ML20234D436
| ML20234D436 | |
| Person / Time | |
|---|---|
| Site: | Vogtle  |
| Issue date: | 06/29/1987 |
| From: | Rogge J, Schepens R, Sinkule M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20234D407 | List: |
| References | |
| 50-424-87-37, 50-425-87-27, NUDOCS 8707070207 | |
| Download: ML20234D436 (18) | |
See also: IR 05000424/1987037
Text
UNITED STATES '-
(An Mooq
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NUCLEAR REGULATORY COMMISSION _
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8%-
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REGION 11
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101 MARIETTA STREET,N.W.
$fg
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ATLANTA. GEOriGI A 30323
s. v /
.....
Report Nos.:
50-424/87-37 and 50-425/87-27
Licensee: Georgia Power Company
P.O. Box 4545
Atlanta, GA 30302
Docket Nos.:
50-424 and 50-425
License Nos.: NPF-68 and CPPR-109-
Facility Name:
Vogtle 1 and 2
Inspection Conducted:
May 23 - June 19, 1987
Inspectors:
$
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b . F. Rogge, Senior Resident Inspector,
Date Signed
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Operations
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R. J.~ 5thepens, Resident Inspector, Operations
Date Signed
Accompanying Personnel:
C.W. Burger
Approved by:
'N
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h %7 77
M. V. Sinkule, Section chief ~
Date Signed
Division of Reactor Projects
SUMMARY.
Scope:
This routine, unannounced inspection entailed Resident Inspection in
the following areas: plant operations, radiological controls, maintenance,
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surveillance, fire protection, emergency preparedness, security, outage-
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activities, startup' test program, preoperational test program, quality p,rograms
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and administrative controls affecting quality, and follow-up. on previous
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inspection identified items.
Results:
Three violations were identified in the area of Operations (Failure
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to Place the Unit in Hot Standby, Failure to Follow Procedures with Three
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Examples, and Failure to Follow the Diesel Generator Action Statement).
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B707070207 870629
ADOCK0500g4
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DETAILS
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1.
Persons Contacted
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Licensee Employees
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- G. Bockhold, Jr. , General Manager Nuclear Operations
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E. M. Dannemiller, Technical Assistant to General Manager
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T. V. Greene, Plant Manager
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R. M. Bellamy, Plant Support Manager
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C. W. Hayes, Vogtle Quality Assurance Manager
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E. Belflower, Quality Assurance Site Manager - Operations
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E. D. Groover, Quality Assurance Site Manager - Construction
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G. A. McCarley, Project Compliance Coordinator
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W. C. Gabbard, Regulatory Specialist
C. F. Meyer, Operations Superintendent
R. M. Odom, Plant Engineering Supervisor
M. A. Griffis, Maintenance Superintendent
G. R. Frederick, Quality Assurance Engineer / Support Supervisor
R. E. Spinnatu, ISEG Supervisor
J. F. D Amico, Nuclear Safety & Compliance Manager
- W. F. Kitchens, Manager Operations
- V. J. Agro, Superintendent Administration
A. L. Mosbaugh, Assistant Plant Support Manager
M. P. Craven, Nuclear Security Manager
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J. E. Swartzwelder, Deputy Manager - Operations
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M. J. Rowe, Operations Superintendent
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H. M. Handfinger, Asst. Plant Support Manager
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- W. E. Burns,' Nuclear Licensir.g Manager
Other licensee employees contacted included craf tsmen, technicians,
supervision, engineers, operations, maintenance, chemistry, inspectors,
and office personnel.
- Attended Exit Interview
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2.
Exit Interviews - Units 1 & 2 (30703)
The inspection scope and findings were summarized on June 19, 1987, with
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those persons indicated in parag,raph 1 above.
The inspector described the
areas inspected and discussed .in detail the inspection results.
No .
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dissenting comments were received from the licensee.
The licensee did not-
identify as proprietary any of the materials provided to or reviewed by
the inspector during this inspection.
Region based NRC exit interviews
were attended during the inspection period by a resident inspector.
The items identified during this inspection are:
a.
Violation 50-424/87-37-01 " Failure to Place the Unit in Hot Standby
Within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> per Action 10 of Technical Specification 3.3.1" -
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Paragraph - 5.A
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b.
Violation 50-424/87-37-02 " Failure to Follow Procedures - Three
Examples (Crud Tank Alignment, Emergency Ventilation, and Rod
Manipulation)" - Paragraphs - 6 and 8.
c.
Violation 50-424/87-37-03 " Failure to Follow Technical Specification 3.8.1.1 Acticn b Regarding the Activities Which Render the Diesel
Inoperable" - Paragraph 5.C.(6),
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d.
Unresolved 50-424/87-37-04 " Review the Licensee's Determination of -
Technical Specification Surveillance Compliance and - Deportability
Regarding the Contro' Room Emergency Ventilation" - Paragraph 4
3.
