IR 05000334/1989004
| ML20245C548 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 04/19/1989 |
| From: | Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20245C546 | List: |
| References | |
| 50-334-89-04, 50-334-89-4, 50-412-89-04, 50-412-89-4, NUDOCS 8904270210 | |
| Download: ML20245C548 (17) | |
Text
. _ _
_ _ - _ _ _ _ _
_
.
.
,
,.
,
.
U. S. NUCLEAR REGULATORY COMMISSION Region I Report:Nos.:
50-334/89-04 License Nos.: DPR-66 50-412/89-04 NPF-73 Licensee:
Duquesne Light Company One Oxford Center 301 Grant Street Pittsburgh, Pennsylvania 15279 Facility Name: Beaver Valley Power Station, Units 1 and 2 Location:
Shippingport, Pennsylvania Dates:
February 16 - March 31, 1989 Inspectors:
J; E. Beall, Senior Resident Inspector S. M. Pindale, Resident Inspector F. 9. W lson, Reactor Engineer
~ Approved by:
'A
.
/h 10well 'E. TripH Chief Date
'
Reactor Projects Section No. 3A Division of Reactor Projects Inspection Summary:
Combined Inspection Report Nos. 50-334/89-04 and 50-412/89-04 for February 16 - March 31, 1989 Areas Inspected:
Routine inspections by the resident inspectors of licensee actions on previous inspection. findings, plant operations, security, radiolog-ical controls, plant housekeeping and fire protection, surveillance testing, maintenance, personnel errors resulting in safety injection, OPPS Potentially Inoperable During Shutdown, Unit I safeguards building ventilation review and in-office review of licensee event reports.
Results:
One violation was identified regarding inadequate procedures which contributed to the March 22 safety injection (Section 7). Two unresolved items were identified. One involved the absence of administrative controls concern-ing the outdoor staging or storage of flammable items (Section 4.6). The other unresolved item involved apparently non-conservative assumptions in the design calculations for the safeguards building ventilation system as related to its capability to remove heat following an accident (Section 9). Seven previous open NRC items were closed during this inspection, while two others remained open.
427021o 9994,9 a
ADOCK osooo334 PDC
- - _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _
_ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ - _ _ _ _ _ - _ _ _ _ _ - _ - _ _ - - _ _ _ _ _ _ _ - _ _ _ - - _ -
_.
_____-_- _
___
.,
j
.
.
.
-.
.
..
v
.
TABLE OF CONTENTS P, age _
!
1.
Persons Contacted...........................................
1.
2.
S umma ry o f Fa c i l i ty Ac ti v i t i e s..............................
3.
Followup on. Outsusdi ng Items (92701).......................
4.
Plant Operaticm ( H707,-71710, 93702)......................
4.1 Genera 1................................................
4-4.2 ESF Wa1kdown...........................................
4.3 0perations.............................................
4.4 Plant Security / Physical Protection.....................
4.5 Radiological Controls..................................
4.6 Plant Housekeeping and Fire Protection.................
5.
Surveillance Testing (61726)................................
6.
Maintenance (62703).........................................
7.
Personnel Errors Resulting in Safety Injection (40500, 92700).........................................
..........
8.
Overpressure Protection System Potentially Inoperable During Cold Shutdown (71707, 93702).......................
12'
9.
Unit 1 Safeguards Building Ventilation (37700, 40500, 71707)....................................................
10.
In-office Review of Licensee Event Reports (90712)..........
11. Unresolved Items............................................
12. Meetings (30703)............................................
1
-
_ _ _ _ _ _ _ _ _ - _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _
_ _
_ _ _ _ _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ - _ _
- - - _
.
-
.
.
,
DETAILS 1.
Persons Contacted During the report period, interviews and discussions were conducted with members of licensee management and staff as necessary to support inspec-tion activities.
2.
Summary of Facility Activities At the beginning of the inspection period, Unit 1 was operating at 90%
power and Unit 2 was in Mode 3 (Hot Standby) following the February 12 reactor trip.
In accordance with the Unit I cycle extension program, weekend load reductions to 50% were made on most weekends.
On March 6, the 90% power level restriction was lifted and full power was achieved.
Unit I was at 100% power at the end of the inspection period.
Unit 2 reached about 57% power in a core coastdown mode on February 19. Unit 2 remained at that power level on one feedwater pump until commencing its first refueling maintenance outage on March 17.
Mode 5 was reached on March 19 and Mode 6 on March 26. At the end of the inspection period, the licensee commenced a total core offload.
3.
Followup on Outstanding Items The NRC Outstanding Items List was reviewed with cognizant licensee per-sonnel.
