ML20198J041
| ML20198J041 | |
| Person / Time | |
|---|---|
| Site: | Rancho Seco |
| Issue date: | 05/14/1986 |
| From: | Albert W, Bosted C, Burdoin J, Eaton R, Gore B, Andrew Hon, Ivey K, Johnson G, Johnston G, Miller L, Myers C, Perez G, Phelan P, Royak M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML20198J013 | List: |
| References | |
| 50-312-86-07, 50-312-86-7, NUDOCS 8605300633 | |
| Download: ML20198J041 (54) | |
See also: IR 05000312/1986007
Text
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U. S. NUCLEAR REGULATORY COMMISSION
REGION V
Report No. 50-312/86-07
Docket. No. 50-312
License No. DPR-54
Licensee: Sacramento Municipal Utility District
P. O. Box 15830
Sacramento, California 95813
Facility Name: Rancho Seco Nuclear Generating Station
Inspection at: Herald, California
Inspection Conducte
Febr
2 - April 11, 1986
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Inspectors:
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Summa ry:
Inspection February 21 - April 11, 1986 (Report No. 50-312/86-07)
Areas Inspected:
Special inspection by eleven NRC inspectors (7 region, 3
resident, I headquarters), and one NRC contractor of the licensee's
preparations for restart of Rancho Seco following the December 26, 1986
cooldown transient.
This report summarizes the inspection activities which were conducted at
various times during the inspection period.
During this inspection, Inspection Procedures 93702, 62700, 62702, 62705,
37700, 72701, 93702, 25565, 41701, 61725, 90712, 92700, 94702 were followed.
Results: Of the areas inspected, which were identified by a list of 38
restart issues and the IIT report on the December 26, 1985 overcooling
transient (NUREG-1195) . One deviation was identified relating to electrical
shielding. Of the 38 restart issues, 20 were closed. Other enforcement
action related to this inspection will be the subject of separate
correspondence.
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Table of Contents
Page
1.
Persons Contacted
1
2.
Inspection of December 26, 1985 Overcooling Event
1
A.
Background
1
B.
Findings Relating to Inadequate Procedures
2
a.
Absence of ICS Failure Procedure
2
b.
Absence of Procedure for Properly Securing HPI System 2
c.
Absence of Procedure for Exercising Manual Valves
3
C.
Findings Relating to Implementation of Procedures
a.
Improper Valve Operations
3
b.
Failure to Follow Emergency Procedure E0P E.05,
" Excessive Heat Transfer"
4
c.
Procedure Implementation Problems with Radiation
Protection and Emergency Planning Procedures
4
D.
Findings Relating to Maintenance of Procedures
6
E.
Conclusion
6
3.
Inspection of Restart Issues
6
A.
Background
6
B.
Restart Issue Inspection
0-1
Steam Binding Within Auxiliary Feedwater System
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0-2
Prevention of Water in Main Steam Lines
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0-3
Procedures for Switching from AFW to MFW
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0-4 Event'Related Procedures - ATOGs
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0-7 Prcssutized Thermal Shock Guidance
10
0-9
Overcooling Training and Other Training
11
0-10 System Training
16
0-11 Incapacitated Operator
17
0-12 Emergency Procedure Training
17
0-13 Control Room /TSC Emergency Filtration System
18
0-14 Valve Training
21
0-15 Annunciator Response Procedures
22
E-1
Secondary Steam Lines
22
E-3 Root Cause Analysis
23
E-5 Trouble Shooting
23
E-7 Post Trip Report
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E-8 Main Steam Line Stress Analysis
25
E-9 Pressurizer Level
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E-10 Pressurizer Heaters
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E-11 Instrumentation Loss With ICS Loss-
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E-12 Main Feedwater (MFW) Block Valve
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E-13 Operator References for OTSG Level
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E-15 tRJ Pump Failure
30
E-16 MU Pump Procedures
31
E-17 MU Pump Schedule
31
E-18 LER on Overcooling
31
E-19 Core Lift
32
E-20 Closing Maintenance Valves
32
MA-1 Valve PM Program
33
MA-2 Electrical Terminations
34
MA-3 CRD Breakers
37
MA-4 Operability of Manual Valves
40
MA-5 Repairs to ICS and Valves
41
MA-6 Station 125V DC Batteries
41
MO-1 ADV, TBV Operation
45
MO-3 Control of ADV's, TBV's and AFW Flow
45
MO-6 Annunciator Change
47
MO-8 Minimum Flow to Pumps
48
4.