Licensee Action on Previous Enforcement Matters - Units 1 & 2 (92702)
Not inspected.
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4.
Unresolved Items - Unit 1 (92701)
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Unresolved items are matters about which more information is required to
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determine whether they are acceptable or may involve violations or
deviations.
One unresolved item identified during this inspection is
discussed in Paragraph 5.C.(5).
5.
Operational Safety Verification - Unit 1 (71707)
The plant began this inspection period in Hot Standby (Mode 3) preparing
for reactor restart following completion of the management hold points
regarding the contamination of the demineralized water header problem.
On
May 24 the plant returned to Power Operatien (Mode 1) and experienced a
reactor trip from 7% power while transferring, to bypass control.
The unit
again returned to Mode 1 on May 24 and remained in Mode 1 until June 3.
On June 3 the unit experienced a lightening strike which resulted in a
reactor trip from a turbine trip at 100% power. _The unit conducted a
Natural Circulation demonstration shortly following the trip.
From June 4
through June 6 a short outage was conducted.
On June 6 the unit was in
Startup (Mode 2) when a premature criticality occurred and the unit
experienced a reactcr trip from the Source Range Hi-Flux signal.
On
June 7 the unit returned to Mode 1 and experienced a reactor trip from 9%
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power on #4 Lo Lo Steam Generator following a main feedwater isolation
which occurred at 18% power.
Later on June 7.the unit was in Mode'2 at 4%
power and experienced a loss of feedwater due to a faulty check valve on
the A main feedwater pump which resulted in a reacter trip on lo Lo Steam-
Generator level
From June 7 through June 12 the unit remained in Mode 3-
for an' outage.
On June 12 while in Mode 2 the unit stopped the reactor
startup and returned to Mode 3 as a result of an incorrect estimated
critical condition.
On June 13 the unit successfully achieved Mode 1 and
began a power accent to 100%.
On June 14 while at 98% power the unit
experienced a loss of the A main feedwater pump, and a reactor tria on Lo
Lo Steam Generator level.
From June 14 to the end of.the period tie unit
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was conducting an outage to repair the A-main feedwater pump and the B
main feedwater pump discharge valve.
During the inspection period two
ESFAS actuations occurred, both being main feedwater isolations on Hi Hi
Steam Generator level.
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a.
Control Room Activities
Control Room tours and observations were performed to verify that
facility operations.were being safely conducted within regulatory
requirements.
These inspections consisted of one or more of the
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following attributes as app'ropriate at the time of the inspection,
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Proper Control P,com staffing
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Control Room access and operator behavior
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Adherence to approved procedures for activities in progress-
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Adherence to Technical Specification (TS) Limiting Conditions
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for Operations (LC0)
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Observance of instruments and recorder traces of safety'related
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and important to safety systems for abnormalities
Review of annunciators alarmed and action in progress to correct
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Control Board walkdowns
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Safety parameter display and the plant safety monitoring system
operability status
Discussions and interviews with the On-Shift Operations
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Supervisor, Shift Supervisor, Reactor Operators, and the Shift
Technical Advisor to determine the plant status, plans and-
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assess operator knowledge
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Review of the operator logs, unit log and shift turnover sheets
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On June 2,1987, during the performance of OSP-14701, Reactor Trip
Breakers UV and . Shunt Trip Test, the licensee identified that the
Auto Shunt Trip Block pushbutton did not return and declared that the
shunt trip feature was inoperable on Reactor Trip Breaker "B".
The
Shift Supervisor (SS) directed the surveillance be stopped and
restored the "B" reactor trip breaker to service and opened the "B"
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train bypass breaker.
The SS . then initiated' MWO 1-87-06G72 to have
the feature repaired.
At 1:14 p.m. EST on June 2,1987, the B bypass
breaker was racked in and closed to allow maintenance per MWO
1-87-06672.
At this time the NRC resident questioned the SS as to
how long the plant was allowed to remain in this configuration and
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was informed that the Technical Specifications only allowed bypassing
the reactor trip breakers for two hours.
Maintenance Personnel
removed the faulty pushbutton, but having no in-hand spare informed
the SS of the status, and went to obtain a new part.
At 9:40 p.m.
EST the "B" bypass breaker was opened and subsequently racked out.
Surveillance Procedure GSP 14701-1 commenced at 10:14 p.m..
EST and
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was completed as satisfactory at 11:00 p.m.
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On June 3,1987, the inspector was reviewing the Unit 1 Control'Lo
which reflected the above information and identified that the "B"g
bypass breaker had rendered the "B" reactor trip breaker inoperable
for a period of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and 34 minutes.
The inspector informed the
Manager-0perations and Operations Superintendent of this finding and
discussed the circumstances in a -subsequent meeting.
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The Technical Specification 3.3.1 requires that the minimum reactor
trip instrumentation channels shall be operable per Table 3.3-1.