Items selected by the inspector were subsequently reviewed through discussions with licensee personnel, documentation reviews and field inspection to determine whether licensee actions specified in the OIs had been satisfactorily completed. The overall status of previously identified inspection findings was reviewed, and planned / completed licen-see actions were discussed for the item reported below.
3.1 (Closed) IFI (50-334/85-24-07) and Unresolved Item (50-334/86-20-02).
Review switchgear ventilation related temperature problems and planned modifications, and determine the root cause of No. 3 inverter failures.
Various equipment failures had repeatedly occurred on equipment such as vital bus inverters and control rod circuitry.
Licensee evaluations concluded that inadequate ventilation had sig-nificantly contributed to the failures.
The only means to remove
,
f heat from the switchgear areas was by forced ventilation of outside air.
The licensee recently completed the installation of a major station modification which provided a new switchgear ventilation and cooling system to address these concerns.
Additionally, locally mounted blowers was installed on several of the rod control cabinets to further enhance circuit card cooling.
l l
l
_-
. _ - _ - - _ _ _ _ _ _.
_ - _ - _ _ - - _ - _ _ _
- __ _
- _ _ _ _ _ - _. _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _
p-
.
l
.
.
.
.
,
,
There has been a -long-standing problem (several years) with the reliability of the No. 3 vital _ bus inverter. The licensee installed static transfer switches on the inverters to reduce the risk of plant trips when the inverter fails.
The switches will automatically transfer the supply for the 120 Volt AC vital buses to an alternate source of AC power.
Although the licensee replaced essentially all of the No. 3 inverter major com-ponents, operational problems continued to occur, but reactor trips did not result due to the static switches. The licensee's root cause investigation is continuing, though the effort has not yet been effective in eliminating the problems.
The switchgear ventilation and static switch modifications addressed several of the above concerns.
The static switch modification has been successful in eliminating reactor trips due to inverter fail-ures.
Further licensee efforts to resolve the operational problems and identify a root cause for the No. 3 inverter, and the effective-ness of the switchgear ventilation system modification will be reviewed during future inspections. These items are closed.
3.2 (Closed) Violation (50-334/86-12-03): Environmental Qualification of Victoreen Higa Ran9e Containment Radiation Monitors. This item was technically closed in NRC Inspection Report No. 50-334/88-21; how-ever, remained open.pending resolution of the potential enforcement actions.
The associated enforcement action was transmitted to the licensee on October 20, 1988.
Initial review of this item was com-pleted in Inspection Report 88-21 and no further concerns were iden-tifiec.
This item is closed.
3.3 (0 pen) IFI (50-334/87-05-01): NRC Inspection Report No. 50-334/88-27 updated this multi-item IFI, leaving sub-items 6, 8 and 10 open.
Sub-item'10 was initially reported and tracked as IFI 84-21-10. The issue was subsequently inspected and tracked as Unresolved Item 50-334/86-12-03.
On October 20, 1988, following an August 12, 1988 Enforcement Conference, the Unresolved Item was categorized as a Violation.
Therefore, sub-item 10 of 87-05-01 will be administra-tively closed.
See Section 3.2 for resolution of Violation 50-334/
i 86-12-03.
l
3.4 (Closed) Unresolved Item (50-334/88-08-04):
Lack of engineering justification for assuring low head safety injection (LHSI) pumps have sufficient net positive suction head (NPSH) during the recirca-lation mode with containment pressure controlled between 14 and 8.9 I
psia.
The licensee completed an engineering evaluation on October 21, 1988, to develop transient bounding analysis curves. The
curves appeared to indicate that there could be insufficient NPSH for
'
- - -
-
- _ _ _
___
.
__
. _ _ - -
.
. - _ - _ _ _
-
-
-
'l'
.
.
.
.
.
J the - LHSI pumps for : specific combinations of sump water. level and I
temperature, containment pressure and LHSI pump flow.
However, the evaluation showed that for all analyzed licensing basis. scenarios, there would be adequate NPSH for the LHSI pumps. The Mcensee con-cluded that the curves provide no real benefit to the accident
' management process since the indicated parameters reach unachievable values and therefore should not be incorporated into the Emergency Operating Procedures. An engineering review was conducted by the NRC which agreed with the licensee's conclusion.
This item is closed.