Management Meeting
50
5.
Status of Restart Issues
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1.
Persons Contacted
Numerous craft, operating and supervisory personnel were contacted during
the course of this inspection. The principal contacts were as follows:
G. Coward, Manager, Nuclear Plant Manager
- C. Stephenson, Compliance Engineer
- S. Crunk, Incident Analysis Supervisor
- S. Redeker, Manager Nuclear Operations
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J. McColligan, Assistant Manager, Nuclear Plant Manager
J. Jewett, Site QA Supervisor
R. Dieterich, Manager, Licensing
R. Colombo, Regulatory Compliance Supervisor
- H. Canter, Quality Assurance Surveillance Supervisor
N. Brock, I&C Maintenance Supervisor
M. Price, Mechanical Maintenance Supervisor
C. Linkhart, Electrical Maintenance Supervisor
- J. Field, Technical Support Superintendent
R. Daniels, Electrical Engineer Supervisor
- T. Tucker, Nuclear Operation Superintendent
- D. Army, Maintenance Superintendent
T. Hunter, Operator Training Coordinator
P. Turner, Training Manager
J. Irwin, I&C Engineer
R. White, Senior Electrical Engineer
T. Miller, Quality Assurance Consultant
J. Meyer, Quality Assurance Engineer
J. Wheeler, Senior Electrical Engineer
M. Basu, Principal Electrical Engineer
Q. Coleman, Quality Assurance Engineer
L. Roven, Quality Assurance Engineer
L. Conklin, Senior INC Design Engineer
W. Ford, Nuclear Operation Coordinator
J. Ambrose, Quality Engineering Specialist
- J. Mau, Training Superintendent
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B. Rausch, STA Supervisor
- Attended either April 4 or April 11, 1986 exit meeting.
2.
Inspection of December 26, 1985 Overcooling Event
A.
Background
On December 26, 1985 the Rancho Seco Plant experienced a loss of DC
power within the integrated control system (ICS) while the plant was
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operating at 76 percent power. Following the loss of ICS DC power,
the reactor tripped on high reactor coolant system (RCS) pressure
followed by a rapid overcooling transient and automatic initiation
of the safety features actuation system on low RCS pressure. The
overcooling transient continued until ICS DC power was restored, 26
minutes after the loss.
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Subsequent to the event the NRC sent an Incident Investigation Team
(IIT) to Rancho Seco. The details of the team's findings,
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description of the event, and conclusions are documented in
NUREG-1195 ' loss of Integrated Control System Power and Overcooling
Transient at Rancho Seco on December 26, 1985." This NRC report
contains a detailed explanation of the event.
In addition, a
,
special inspection was conducted by the Region V office of the
licensee's implementation of the licensee's emergency plan and the
radiological control program. The findings of the special
inspection were documented in Inspection Report 50-312/86-06.
B.
Findings Relating to Inadequate Procedures
The inspectors determined that the licensee had failed to establish
several procedures required by Technical Specification 6.8.1 and
Appendix A of Regulatory Guide 1.33, November 1972 edition. The
absence of the procedures directly contributed to the overcooling
event which occurred on December 26, 1985. The following items were
identified subsequent to the event by the inspectors as examples
where the licensee failed to establish required procedures.
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Section F.18 of Appendix A, Regulatory Guide 1.33 recommends
a.
written procedures for ccmbating emergencies and other
significant events including expected transients. On January
5, 1979 the licensee experienced a reactor trip which included
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the loss of ICS power. The trip was caused by a
short-to ground in the ICS, and resulted in an overcooling
event which exceeded the Technical Specification cooldown limit
of 100 F/ht. The plant response to the event on December 26,
1985 was similar to this earlier event.
Yet, despite the
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January 5, 1979 event, the licensee apparently did not modify
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the ICS or other plant systems, nor did the licensee develop a
loss of ICS procedure. The failure to develop a procedure for
the expected transient, namely loss of ICS DC power, is an
apparent violation,
b.