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Table 3.3-1 Functional Unit Number 19 " Reactor Trip Breakers"
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requires 2 minimum channels operable in Modes 1, 2 or Action
Statements 10, 13 apply.
Action 10 states:
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With the number of OPERABLE channels one less than the Minimum
Channels OPERABLE requirement, be in at least HOT STANDBY within
6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />; however, one channel may be bypassed for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />
for surveillance testing per Specification 4.3.1.1, provided the
other channel is OPERABLE.
Action 13 states:
With one of the diverse trip features (undervoltage or shunt
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trip attachment) inoperable restore it to OPERABLE status within
48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or declare the brerker inoperable and apply ACTION 10.
The breaker shall not be bypassed while one of the diverse trip
features is inoperable except for the time required for
performing maintenance to restore the breaker to .0PERABLE
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status.
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During the above event the Shift Supervisor (SS) determined that
Action Statement 13 was applicable and determined that the plant
could continue to operate for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> and did not declare the
breaker inoperable.
When maintenance did not quickly repair the
breaker the SS then determined that the second sentence of Action 13
allowed the breaker to be bypassed for maintenance which could go for
as long as 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
The inspector informed the licensee, after consultation with the
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Office of Reactor Regulation, that the SS had misread the action
statement.
Action 13 allows the plant to continue with one of the
diverse trip features inoperable for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> but not both features.
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Both features became inoperable when the "B" bypass breaker was
closed.
At this point, it should have been realized that the reactor trip
breaker channel was inoperable and the breaker declared inoperable.
In doing this, it would have been realized that Action 10 would have-
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to be applied, and that the breaker may. only be bypassed for
maintenance while restoring the breaker to OPERABLE status.
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Generic Letter 85-09 issued on May 23, 1985, provides a discussion on
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the considerations behind Action B and other Technical Specifications
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regarding the reactor trip breakers.
Based on the above, the inspector determined that noncompliance with
a technical specification existed when the requirements of the
Limiting Condition for Operation and Associated Action requirements
were not met within the specified time intervals.
This is identified
as Violation 50-424/87-37-01 " Failure to Place the' Unit in Hot
Standby Within 6 Hours as re
Technical Specification 3.3.1" quired by Action Statement 10 of
and is being evaluated for possible
escalated enforcement action.
b.
Facility Activities
Facility tours and observations were performed to assess the
effectiveness of the administrative controls established by direct -
observation of plant activities, interviews and discussions with
licensee personnel, independent verification of safety systems status
and LC0's, licensee meetings and facility records.
During these
inspections the following objectives are achieved:
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(1) Safety System Status (71710)
Confirmation of system
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operability was obtained by verification. that flowpath valve
alignment, control and power supply alignments, component
conditions, and support systems for the accessible portions of
the ESF trains were
proper.
The inaccessible aortionsJare
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confirmed as availability permits.
Additional
indepth
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inspection of the Train A Component Cooling Water system was
performed to review the system lineup procedure with the plant
drawings and as-built configurations, compare valve remote and
local indications, walkdowns were expanded to _ include hangers
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and supports, and electrical equipment interiors.
The inspector
verified that the lineup was in accordance with license -
requirements for system operability.
(2) Plant Housekee)ing Conditions -
Storage of material and
components anc
cleanliness conditions of various areas-
throughout the facility were observed to determir,e whether
safety and/or fire hazards existed.
(3) Fire Protection - Fire protection activities, staffing and-
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equipment were observed to verify that fire brigade staffing was.
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appropriate ' and that fire alarms, extinguishing equipment,
actuating controis,
fire fighting equipment,-emergency-
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equipment, and fire barriers were operable.
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(4) Radiation Protection (71709) - Radiation protection activities,
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staffing and equipment were observed to verify. proper program
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implementation.
The inspection included review of the plant
program effectiveness.
Radiation work permits and personnel
compliance were reviewed durin
the daily plant tours.
Radiation Control Areas (RCA's) gwere observed to verify proper
identification and implementation.
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(5) Security (71881) - Security controls were observed to verify
that security barriers were intact, (guard forces were on duty,
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and access to the Protected Area
PA) was controlled in
accordance with the facility security plan.
Personnel within
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the PA were observed to verify proper display of badges and that
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personnel requiring escort were- properly escorted.
Personnel
within vital areas were observed to ensure proper authorization
for the area.
Equipment operability of proper compensatory activities were
verified on a periodic basis.
(6) Surveillance (61726)(61700) - Surveillance tests were observed
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to verify that approved procedures were being used; qualified
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personnel were conducting the tests; tests were adequate to
verify equipment operability; calibrated equipment was utilized;
and TS requirements were followed.-
The inspectors observed
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portions of the following surveillance
and reviewed completed
data against acceptance criteria:
Surv. No.