3.5 (Closed) Unresolved Item (50-412/88-13-01):
Review First-Out Logic Concern. Following an April 4,1988 reactor trip, the reactor cool-ant pump (RCP) auto-stop annunciator illuminated and sealed-in as the first-out rather than the reactor coolant system (RCS) low flow alarms. The RCP auto-stop did not cause a direct reactor trip on the one out of three coincidence, however, was indicated as such on the control room first-out panel. The licensee conducted a review of the Detailed Control Room Design Review (DCRDR) document and concluded that the operation and location of the RCP auto-stop (1/3 coincidence function) annunciator was in acceptable conformance with the DCRDR commitments.
The inspector conducted an independent review and agreed that. although the RCP auto-stop signal did not trip the reactor, the resulting low flow did cause the trip. The in>pector also concluded that this portion of the first-out circuitry was not in violation of the licensee's DCRDR documented commitments.
This item is closed.
3.6 (Closed) Unresolved Item (50-334/87-06-04):
Resolve discrepancies with MOV thermal overload settings versus design documentation. The inspector verified that the specific hardware deficiencies were resolved.
The licensee also enhanced the administrative process for issuance and control of setting sheets.
The inspector reviewed the governing procedures and no deficiencies were identified. The effec-tiveness of the licensee's corrective actions will be reviewed curing routine inspections.
This item is closed.
3.7 (Closed) Unresolved Item (50-334/87-06-02): Evaluate compliance with IEEE Standard 279-1971, Section 4.16 regarding the Supplementary Leak Collection and Release (SLCR) system.
The licensee conducted an evaluation and concluded that there was no deviation from FSAR com-mitments.
The inspector conducted an independent review and agreed that the applicable portion of the SLCR system logic design was in confer.mance with licensee commitments.
This item is closed.
- _ - - _ - __
__
__ -
- -__ - _ __ - -_-_ _ _____ - _ _ _
__ _ _ _ _ ______ _
_ -___-__ - _ _
-
. - _ _
.
_ _-
- _ _ _ _ _
+
.
,
- -
L
{
{
'
-
3.8 (0 pen) Unresolved Item (50-334/88-08-02):
Vibration monitoring of low head safety injection (LHSI) pumps yielded inconsistent results.
u The licensee revised surveillance test procedures to provide addi-tional details for accurately positioning the vibration shaft stick.
Additionally, the licensee began taking LHSI pump vibration readings'
l in terms of velocity as well as displacement. The inspector reviewd vibration data over the last year and found that inconsistent read-ings continued to occur.
Further. the magnitude of some of ' the velocity readings appeared to disagree with the relative displacement readings. The actions. taken by the licensee did not appear to be effective in eliminating the previously identified. inconsistencies.
The licensee informed the inspector that efforts were continuing to resolve the concern, including an evaluation of permanently installed vibration monitoring instrumentation. This item remains open pending licensee resolution of the above concerns, 4.
Plant Operations r
4.1 General Inspection tours of the following accessible plant areas were con-ducted during both day and night shifts with respect to Technical Specification (TS) compliance, housekeeping and cleanliness, fire protection, radiation control, physical security / plant protection and operational / maintenance administrative controls.
-- Control Room
-- Safeguard Areas
-- Auxiliary Building
-- Service Building
-- Switchgear Area
-- Diesel Generator Buildings
-- Access Control Points
-- Containment Penetration Areas
-- Protected Area Fence Line -- Yard Area
-- Turbine Building
-- Intake Structure
-- Reactor Containment
-- Spent Fuel Building 4.2 ESF Walkdown The operability of selected engineered safety features systems were verified by performing detailed walkdowns of the accessible portions of the systems. The inspectors confirmed that system components were in the required alignments, instrumentation was valved-in with appro-priate calibration dates, as-built prints reflected the as-installed systems and the overall conditions observed were sa ti sfactory.
The systems inspected during this period include the Emergency Diesel Generator, Safety Injection and Recirculation Spray systems.
No concerns were identified.
_ _ _ - _ _ _ _ _ _
_ - _ - _ _ _ - _ _ _ _ _ _ _ - _ - _ _ - _ _ _ _ _ _ _ _ - - _ _ - - - - - _ _ - -
- _ - _ _ - _ - -
- - - _ -
.
- - _ - -
--
--
- _ - _ - _
_
..
n
.
'
,.
~
4.3 Operations-During the course of the inspection, discussions were conducted with operators concerning knowledge of recent changes to procedures, facility configuration and plant conditions. During plant tours, logs and records were reviewed to determine if entries were properly made, and that equipment status / deficiencies were identified and communi-cated. These records included operating logs, turnover sheets, tag-out and jumper logs, process computer printouts, unit.off-normal and draft incident reports. The inspector verified adherence to approved procedures for ongoing activities observed.
