engineered Safety Feature (ESF). The specific pro-cedures wre:
SP 3646A.11, "B LDG Full Load Rejection"
--
SP 3646A.20, "EDG Partial Load Reject"
--
SP 3646A.16, " Train B Loss of Power Test"
--
SP 3646A.18, "T-ain B ESF with LOP"
--
The inspector monitored preparations for the train "B" LOP (loss of off-site power) test performed on June 1, 1989.
These preparations included sysnem lineups, verifications, prerequisite performance, and pre-surveil-lance briefing.
The inspector observed control room operations during de-energization of the "B" 4KV emergency bus.
No personnel or procedural-inadequacies were noted.
Several component failures and test exceptions were noted. The failures were minor in nature and the inspector verified that Trouble Reports (TRs)
were-initiated for each failed component. A Plant Incident Report (PIR)
was also initiated to document the failed components. The test exceptions were components which were inoperable at the time of surveillance due to maintenance.
Both test exceptions and failures were properly listed in
,
-
-
-
-
,,
< /t a
.
p
.
.
the surveillance test acceptance criteria verification appendix.
These will need to be retested before returning the facility to mode 4.
The retests are not expected to require performance of the LOP surveillance.
Retesting of the' failures is positively controlled through the TR, AWO, and PIR programs. Test exceptions are tracked in a less formal manner.
The 09erations Assistant is solely responsible for tracking retest of. test except ons. The inspector found this practice acceptable but suggested i
that a more formal method be develloped to track test exceptions to ensure surveillance activities are completed.
The inspector reviewed the~ remaining completed surveillance procedures.
Test failures and exceptions were minor in significance and were properly documented on TRs in the acceptance criteria verification appendices. The inspector had no further questions.
No inadequacies were noted.
15.0 Review of Licensee Event Reports (LERs)
Licensee Event Report (LER) 88-26-01 was reviewed to assess LER accuracy, the adequacy of corrective actions, compliance with 10 CFR 53.73 reporting requirements, and to determine if there were generic implications or if further information was required. Selected corrective actions were re-viewed for implementation and thoroughness.
Licensee corrective actions for design deficiencies identified in the LER are discussed further in Section 11.2 above. The inspector had no further questions.
16.0 Management Meetings Periodic meetings were held with station management 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.
--
_ _ _ _ _.