Department
Title
14005-101
Operations
Shutdown Margin Calculation
14235-101
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On-Site Power Distribution
Operability Verification
14905-101
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Leakage
Calculation
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(Inventory Balance)
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14940-101
Estimated Critical Condition
Calculation
14553-101
Train A ESF Room Cooler and
"
Safety Related Chiller Flow
Path Verification
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14806-101
Train A ' Containment Spray
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Pump
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Inservice Test
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14802-105
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Train B Nuclear Service Water
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Pump No. 4 and Discharge
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Check Valve Inservice Test
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24812-102
Delta
T/Tavg
Loop
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Protection Channel III T-431
Analog Channel Operational
Test and Channel Calibration
(7) Maintenance Activities (62703) - The inspector observed
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maintenance activities'to verify that correct equipment
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clearances were in effect; work requests and fire' prevention
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work permits, as required, were issued and being followed;
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quality control personnel were available for inspection
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activities as required; retesting and return of systems to
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service was prompt and correct; TS requirements were being
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followed.
Maintenance backlog was reviewed
Maintenance was
observed and work packages were reviewed for the following
maintenance activities:
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MWO No.
Department
Description
1-87-04250
Replace / calibrate
essential chill water
system flow transmitter
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1 FT-22426
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1-87-06175
Reheater
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steam
temperature investigate
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rework / recalibrates loop
1T1-6048 channel check
indicates
out
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calibration
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1-87-05959
Elect / Mech.
"B" main feed
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feed
pump discharge
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isolation valve repe r
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1-87-06804
Mech
"A"
mainfeed
pump
discharge check valve
inspection / repair
1-87-06877
Mech
"A"
mainfeed
pump, isolation valve
repair
(8) Startup Test Program - The inspector witnessed the Natural
Circulation Demonstration Testing following the trip from 100%
power.
The inspector noted the presence of operator trainees in
the Control Room for the testing to satisfy . TMI I.G.1
requirements.
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(9) Inspector Concerns - During th,e period the inspector raised two
concerns regarding (1) pressurizer level reference legs and (2)
DC Power Buss Grounds,
The inspector requested assurance that
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all three reference legs were operable when the failure of one
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pressurizer -level instrument had been attributed to the
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condensing pot not filling the reference leg, since the design
was similar for the other reference legs.
The site and
Westinghouse made the appropriate ' level of response to address
the concern.
The second concern addressed .the operation of the
plant for extended periods without removing the electrical
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grounds.
This inspector felt that this condition coulo in time
put the plant into a transient from an unwanted loss of a DC
buss.
Site Engineering discussed the issue and is examining an-
improved methodology for ground clearing.
These above items are
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good examples of licensee responsiveness to NRC concerns.
c.
Sustained Control Room and Plant Observation (71715)
This inspection was performed to evaluate the licensee's control room
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and plant performance over a sustained period.
Commencing on June 14
at noon the inspectors performed the evaluation for the next 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />
on a shiftwork basis.
This observation period covered four of the
five operating crews.
While the routine inspection activities
presented in paragraphs A and B above were also performed more
frequently the inspection gave particular attention to the following
areas:
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Operators were attentive and responsive to plant parameters and
conditions.
Plant evolutions and testing were' planned and properly
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authorized.
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Procedures were used and followed as required by plant policy.
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Equipment status changes were appropriately documented and
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communicated to appropriate shift personnel.
The operating conditions of plant equipment were effectively
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monitored, and appropriate corrective action initiated when
required.
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Backup instrumentation, measurements, and readings were used as
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appropriate when normal instrumentation was found to be
defective or out of tolerance.
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Logkeeping was timely, accurate, and adequately reflects' plant
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activities and status.
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Operators were following good operating practices in conducting
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plant operations.
The . plant was in Mode 1 (Power Operation) increasing ' power level-
toward 100% at the commencement of the inspection.
At 6:25 p.m. EST
the unit experienced a feedwater transient which- resulted in a
reactor trip on #4 to Lo Steam Generator Level.
The unit remained in
Mode 3 (Hot Standby) for the remainder of the observation period in
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order to effect repairs. to the
"A" main feed pump.
The following
observations were made:
(1) On June 14 at approximately 6:24 p.m. the operators received a
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Steam Flow / Feed Flow Mismatch alarm.
The initial review of the
control board alarms did not-identify an immediate indication of
the problem.
The operator then quickly identified that the "A"
Main Feed Pump had lost speed and discharge pressure and
appeared to be returning.
The operator did not. attempt manual
control of the pump because the' demand signal was at 100%.
Both
operators then began to reduce turbine load and. reactor power
within the capacity of a single feed pump, t and the reactor
however the #4 Steam
Generator level reached the Lo Lo Setpoin
tripped.
The subsequent actions in accordance with the
Emergency Operating Procedures were performed smartly.
The
inspector was at the control panel and was impressed with the
operator's actions.
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(2) On June 14 while the plant was at 75% power repeated alarming
was generated from the spurious actuation of the #3 reactor
coolant pump under voltage bistables.
Instrument and Control
personnel responded but the actuations had ceased.