Section C of Appendix A, Regulatory Guide }.33, recommends
procedures for startup, operation, and shutdewn of safety
related PWR systems including instructions for changing modes
of operation. After the loss of ICS de power on December 26,
the reactor coolant system pressure decreased to 1600 psig and-
a safety features actuation occurred.
High pressure injectio'n
(HPI) loop valves opened, suction valves from the borated water
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storage tank (BWST) received an open signal (these valves had
been previously opened), the A HPI pump (P-238A) started (the
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makeup pump, P-236, and the B HPI pump, P-238B, were already
started), and the suction valve from the make up tank
(SFV-23508) closed.
During the subsequent recovery from the high pressure injection '
initiated by the safety features system, the suction valve from
the BWST (SFV-25003) was closed in error by a licensed
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operator, stopping flow to the A HPI pump and the makeup pump.
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The A HPI pump had already been secured by this time, but the
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makeup pump was operated without flow for about 25 minutes.
The pump was not secured until af ter the pump' had been severely
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damaged. As a consequence, primary coolant spilled onto the
makeup pump cubicle floor, and some minor amounts of
radioactivity was unnecessarily released to the atmosphere, and
ultimately, to the environment.
The failure to have a procedure to secure the high pressure
injection system properly and safely following its initiation
is an apparent violation.
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c.
Section 1.4.a of Appendix A, Regulatory Guide 1.33, recommends
written procedures for exercise of equipment which is normally
idle, but which must operate when required. During the event,
following unsuccessful attempts to close the A auxiliary
feedvater (AFW) flow control valve (FV-20527), a nonlicensed
operator was directed by the control room operators to close
the manual isolation valve (FWS-053) downstream of the A-AFW
flow control valve. This closure was ordered to mitigate the
severe cooldown in progress; however, the operator's efforts to
close the valve were unsuccessful, despite the use of a large
valve wrench, and the valve remained stuck in its normally open
position.
Subsequent to the event, the inspectors determined that no
written procedures existed for the exercise of auxiliary
feedwater system valve FWS-063, which was normally idle (not
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operated), to ensure its capability to operate when required.
This is an apparent violation.
C.
Findings Relating to Implementation of Procedures
During the event of December 26, 1985, the licensee also failed to
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implement several procedures, contributing to the overcooling event,
its radiological consequences, and the unnecessary damage of plant
equipment. The following are examples identifying failures to fully
implement procedures during the December 26, 1985 event.
During the event the Control Room Operator dispatched a
a.
nonlicensed operator to manually close the auxiliary feedwater
(AFW) flow control valves. The operator first attempted to
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close the B AFW flow control valve, FV-20528. After he had
assumed he had closed the valve, he proceeded to the A AFW flow
control valve, FV 20527. Subsequently, another operator
approached the B AFW flow control valve and found it not fully
closed. At that time the second operator closed the valve.
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The first operator attempted to close the A AFW flow control
valve.
In this attempt a valve wrench was used on the manual
handjack of the valve.
The operator failed to recognize that
he had already closed the valve, so when the valve wrench was
used to close the valve further, the manual' operating mechanism
was broken loose from the actuator.
Internal spring pressure
reopened the valve, and consequently, AFW flow was not secured
to the steam generators.
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Section.C of Appendix A, Regulatory Guide 1.33, recommends
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procedures for startup, operation, and shutdown of safety.
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related PliR systems including instructions for changing modes
of operation.
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The inspector determined that the licensee.had established some-
instructions for operating valves FV 20527 and FV 20528 in the
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case where the control. room was evacuated in procedure C.13A,.
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" Hot Shutdown from Shutdown Panel with a Fire in the Control
Room," Enclosure 4.6, " Operator No. 2 Supplementary Actions,"
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Step 4 and 5.
These instructions appeared applicable in.this
event, as well. They did.not contain appropriate precautions
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to prevent excessive leverage on the valve manual operators.
The improper. operation of valve FV 20527 in the manu.sl mode
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prolonged the' excessive cooldown during the event. This is an
apparent violation.
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b.
Section F. of Appendix A, Regulatory Guide 1.33, November 1972,
recommends procedures for' combating emergencies and other
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significant events. During the event.the operators used
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emergency procedure E'.05 " Excessive Heat Transfer". Step 3 of
procedure E.05 directed operators to isolate the once through
steam generators (OTSGs). With no ICS DC power available,
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operators were dispatched to the v.3 ves and. instructed to
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operate them manually to isolate the 0TSGs. The procedure
states in step 3.3, "if feed flow continuca, trip appropriate
feed pumps to terminate flow." The' operators did not isolate
feed flow toithe OTSGs before power to-the ICS was restored.