Shift turnovers were witnessed and staffing requirements confirmed. Inspector comments or questions resulting from these reviews were resolved by licensee personnel. In addition, inspections were conducted during backshifts and weekends on February 17, February 24, March 4, March 7, March 8, March 9, March 14, March 17, March 18, March 19, March 21, March 23, March 25, March 30 and March 31.
4.3.1 Safety Injection Due to Personnel Error On March 22, an inadvertent Safety Injection (SI) occurred at Unit 2 while in Mode 5 (Cold Shutdown) with the reactor coolant system (RCS) vented to atmosphere due to a low pressurizer pressure actuation signal.
Technicians were performing loop calibrations on two pressurizer pressure channels simultaneously, and placed the associated bis-tables in the trip position, satisfying the two out of three coincidence necessary to actuate the SI.
The majority of the emergency core cooling system was tagged out of service due to plant configuration, however, actual injection of borated water into the RCS occurred (about 2500 gallons) since one SI accumulator isolation valve was electrically enabled due to concurrent operation surveil-lance testing.
There was adequate free volume in the pressurizer to accommodate the added water. The operable diesel generator also automatically started due to the SI signal.
Station procedures were used to restore plant systems to normal Mode 5 conditions.
For additional l
details and assessment of root cause, see Section 7.
4.3.2 Overpressure Protection System Potential Inoperable During Unit 2 cooldown initiated on March 18, the licensee experienced problems with the two PORVs providing low tem-perature overpressure protection for the RCS. The licensee was unable to restore a PORV and exceeded the TS allowed time period to vent the RCS to atmosphere in lieu of relief protection.
Alternative relief capacity was available throughout the period. Unit 2 was vented to atmosphere at 1:30 p.m.
on March 21.
For additional details, see Section 8.
. _ -
.___ __-__-__ _ _ _ _ _ _ _ _ _____ -_ _ _ - ___
._ _
- _ _ _ - _ _ _ _ - _
,
.
.
.
b
?
4.3.3-Inadvertent ESF Actuation Due to Component Failure.
I:
On March 11, while Unit I was operating at about 50% power,
'
an actuation of the control room emergency breathing air.
pressurization (CREBAP) system occurred due to the elec-tronic failure of. the
"A" train radiation monitor.
The.
licensee verified normal. radiation levels in the.tontrol room, and the CREBAP system was restored to normal.
The.
licensee identified a faulty radiation monitor power supply as the cause of the actuation, and the power supply was
,
replaced.
The redundant
"B" train of the. CREBAP system I
remained operable throughout the event.
The licensee i
reviewed the associated failure history data for radiation
' '
monitor power supplies to assess whether 4 'ges to the preventive maintenance program were nece>
however,
,
concluded that none were warranted due to the.ow magnitude of failure rates.
No concerns were identified with this event.
4.4 Plant Security /Ph/sical Protection Implementation of the Physical Security Plan was observed in various plant areas with regard to the following:
Protected Area and Vital Area barriers were well maintained and
--
not compromised; Isolation zones were clear;
--
l Personnel and vehicles entering and packages being delivered to
--
the Protected Area were properly searched and access control was in accordance with approved licensee procedures;
.,
Persons granted access to the site. were' badged to indicate
--
whether they have unescorted access or escorted authorization; Security access controls to Vital Areas were being maintained
--
and that persons in Vital Areas were properly authorized.
Security posts were adequately staffed and equipped, security
!
--
personnel were alert and knowledgeable regarding position requirements, and that written procedures were available; and
--
Adequate illumination was maintained.
No deficiencies were identifie. -
_ _ - - -
- -
_ _ _ _ _ _
_ _ _ _ _
_ - _ _ _ - _ _ _ - - -
_ _ _ _ _ _ _ _ _ _ - _ - - - -
.
- .<
.
,
.
-
-7'
4.5 Radiological Controls-Posting and control of radiation and high radiation. ~ areas were inspected.
Radiation - Work Permit compliance-and use of personnel monitoring devices were checked.
Conditions of step-off pads, ' dis-posal' of protective clothing, radiation. control job ' coverage, area monitor - operability and calibration (portable and permanent) and personnel frisking were observed on a sampling basis.
.
The inspector conducted walkdowns of the Containment and Spent Fuel'
Buildings before and during core ' offload.
Equipment material condi-tion, high radiation work support preparations, hot particle program implementation and fuel movement activities were reviewed (the hot-particle program is-discussed in detail in Inspection Report 50-334/
89-06;. 50-412/89-06).
The inspector questioned health physics managers and reviewed exposure records and noted that there had been no instar.ces of internal exposure, of f-scale dosimeters, or signifi-cant e.ternal exposure (highest recorded was below 700 millirem)
since the beginning of the calendar year.