The shift
noted to I&C that a previous MWO had been written a month
earlier.
Subsequently re)eated alarming occurred and I&C was
able to witness the flasiing.
The communicator: cards were
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pulled to alleviate the nuisance.
From discussions with the
shift the in,pector learned that approximately eighty alarm
indicators or recorders were not working properly.
The
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ins 3ector was aware that management had a program to reduce the
num3er but had thought that progress had been achieved to reach
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the thirty level.
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(3) Surveillance Procedure 14000-1 " Operations Shift and Daily
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Surveillance Logs" contains the logs to demonstrated com)liance
with the less than 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> periodicity surveillance.
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the review on June 15 the inspector questioned why the Mode 1 &
2 surveillance forms had been filled in as well as the Mode 3 &
4 logs.
The inspector was informed that this was a prerequisite
for entry into Mode il & 2 and was performed to satisfy that
requirement.
The inspector discussed with- the operator that-
some of the entries did not demonstrate compliance (e.g. Group
Counter logged at 228 steps with the' rod position at 0 did .not
satisfy the requirement to be within 12 steps).
The operator
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stated that he was aware of this.
Upon further review of the
Mode 3 data the inspector noted that one surveillance requiring
that the required reacter coolant loops be verified in operation
had not been properly executed.
This item was corrected by the
operator.
These observations were communicated to the
Operations management including a need to
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Clarify whether initials or the parameter value should be
recorded.
Currently both are acceptable.
Addition of completion time. - This information is currently.
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logged in another log.
(4) Surveillance Procedure 14400-1 " Control
Room Emergency
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Ventilation Actuation Logic Test" contains the directions to
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satisfy the Actuation Logic Test required by Technical
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Specification Surveillance 4.3.2.1 (Table 4.3.2,
Item 10b).
During the performance of the procedure on June 15 the op'erator
and the shift supervisor both failed to follow 00054-C Rules
for Performing Procedures" regarding step 4.1.5 which states:
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"If finding the procedure to be incorrect, stopping and
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notifying,'Revisinghis/her immediate supervisor" and ste,p 4.1.7 whic
states:
procedures in accordance with 00051-C .
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" Procedure Review and Approval" or 00052-C "Temporar
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when found to be incorrect prior to resuming work." y Changes",
During the
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performance of the surveillance procedure both trains were
actuated, however the procedure does not address the restoration
of the second train.
The procedure was set up to be completed
on either train on a staggered test basis and does not address
the fact that both trains will actuate.
In restoring the second
train the operator utilized the train similarity to manipulate
the restoration but did not stop work and inform his supervisor
per step 4.1.5.
At another point in the
monitors did not reset per the procedure. procedure the radiation
The operator stopped.
per step 4.1.5, however the supervisor gave verbal. directions to
complete the surveillance and did not perform step 4.1.7
regarding the processing a TCP per Procedure 00052-C.
Following
the completion of the surveillance these observations were
provided to the On-Shift Operations Supervisor who ensured that
the proper procedure revisions were made.
This item is
identified as one of the three examples of Violation
50-424/87-30-02 " Failure to Follow Procedures - Emergency
Ventilation".
(5) The inspector reviewed past copies of 14000-1 and 14400-1 to
review the manner in which past surveillance was conducted.
The
inspector _ determined that the observations regarding 14000-1
were substantiated regarding the logging 'of parameters versus
initials.
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In the review of past 14400-1 performance the inspector noted
that on March 7,
1987, both trains had been performed
satisfactorily with notes that the Radiation Monitors were not
available and would be performed later.
The surveillance
tracking system took full credit for these surveillance
and
rescheduled the surveillance at the next periodicity.
Train A
was performed on April 7, 1987 and Train B on May-23, 1987.
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licensee was asked to review these surveillance for adequacy to
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determine if they were in compliance.
In addition the licensee
has examined the June 13 surveillance and determined the
surveillance to be unsatisfactory because rad monitor RE-12:17
was not utilized.
Subsequent discussions with the licensee have
broadened the issue to determine if a failure to report an
inadvertent actuation due to the procedure inadequacy.
It
should be noted that the April 7,
May 23 ' and June 13
performances all utilized the same procedure revision and only
the June 13 performance has resulted in identification of
problems.
Since performance of each procedure actuates'an additional train
than expected the licensee was asked to review the deportability
aspects.
This item is identified as an Unresolved Item 50-424/87-31-04
" Review the Licensee's Determination of Technical Specification
Surveillance Compliance and Deportability Regarding the Control
Room Emergency Ventilation".
(6) Surveillance Procedure 14980-1 " Diesel Generator Operability
Test" and Operating Procedure 13145-1 " Diesel Generators".
On
June 15 the inspector observed the performance of the above
procedures on the A diesel.
The inspector noted:that OP 13145-1
required the diesel to be placed in an inoperable condition
while moisture checks, air rolling and prelubeing'was performed.