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The OTSG levels continued to increase, to 95' percent on the
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operating range. At this' time-E.05, step 3.1, directs the
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operators to stop the turbine-driven AFW pump and start the
motor-driven.AFW pump. However, this action.was not taken, and
both AFW pumps continued to pump water into the OTSGs. 'As a
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result, the OTSG levels continued to increase and water started-
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overflowing into the "A"' main steam lines.
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(Rule 3, "Feedwater Throttling Guidelines," to the emergency ^
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. procedures is even nore definitive-in this esent.
It gives the
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. operators explicit gVids.nce to stop AFW flow'during overcooling
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events. Rule 3 states,Qn part:
"If excessive primary to ' '
secondary heat transfergexists, then stop AFW flow-,to the. steam
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generator (s) being ove: cooled."
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This is an apparent violation.
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(The inspectors also noted that as a direct result of the
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fa,ilure to stop the AFW flow to'the OTSGs, Technicali, _
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Specification 3.1.2.2, which limits'the reactor coolant system
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cooldown rate to 100?F/hr, at temperatures greater than 270*F,
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was exceeded.)
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Other examples of the failure;to implement existing proce'ddres
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-during this event were previ.ously discussed in-Inspection
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Report 50-312/86-06. These;are summarized below:
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1.
Section F.27 of Appendix A, Regulatory Guide 1.33,
November 1972, recommends procedures for abnormal releases
of radioactivity.
Annunciator response alarm procedure H2PSA-7, Revision 14,
Window #12 requires in step #4, " Notify Rad / Chem or
Emergency Team to don respirators and make reentry into
area to obtain air sample and determine source of high
activity IAW (in accordance with) the Emergency Plan," and
in step #2 it requires personnel be evacuated from area
being monitored for high gas activity upon receipt of a
high alarm on actuating device R15002B (i.e., auxiliary
building stack monitor).
Procedure AP 305-28, Revision 1, dated May 25, 1985, "MPC
Determination at Site Boundary From Radioactive Releases,"
requires in paragraph 3.0 that a 10 CFR 50.72 evaluation
is required if an unplanned, uncontrolled or accidental
release occurs.
Paragraph 3.1.1 requires the evaluation be accomplished in
the following manner:
"a.
Sample the stack for noble gases, tritium,
particulate, and charcoal (iodine),
b.
As soon as possible, perform the evaluation based on
noble gases. Collect tritium, particulate, and
charcoal (icdine); sample for one hour.
c.
If the release changes, additional noble gas samples
will be required in order to average over one hour.
d.
Determine Concentration at Site Boundary."
Contrary to the above procedures, upon receipt of the auxiliary
building stack high gaseous activity alarm (R15002B) at
approximately 5:05 a.m.,
December 26, 1985, personnel were not
evacuated from the auxiliary building and a sample was not
taken from the auxiliary building stack for determining the
initial site boundary maximum permissibie concentration.
This is an apparent violation.
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2.
Rancho Seco Technical Specifications 6.8.1.e requires that
written procedures shall be established, implemented and
maintained covering the emergency plan implementation.
a)
Step 5.1.3 of Procedure AP 502, " Notification of
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Unusual Event," requir:es the Emergency Coordinator to
direct the emergency alarm be sounded for ten seconds
and announce or have announced, the appropriate
messages described in Step 5.1.3 over the public
address system whenever an actual event has cccurred.
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Contrary to the above, on December 26, 1985, the
Emergency Coordinator did not activate the siren and
make the announcement following declaration of a
notification of an Unusual Event.
b)
Step 5.1.4 of Procedure AP 506,
" Notification / Communication" requires the Emergency
Coordinator to complete a followup Notificatica Form
(Attachment 7.4) which requires that followup
information should be sent to the State and counties
at least hourly, during an emergency.
Contrary to the above, on December 26, *.985, followup
notifications after the declaration of an unusual
event were not made to the appropriate offsite
authorities (i.e., Amador, Joaquin, and Sacramento
counties).
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D.