Chemox respirators, normally used with the Containment. under. vacuum, were not found in use with the Containment at normal atmospheric pressure.
Steam generator (primary side) work sctivities with the -
potential for high airborne exposure to radioactive gas and particu-late were ' observed and the workers were noted _to. be using positive-pressure, hood-type breathing equipment. Other work activities with a lower potential for exposure were. performed with air. filter respirators.
Work activities in Containment were noted to be con-ducted'in two 10 hour1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> shifts per day with the 6:00 p.m. to 10:00 p.m.
interval not normally worked. Site work policies are consistent with NRC guidance in that an individual's work hours are limited to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in a 7-day period unless formally authorized by the licensee's senior management. Discussions with the licensee indicated that,. as of the end of the inspection period, no such authorization had been given.
No concerns were identified.
l
' 4.6 Plant Housekeeping and Fire Protection Plant housekeeping conditions, including general cleanliness condi-tions and control and storage of flammable material and other poten-tial safety hazards, were observed in various areas during plant tours. Maintenance of fire barriers, fire barrier penetrations, and verification of posted fire watches in these areas were also observed. The inspector conducted detailed walkdowns of the access-ible areas of both Unit I and Unit 2.
i J
'
i i
L---___-_________
_ _ _ _
- _ _ _ -
-
. _ -
k,
.
l
.
,
..
,
.
+
The inspector observed 20 55 gallon. barrels of lube oil against the outside wall of the Unit 2 diesel building.
Several other barrels were also present; :some were empty and others contained waste mate-rial such as rags and used oil filters.
Following questioning, the inspector determined both that the oil was -intended to replenish the 2-2 EDG reservoir after maintenance and that the operating staff was
~
not aware of'the presence of the oil. The inspector questioned the suitability of staging such a large quantity of flammable material against the safety-related building on March 17, 1989. No action was taken.by the licensee in response to the inspector'r concerns. On March 20, 1989 at 1:20 a.m., the 2-2 EDG was taken out of service; at that time the interior of the-structure against which the oil was stored no longer contained operable safety-related equipment.
Beaver Valley is committed to the Flammable and Combustible Liquids Code (NFPA 30) which places limits on the storage of flammable liquids. The code (Section 4.8) allows a maximum of 1100 gallons to be stored against exterior walls if constructed to a rating of not less than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. Although this limit may not have been exceeded in this instance, the inspector determined that the licensee had no procedure or controls concerning the outdoor staging or storage of flammable liquids implementing the commitment to NFPA 30. This item is Unresolved (50-334/89-04-01; 50-412/89-04-01).
.5.
Surveillance Testing The inspectors witnessed / reviewed selected surveillance tests to determine whether properly approved procedures were in use, details were adequate, test instrumentation was properly calibrated and used, Technical Specifi-cations were satisfied,. testing was performed by qualified personnel and test results satisfied acceptance criteria or were properly dispositioned.
The following surveillance testing activities were reviewed:
OST 2.1.11D Safeguards Protection System Train A CIA Go Test, performed on March 14, 1989 OST 1.24.7 Dedicated Auxiliary Feed Pump Test, performed on March 15, 1989 No deficiencies were identified.
6.
Maintenance The inspector reviewed selected maintenance activities to assure that:
the activity did not violate Technical Specification Limiting Condi-
--
tions for Operation and that redundant components were operable-
!
required approvals and releases had been obtained prior to commending
--
,
work; i
I l
_ - - - _ - _ - _ _ _ - _ _ _ - -
_ _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - - _ - - _ - _ _ _ _ _ - _ _ - - _ _ _ - _ _ _ -.
_ _ _ _ _
_ - - _ _ _
r
_
_ - _ _ _ _ _ _
j
.
.
.
.
..
,
.
.
--
procedures used for the task were adequate and work was within the a
skills of the trade; j
activities were accomplished by qualified parsonnel;
--
'
where necessary, radiological and fire preventive controls were ade-j
--
quate and implemented; i
l
~i QC hold points were established where required, and observed;
--
equipment was properly tested and returned to service.
--
Maintenance activities reviewed included:
MWR 890281, " Troubleshoot ID Bus Undervoltage Relays"
--
MWR 890288, " Investigate and Repair Spurious Control Room Alarms"
--
Additionally, the inspector reviewed several outage activities on Unit. 2.
These activities included:
Steam generator eddy current testing and tube plugging;
--
Reactor vessel head removal;
--
Inside containment snubber removal;
--
Fuel movement activities;
--
No significant deficiencies were identified.
7.