From discussion with the Shift Supervisor the inspector. learned
that the A train diesel was being demonstrated operable because
the B train diesel had become inoperable for a five minute
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period earlier and Action b. of Technical Specification 3.8.1.1
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requires the test even though the B diesel has been restored.
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The inspector reviewed the Technical Specification and
identified to the Shift Supervisor'that the action statement
also stetes:
"The diesel shall not be rendered inoperable by
activities performed to support testing pursuant to the Action
Statement (e.g., an air roll)."
The On-Shift ~ 0perations
Supervisor stated that these words are to clarify that the
diesel does not have to be declared inoperable while these tests
are being done.
The inspector noted that if this was the
situation the note should be part of the Surveillance not the
Action Statement.
The inspector reviewed the wording with NRR
and was informed that the licenree had violated the Technical
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Specification and License Condition #4 of Attachment 1.
The
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note in the action statement is intended to reinforce the
license condition.
Given the situation where the first diesel
had been returned to an operable status the significance af the
licensee actions were equal to that of performing a -routine
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surveillance, however the action statement strictly prohibits
{
the rendering of the diesel inoperable while doing the
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surveillance pursuant to the action statement.
Based upon the above, this 'is identified as Violation
50-424/87-37-03 " Failure to Comply with Technical Specification 3.8.1.1 Action b. Regarding the Performance of Activities Which
Render the Diesel Inoperable" and 'is being evaluated for
possible escalated enforcement action.
4
(7) During the four different shifts the inspectors noted that
morale has been lowered due to the recent series of events.
Operators felt that an overwhelming level of - management
oversight and pressure was being placed on them and that in
general management did not trust them to correctly operate the
plant.
The inspectors believe that during the response to
events the operators can demonstrate their skills very well (see
,
paragraph 5.c.(1)), however on the day-to-day activities of
Technical Specification and procedure compliance that -the
opportunity for improvement exists (see paragraph 5.c.(2) thru
5.c.(6), 5.a and 6).
6.
Onsite Followup of Event - Unit 1 & 2 (93702)
During the time frame of May 18 through 20, 1987 the crud tank was
overpressurized causing contamination of the demin water system and the
steam generator blowdown filter which subsequently lead to the flooding of
the turbine building.
The following is a sequence of events and the
inspector's review and conclusion.
(Note all time CST)
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May 18,1987.
At 9:30 AM the Rad Waste Operator was helping work the
number 4 seal injection filter drain flush valve.
The backflushable
filter system was out of service.
At 2:35 PM Operations placed the number-
4 seal injection filter in service.
At 5:15- PM the Rad Waste Operator
suspected that a high crud tank level existed although there is no level
indication available while pumpin,g the crud tank.
At 5:50 PM the waste
hold-up tank inleakage was approximately 25 gpm.
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May 19, 1987.
At 4:50 AM the Rad Waste Operator noted that approximately
25 gpm inleakage was occurring to the waste hold-up tank.
At 5:30 AM
Operations back' lushed the number 5 seal injection filter and noted a
problem with incomplete backflush dite to crud tank level.
At 10:00 AM a
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Rad Waste Operator was sent to find the source of the waste hold-up tank-
inleakage and found the crud tank vent filter drain valve 1-1224-U4-012
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open and flowing water to the waste hold-up tank.
The valve was then
closed.
At 11:20 AM the Shift Supervisor was : informed of valve
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1-1224-U4-012 status.
At 11:50 AM Chemistry reports that the result of
the waste hold-up -tank sample supports demin water as inleakage to the
waste hold-up tank via the crud tank valve 1-1224-04-012.
At 11:51 AM the
demin water to the crud tank isolation valve 1-1418-U4-071 was closed.
At
12:15 AM a high rad alarm was received on monitor RE-0018 while flushing
with demineralized water.
At 1:55 PM a hi rad alarm was received on
monitor RE-0076 during flushing with demineralized water confirming
contamination of the demin water system.
At approximately 2:00 PM the
licensee formulated the following plan of action:
Isolate makeup from Demineralized Water to all cooling water systems
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and Electric Steam Boiler Condensate Receiver Tank.
Ascertain extent of contamination by Chemistry sampling legs of the
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Demineralized Water Header.
Drain Crud Tank.
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Continue flushing RE-0018 and RE-0016 to the floor drains.
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Flush Demineralized Water Header back to the crud tank (source).
At 3:45 PM the crud tank was vented and drained to the floor drains.
At
5:35 PM the liquid waste system was almost filled to capacity, therefore
waste monitor tank 009 was released.
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May 20, 1987.
At 12:55 AM Chemistry notified the Control Room that the
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Turbine Building. oil waste separator was contaminated.
At 1:20 AM the oil
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waste separator was isolated and Chemistry was requested to sample the
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Auxiliary Building clean sump.
At 2:10 AM Chemistry reported high
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radiation in the Auxiliary Building clean sump.
pumps were shut down.