Findings Relating to Maintenance of Procedures
Technical Specification 6.8.le requires, in part, that written
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procedures shall be maintained covering emergency plan
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implementation.
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Inspection Report 50-312/86-06 has previously detailed an area where
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the licensee's procedures were not maintained.
Attachment 7.2 Tab 4 of procedure AP 501, " Recognition and
Classification of Emergencies," Revision 4, dated August 23, 1985,
lists an Emergency Action Level for R15002B (Aux. Bldg. Stack Gas)
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alarm at 20,000 cpm.
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Contrary to the above, procedure AP 501 was not maintained in that
the Auxiliary Building Stack Monitor R15002B setpoint had been
changed to 60,000 cpm on July 21, 1984, and the setpoint as listed
in Attachment 7.2 Tab 4 had not been revised as of December 26,
1985.
E.
Conclusion
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The inspectors concluded from the review of the licensee's
performance that the variety and number of procedural violations and
omissions which occurred during this event, or which were revealed
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in the inspections which followed it, collectively indicated a
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serious breakdown in the management controls which should. establish
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and implement important procedures.
(86-07-01)
3.
Inspection of Restart Issues
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A.
Backrround
This is an interim report on the examinations conducted to date,
April 11, 1986, on a list of issues prepared by Region V.
This list
represented specific items which Region V considered important to
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resolve prior to recommending restart of Rancho Seco following the
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December 26, 1985 cooldown transient. Not all of the items on the
list of " restart issues" specifically address issues directly
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arising from that transient, nor is the list intended to
comprehensively list all the actions necessary for restart of the
plant.
The Region V restart list has been modified from time to time.
Among the modifications was the elimination of those items which are
to be exclusively resolved by NRR. Thus, the following paragraphs
. address the items on the list in numerical order but skip those
numbers which represent items to be resolved by NRR only. Also the
following material does not address issues relating to health
physics, emergency preparedness or security. These issues are
addressed in separate inspection reports issued by Region V.
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The detailed discussion of the various restart issues is in the
following report sections. These sections outline the status of the
issues at the close of this inspection period (April 11). Therefore
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this report represents an interim report on those issues which have
not been closed out.
Followup examination on most of these open
issues will follow appropriate licensee action.
The following items are classed as either "open" or " closed".
" Closed" means " closed as a restart issue".
The closure of an item
as a restart issue does not imply that it may not be reopened if
further questions arise or that NRC organizations other than Region
V may not have further questions. #.lco, the closure of an item as a
restart issue may be contingent on understandings reached with the
lickasce regarding aspects of the issue which remain open but are
not conditions for restart.
In the following listing each issue is addressed by the following
designators:
The Region'V restart list number
The licensee action list number
The item number from the memorandum of Mr. V. Stello to Mssrs.
Denton, Taylor and Martin titled " Staff Actions Resulting from
the Investigation of the December 26, 1985-Incident at Rancho
Seco," dated March 13, 1986, if that item was assigned to
Region V.
(EDO list)
The numbers are followed by a description of the expected licensee
action.
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B.
Reitart. Issue Inspection
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(closed)
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Deyelop proceduces fg _non Qoring ccndition's within the Auxiliarv
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Feedwater System (AFWS), for 'cecognizirg steam hinding,yd for
rest 6 ring the ARiS to ope _rability.
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. Conduct necestacy training.
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This item was taken froni IE Bulletin S5-01. Tbc NRC inspector
reviewed the licensee *s response dated 02/27/S6, AFW System
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Operating Procedure !i.51, and Surveillahce Procedure 200.01. The
NRC inspector found that the necessary proce. dure charigen have been
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ecmoleted and that these procedure changes provided for recognition .
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of the sr.eam bicding, condition if it eccursd und also provided for
rtstoration of the AfMS when such a condition is found. The
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licensee stated that trairiing has been conducted regarding these .
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procedure < changes. This wili be examined as part of the overall
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training review discussed in other paragraphs belowe
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No violatiotir ver.e identified.
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This item is closed as a restart issue.
0-2 (closed)
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Reviey pruc,edures to prevent water in train steaingline's. .(NUREG:
'1154)
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The NRC inspector reviewed a draft _ copy of 'the licensee's closure
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report and had no questions regarding' the conclusiens.