Personnel Errors Resulting in Safety Injection Several personnel errors (including procedure errors) contributed to the March 22, Safety Injection (SI).
Prior to the event, on March 21 at 6:30 a.m., technicians had obtained the signature of a control room super-visor, which acknowledged the commencement of the Pressurizer Pressure Loop 2RCS-P455 Protection Channel I Calibration (2MSP-6.35-I). Although not specified in the MSP, the technicians had been allowing about a 24-hour " soak" time for the pressure transmitter at an electrically simu-lated system pressure to address a previously identified instrument drift concern. When the calibration of Channel I was completed, the technicians removed the test device from the transmitter and obtained control room supervision authorization to commence 2MSP-6.36-I, the same calibration for Pressurizer Pressure Channel II (5:00 a.m. on March 22).
2MSP-6.35-I was not entirely completed at that point and the channel was not restored
_
_ _ _ - _ - _ _ _ -
_ _ _ - _ -_
_ _ - _ _ _ _ _
-
_-_
_ _ _ _.
- -, - - _ _ _ _ _ _
. _ _ -
--
--._
_ _ _ _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ - _ _ _ _
_-_______-
_
.
.
.
..
.
.
.
before entering the second channel.
When the technicians placed the pressurizer pressure SI blocking bistable in the " Test" position on Channel II, the P-11 SI block permissive (for shutdown conditions) was defeated and therefore, the two out of three Pressurizer Pressure SI actu-ation logic was satisfied.
The SI actuation occurred at 5:30 a.m.
The only ECCS pump that was not tagged out of service for Mode 5 conditions was the "A" charging pump, which was already running prior to the event.
The No. 1 Emergency Diesel Generator (EDG) automatically started as per design due to the SI signal actuation. The No. 2 EDG was not in service and so could not start The licensee reported the SI actuation to the NRC as a four-hour non-emergency report per 10 CFR 50.72 and stated that no water had been injec-ted into the RCS.
The inspector independently reviewed this event and questioned a pressurizer level recorder trace which appeared to show level variations subsequent to the SI.
The licensee then further reviewed com-puter printouts, level traces and other ongoing activities, and determined that there had been an injection of borated water into the RCS via the "B" SI accumulator. The licensee initially concluded that no injection had occurred because the SI pumps and associated flowpaths were on clearance and were incapable of injecting water into the core. However, an Opera-ting Surveillance Test (OST) 2.11.15, SI Accumulator Check Valve Test, was being performed concurrent with the two MSPs when the SI occurred.
OST 2.11.15 was intended to fully stroke the SI accumulator discharge check valves. The discharge piping arrangement is such that a discharge stop valve is downstream of the check valve for each of the accumulators. Dur-ing normal operation, the stop valves are opened and de-energized, how-ever, they still received an auto-open signal upon an SI actuation. Plant operators must insert an electrical jumper (jack) to permit remote opera-tion from the control room of the motor-operated stop valve (MOV). OST 2.11.15 (Issue 1, Revision 1) was written to insert the three jacks (one for each stop valve) within a single, three part step, however, plant operators inserted only one jack at a time.
The "C" accumulator MOV jack was not yet inserted because that accumulator was fully pressurized to provide a pressure source to maintain the closed "A" loop stop valves fully seated for the ongoing loop draindown evolutions (via Temporary Operating Procedure No. 2-89-05, Operation of Disc Pressurization System for Loop Isolation Valve Using SI Accumulators). The "A" and "B" accumu-lators had already been discharged separately and the
"B" was in the process of being refilled to be used for loop stop valve disc pressuriza-tion so that the
"C" accumulator could be tested.
The jack remained installed in the "B" accumulator MOV.
_ _ _
_ _ - _ _ - _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _.
_
-
- __-_ ____ -__ - _ _ _ _ -
.
.
.
..
f'
,
-
During the actual performance of OST 2.11.15, the operators used only one jack which electrically allowed movement of.one stop valve at a time (for the accumulator being discharged).
Therefore, at the time of the SI, since only the
"B" Jack was inserted, that MOV opened and the associated accumulator injected its partially filled contents of borated water into 1-the RCS (about 2500 gallons). If the operators had followed the procedure as written, at least two accumulators could have injected, filled the pressurizer which was vented to atmosphere and spilled into containment.
~
The licensee subsequently made a followup notification to the NRC Opera-tions Center on March 22 (about 1:00 p.m.) and provided clarification
,
l regarding the actual injection as a result of SI actuation. On the fol-lowing day, March 23, the NRC questioned the licensee whether an Unusual Event was or should have been declared due to the SI.