The excessive drainage to the Auxiliary Building
clean sump was drained to the Turbine Building drain tanks.
In time these
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drain tanks overflowed to the Turbine Building floor thereby flooding the
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Turbine Building with low level contaminated water.
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This event was closely monitored at the site by Resident Inspector and
Region Based Specialists.
.
On the morning of May 21, Site management took aggressive action to
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formulate a Recovery Team.
Corporate management supplemented this
activity.
Five functional groups were established as follows:
a.
Technical Team - Identify and correct all contributors to the event,
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identify root cause, and provide immediate corrective actions.
b.
Communication Team - Establish details of evdnt and properly
communicate them to offsite parties.
c.
Plant Control - Maintain plant conditions and work pr.iority.
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d.
Special Support - Provide craft personnel support.
e.
Corporate & Special Design - Review design basis of. plant. systems
with particular emphasis on clean system versus radioactive system
interface, and process any subsequent design changes.
During the recovery phase the team approach proved very effective in
resolving the design, water management and decontamination issues.
A detailed followup inspection was performed on this event to determine
the root cause.
The inspector reviewed the "Backflushable Filter System
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Alignment for Startup and Normal- Operation" Procedure No. 11213-1 Rev. 3
and determined that the demin water to backflush filter system isolation
valve 1-1418-U4-071 was required to be in the closed position.
If this
valve had been in the correct position the event would not have occurred.
The . inspector reviewed the "Backflushable Filter System" Procedure No.
13213-1 Rev. 2 and determined that the demin isolation. valve 1-1418-U4-071
is cycled when flushing the crud' tank with demin water.
The Rad Waste
Operating Log for the time' period of the event was reviewed and it was
noted that on May 18,1987, at 7:23 AM it took only 7 minutes to pump down
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the crud tank.
The log showeo that later on May 18 it took hours to pump
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down the crud tank and that an entry was made stating'that the control
room was called by the Rad Waste Operator notifying them of a large amount
of water in the crud tank.
The inspector interviewed the Rad Waste
Operators and Supervisors regarding valve 1-1418-U4-071.
It was
determined from the interviews that valve 1-1418-U4-071 had a red tagged
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clearance until sometime after 7:30 AM on May 18.
The inspector reviewed
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the clearance sheet (Procedure 00304-C) used for alignment of the
Backflushable Filter System on May 18. -The clearance sheet showed that
<
valve 1-1418-U4-071, the demin water to Backflush system isolation valve
was aligned to the open position upon removal of the clearance.
Further
inspection revealed that Operations had used the P&ID diagram te determine-
the restoration position of the valves on the clearance sheet instead of
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the alignment procedure for the system.
The P&ID showed valve
1-1418-U4-071 as open.
The inspector identified that the disagreement
between the alignment procedure and the P&ID existed because the
downstream valve which serves as a remotely operated valve had excessive
seat leakage (25 gpm) and as a short term solution the 1-1418-U4-071 valve
had been closed and the alignment procedure changed.
The following concerns were raised to management's attention.
A poor operating practice exists when during the performance of a
a.
surveillance procedure a red tag is encountered.
This red tag
changes the intent of the procedure and should require a major
procedure change in order to continue with the surveillance.
No
chenge. was pursued nor were any questions' raised when attempting to
perform a procedure on a system tagged for maintenance,
b.
When restoring a system the SS mur,t use the proper aides to determine
correct valve position.
The valve alignment; procedure .is the
established methodology, however the P&ID's ~ should reflect the
correct valve configuration.
Both' systems have pitfalls; valve
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alignment procedures may show a valve as open, but due to the fact
that a system was just worked on could lead to a sudden filling of
the system.
The P&ID's usually depict a system in normal operation.
In this event the normal operational positioi of the valve was not
reflected on the P&ID.
A third aide to the SS could be the recording
of the as-found condition prior to establishing the hnld tag (not
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currently required).
c.
When reports of problems are r&eived in the Control Room immediate
and prompt resolution by the 55 is mandatory.
Engineering and other
offshift personnel should be effectively utilized to ensure problem
4
resolution in a timely manner.
Based on the abcve. discussion, the licensee failed to implement
)
Procedure No. 11213-1 "Backflushable Filter System Alignment for
.Startup and Normal Operation" and is identified as one of three
,
examples of Violation 50-424/87-37-02 " Failure to Follow Procedures -
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Crud Tank Alignment".
Unresolved Item 50-424/87-31-03 " Complete Review of Crud Tank
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Overpressurization" is closed based on identification of the above-
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violation.
7.
Followup of Reportable Items - Units 1 & 2 (92700) (36100)
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This inspection was conducted to determine whether the items have been
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received by the licensee, evaluated and corrective action taken, where
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appropriate.
The inspector utilized discussions with cognizant personnel
review of applicable documentation, and for field verification as a basis,
for closure of each item.
(Closed) 50-424/425 P2186-03, "BBC Brown Boveri F600/F800 Circuit Breakers
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Wire Harness".