The licensee's emergency preparedness plan specified the declaration of an Unusual Event if an event occurred that resulted or should have resulted in emergency core cooling system discharge into the RCS.
Due to the failure to recognize and evaluate the operating of the accumulator stop valve, an Unusual Event was not declared since Operations personnel concluded that there had not been an actual injection of water into the RCS.
There were several concerns identified as related to the SI event, and are listed as follows:
1.
Technician supervisors directed the actions taken by the technicians regarding attempting to perform surveillance tests on two channels simultaneously.
2.
The evolution of taking out a protection channel for approximately one full day (" soak" period) was not described by station procedures.
3.
The surveillance procedure was not adequate in that it did not pre-vent the defeating of more than one pressurizer pressure block signal at a time.
l
'
4.
Control room supervisors acknowledged and allowed the activities described above without realizing the potential consequences 5.
Plant operators and station supervisors failed to determine that an actual injection to the RCS occurred until questioned by the inspec-tor later that day.
6.
OST 2.11.15, as written, did not prohibit the enabling of all three accumulator stop valves.
If "C" was not isolated for disc pressur-ization and the procedure was followed verbatim, all three accumula-tors could have injected into the RCS, overfilled the pressurizer, and caused a major spill of reactor coolant inside containment.
7.
An Unusual Event was not declared in accordance with the licensee's
{
Emergency Preparedness Plan.
I
.
l l
A
i
.
,
.
s a
The~ 1arge number and the potentially high safety impact of the above errors indicated an apparent breakdown in several areas, including atten-tion to detail and centrol of the integrated station activities.
10 CFR Part 50, Appendix B, Criterion V, requires that activities affec-ting quality shall be prescribed by procedures of a type appropriate to the circumstances and shall be accomplished in accordance with these pro-cedures.
As described above, Maintenance Surveillance Procedures asso-ciated with the pressurizer pressure calibrations (2MSP-6.35-I and 2MSP-6-36-I) and Operations Surveillance Test Procedure No. OST 2.11.15 were-found to be inadequate. This is a Violation (50-412/88-04-02).
8.
Overpressure Protection System Potentially Inoperable During Cold Shutdown Unit 2 reduced power and entered the first cycle refueling outage on March 18, 1989. At 5:19 p.m.,
dual indication was received on one of the two operable PORVs. The cause was the automatic cycling of the PORV block valves (as RCS pressure drifted about at the pressure setpoint) which led to the brief " popping" of both PORVs.
Stable RCS pressure indicated that both PORVs reseated but one valve (2RCS-PCV-455C) had dual indication (off the seat). In Modes 1, 2 and 3, faulty PORV indication requires that the associated block valve be shut and de-energized within one hour (TS 3.4.11).
The block valve actions were completed at 5:43 p.m..
The cooldown continued and Mode 4 was reached at 10:58 p.m.
At that time, TS 3.4.11 no longer applied; instead the Overpressure Protection System (OPPS) was required to be operable (TS 3.4.9.3).
The OPPS requirement was for both PORVs to be operable. With only one PORV operable, restoration of the out of service PORV was required within 7 days or the RCS had to be vented within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
The licensee's schedule involved depressurizing well within the allowed time period, so no problem was anticipated in complying with the TS requirement.
Unit 2 reached Mode 5 at 2:21 p.m. on March 19. The operable PORV (2RCS-PCV-456) was stroke tested as required (TS 4.4.9.3.1.d) at 4:50 p.m., but the valve failed the test in that full open indication was not received.
RCS pressure drop was observed, however, so some valve stroke occurred.
The PORV was declared inoperable because the test acceptance criteria con-tained a two second maximum stroke time which could not be confirmed. At this time, no PORVs were formally operable, although 2RCS-PCV-456 remained available.
_ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _
____ - - ____________ _ _ ____- -_ _ _ _ _-_
_ _ _ _ - _ _ _ _ _ _ _
.
p,
.
,
,
-
-
With no operable PORV, the RCS is required to be vented to atmosphere within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> (TS 3.4.9.3.b).
Operators attempted to stroke the other OPPS PORV (2RCS-PCV-455C) with no success, possibly due to RCS pressure being too low to stroke the pilot-operated valve. Technicians also tried to correct the PORV indication, also with no success.
The pressurizer vapor space was still hot (about 300 F) and not fully purged of hydrogen, The RCS could not, therefore, be vented until the pressurizer was purged i
l and further cooled.
The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> TS Action Statement period was exceeded
'
and the appropriate ENS notification was made at 4:51 a.m.
on March 20.
f The licensee experienced difficulties with the polar crane (needed for the removal of a safety valve for venting), the nitrogen equipment (needed for PORV testing), and PORV position equipment. Continued efforts to success-I fully test a PORV were unsuccessful and one valve (2RCS-PCV 456) appeared not to fully reseat immediately as evidenced by continued pressure rise in the pressurizer relief tank (PRT). Operators closed the PORV block in an attempt to stop PRT pressure rise.
The PORV's remained blocked for about 90 minutes until one was reopened following questioning by the inspector.
The RCS vent was established at 1:30 p.m. on March 21, 1989.
During the period that the unit had no formally operable OPPS, several administrative and design features were in place which mitigated the potential significance of an event.
According to procedure, all pumps capable of injecting into the RCS were out of service and could not start with the exception of one charging pump in normal use.
Potential flow-paths were defeated by administrative controls and de-energization of the valves in the closed position.
The residual heat removal system (RHS)
which was in use during the period contained two operable relief valves (2RHS-RV 721A and B).
One RHS train was in service during the cooldown and the other train was unisolated at 12:37 a.m. on March 19. Also, one PORV (2 RCS-PCV 456) was verified to stroke and relieve pressure and was available during the period (except for the 90 minute interval noted above).
Unit 2 status and the licensee's progress toward resolving the problem was discussed frequently with licensee and NRC management. The need for docu-mentation and its formal review by licensee management and appropriate committees during the period was also discussed.
The licensee already uses a Justification for Continued Operation (JCO) document in certain
,
cases during operation. The inspector discussed the appropriateness of a similar document in instances where a unit is shutdown but in a condition not clearly covered by the unit's Technical Specifications.
No additional concerns were identified.
.
-w m
____m
_ _ _ _ _ _ _ _ _. _-.
.
.
'* '
'
l l
9.
Unit 1 Safeguards Building Ventilation The Supplementary Leak Collection and Release (SLCR) system is designed to remove the heat from various safety related loads in the Unit 1 Safeguards Building during a loss of offsite power. When building temperatures reach a predetermined setpoint, dampers open to pull cooler outside air through the room to lower building temperature.
The dampers close when a pre-determined low temperature is reached.
The major heat loads in the Safe-guards Building include the following:
two electric driven Auxiliary Feedwater pumps; one steam driven Auxiliary Feedwater pump; two Quench Spray pumps; two Safety Injection pumps; and two Recirculation Spray pumps. During a hypothetical Safety Injection, coincident with a loss of offsite power, all of the above components should start.
Other events automatically start the Auxiliary Feedwater pumps.
The inspector reviewed the design and environmental qualification (EQ)
calculations for Safeguards Building ventilation during a loss of offsite power.
Both calculations appeared to assume that not all of the heat loads discussed above operate. The design calculation considered that one half of the components operate (and does not include steam driven Auxiliary Feedwater pump). The EQ calculation considered only one half of the components operate along with the second electric driven Auxiliary Feed pump (steam driven pump not considered).
The EQ maximum allowed temperature is 120 F.
The SLCR system design does not appear to open the dampers to cool the building until 130 F.
The licensee is evaluating the adequacy of the SLCR system to remove the heat in the Safeguards Building if all the major hert loads are operating.
This issue is unresolved pending the further evaluation by the licensee (50-334/89-04-02).
10.
In-Of fice Review of Licensee Event Reports (LERs)
The inspector reviewed LERs submitted to the NRC Region I Office to verify that the details of the event were clearly reported, including accuracy of the description of cause and adequacy of corrective action. The inspector determined whether further information was required from the licensee, whether generic implications were indicated and whether the event war-ranted onsite followup. The following LERs were reviewed:
,
Unit 1:
LER: 89-01-01 Reactor Trip Due to personnel Error
- _ _ _
- _ _ _ _ _ _ - _ _ - _ _ _ _ _ _ _ _ _ _ - - _ _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ - _ _ _
_
-
_
_ _ -. ___
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
-
c
-
.
i l
l
,.. *
Unit 2:
}
LER: 89-01-00 Inadvertent Letdown Isolation (ESF Actuation)
LER: 89-02-00 Inadvertent Control Room Pressurization (CREBAPS) Actuation
[
No significant deficiencies were identified.
11.
Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations or deviations.
Unresolved items are discussed in Sections 4.6 and 9.
12. Meetings Periodic meetings were held with senior facility management during the course of this inspection to discuss the inspection scope and findings. A summary of inspection findings was further discussed with the licensee at the conclusion of the report period on April 13, 1989.
>
_ _ _ - _ _ _ _ _ _ _ _ _ _ _ -.
._ _
_
_
J