This item was previously addressed in- NRC Report
50-424/87-12 and 50-425/87-08.
The inspector reviewed the inspection
summary for these breakers and determined that no. reportable deficiencies
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were noted.
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(Closed) 50-424/425 P2186-06, "Transamerica Delaval, Inc. (TDI) Time Delay
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Relays".
This item was previously addressed in NRC Report 50-424/87-12
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and 50-425/87-08.
The inspector reviewed the Bechtel evaluation dated
April 23, 2987.
This evaluation determined that the relays are usea in
annunciator circuits only and have no affect on the ability of the diesel
to start or run.
(Closed) 50-424/425 P2186-07, " Insufficient Design Margin' in Brown Boveri
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Ground Detector Relays".
This item was previously. addressed'in NRC Report
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50-424/87-12 and 50-425/87-08.
The licensee has the relays correctly set.
(Closed) 50-424/425 P2187-01, " Inadequate Welding Qualification on the
Remote Shutdown Panels".
On April 13, 1987 Duane Arnold made a verbal
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report and on April 15, 1987 a written report (LER 87-008) describing the
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failure to have a qualified welding process at P;ank Electric.
The
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licensee review identified that the Vogtle remote shutdown panels were not
supplied by Frank Electric.
Vogtle was supplied panels by Johnson
Control, Inc. which utilized the Frank Electric panels in the Control
Building HVAC parzls, 1-500-V7-001-CBA and 1-500-V7 _002-CBB.
Licensee
discussions with the vendor indicate that the welding process has been
qualified and that these procedures were the same as utilized for Vogtle
and thus the panels are indeed satisfactory.
8.
Review of Licensee Event Reports - Unit 1 (90712)-
Licensee Event Reports (LERS)_ and Deficiency Cards (DC's) were reviewed
s
for potential generic impact, to detect trends, and to d9termine whether
corrective actions appeared appropriate.
Events which were reported
'
immediately were reviewed as they occurred to determine if the technical
specifications were satisfied.
The inspector conducted a review of the following reactor trip review
reports to verify proper determination of root cause, the proper
functioning of safety-related equipment, and the: licensees corrective
,
action both short and long term.
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Report No.
Date
Description
1-87-21
6/6/87
Rx trip on Hi flux source rang'e
1-87-22
6/7/87
Rx trip on SG Lo-Lo level
1-87-23
6/7/87
Rx trip on SG Lo-lo level
Reactor trip report no.1-87-21 documented a reactor trip which occurred
I
on June 6, 1987, where performing a reactor startup.
The operator who was
a licensee trainee under the direction of the licensed reactor operator
was performing a routine reactor startup.
The estimated critical rod
position (ECRP) was 45 steps on control bank
"D".
Rod
aulls were
conducted at 50 step intervals up to 71 steps on control
aank "C"
3er
unitoperatingprocedure(MOP) 12003-1 " Reactor 'Startup mode 3 to moce 2."
Subsequently, the reactor operator continued with the reactor startup by
withdrawing control rods to 101 steps on control bank "C" at which time a
reactor trip occurred on source range high flux due to a high startup rate
(2.2 decades per minutes).
Per UDP 12003-1 step 4.2.14 if criticality is projected to occur prior to
reaching 500 PCM below the ECRP height (1.e. ,105 steps on control bank
!
"C") then control bank withdrawal shall be stopped and control banks shall
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be inserted 500 PCM.
Contrary to this, on June 6,1%i, the U0P
No. 12003-1 was not properly 1mplemented in that the unit was taken
critical-with the actual rod height greater than 500 PCM below the ECRP
height and the control banks were not inserted as required.
,
The foregoing is considered to be in violation of Technical Specification 6.7.la and will be identified as another example of violation
50-424/87-37-02 " Failure to follow procedures".
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Additional underlying problems identified by the licensee in the reactor
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trip. review report were:
1) the operator did not recognize that the
i
reactor was critical at approximately 84 steps on control bank "C", 2)
operators were unaware of the high reactivity-worth of control rods in
this area, and 3) operations estimated critical condition (ECC) procedure
!
no. 14940-1- was inadequate.
The inadequate ECC procedure will be
!
addressed in inspection report no. 50-424/87-38.
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9.
Management Meeting - Unit 1(30702)
'The resident inspectors attended a management meeting in Region II with
the NRC staff and the licensee on June-11,1987, to discuss Vogtle's
!
recent operational experience.
The licensee reviewed the three (3)
reactor trips which occurred during the weekend on June 6, -1987. .The
licensee's presentation encompassed the plant conditions, description of
the event, root cause analysis, and corrective action for each of the
.
Furthermore, the licensee discussed additional reviews and
'
improvements which management was involving to strengthen the reactor trip
,
review process.
,
The resident inspector attended an NRC' Enforcement Conference on security
'
matters held with the licensee in Region II on June 17, 1987.
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