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licensee's prutedures do not 3ppear to require modification.
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>0parator awareriers of the difference betweee Safety Parameter
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Lirplay Systam-Once Through Steagt; Generator level indication and
actua) level resiaing'a eencern.. . This point is addressed is is. sue.
E-23 b'elow.
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.No vislAtions were identified.
This-itsm is closed as e restart issue.
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EDO -
n.a.
Develop procedures for switching from AFW to Main Feed Water (MFW)
including reset of AFW valves when MFW is reset. Assure oIerator
understanding of equipment response.
(Trip Report #73, 10/2/85 event).
The licensee was changing procedure A.51 " Auxiliary Feedwater
System" to incorporate.a method for the transfer. Training on the
procedure changes, when complete, will also be reviewed.
The item remains open as a restart issue.
RV
-
0-4 (open)
SMUD -
16a(4)
EDO -
5.a
Evaluate need for event related procedures in addition to system
related procedures (derived from the Abnormal Transient Operating
Guidelines (ATOGs)).
This item was addressed by RV, although primary close-out
responsibility has been accepted by NRR. RV addressed the issue as
part of the Region's review of the consistency of the licensee's
emergency procedures with'the ATOG's.
The licensee's review
'
determined a need for two additional event related procedures, one
dealing with the loss of ICS and one with the restoration of the
reactor system after SFAS initiation. During this inspection, RV
examined the consistency between the ATOGs and the E0Ps and also
addressed the issue of event related procedures. This review was
limited because the licensee had not finished adapting his
procedures to the latest applicable ATOG's.
This work is currently
underway.
In addition, when comparing the requirements of
Regulatory Guide 1.33 (November 1972) Appendix A Pact F, " Procedures
for Combating Emergencies and Other Significant Events", with the
station procedures, the inspector noted that several procedures
required by Regulatory Guide 1.33 were not available in the station
procedure manual. .The following listed items from Regulatory Guide 1.33, Appendix A, were not found to have a corresponding procedure:
Section F.3
Loss of Electrical Power (and/or degraded power
source) (in particular, loss of 125 VDC or 120
,
VAC power)
Section F.11
Loss of Flux Indication
Section F.24
Acts of Nature (in particular, tornado and dam
failure)
Section F.25
Irradiated Fuel Damage While Refueling
The inspector noted the following: A procedure for " irradiated fuel
damage while refueling" was partially present in the " Limits and
-
.
10
.
Precautions" section of B-8 " Refueling" procedure; however the
" Limits and Precautions," were not sufficiently detailed to be a
complete procedure, as defined by ANSI 18.7-1972 Section 5, which
prescribes procedure content and format. The emergency plan
implementing procedures (EPIPs) contained information on the
classification and general site activities required in the event of
a tornado or high wind conditions, but these procedures did not
address the plant activities as complete procedures to-the degree
required by Regulatory Guide 1.33 and ANSI 18.7-1972, Section 5.
There were numerous annunciators in the control room that indicated
various losses of voltage for the 125 VDC buses, and with each
annunciator there was a diagnostic response detailed in the
annunciator procedure. These, too, lacked the detailed corrective
action expected in a complete procedure. Also, there was no
corresponding procedure for loss of 120 VAC. The limiting
conditions of the Technical Specifications for a loss of flux
indication provided an action statement for this condition.
However, the Technical Specifications limiting conditions are not a
procedure in the sense required by Regulatory Guide 1.33, and ANSI
N18.7-1972Property "ANSI code" (as page type) with input value "ANSI</br></br>N18.7-1972" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process..
It was noted by the licensee at the Exit Interview that Inspection
Report 50-312/73-03 (issued in 1973) discussed areas in Regulatory
Guide 1.33 (Safety Guide No. 33) that were not covered by separate
individual procedures. They were in part: Loss of Flux Indication,
Expected Transients, and Acts of Nature.
It was the inspectors'
conclusion at the time of the 1973 inspection that the " Procedures
available for combating emergency conditions or significant events
appear to be generally consistent with the recommendations provided
in ANS 3.2 and AEC Safety Guide No. 33."
This appearance of general
consistency remains valid thirteen years later. However, in 1986 it
is concluded that certain specific procedures were not consistent
with Regulatory Guide 1.33.
This is an apparent violation.
This item remains open as a restart issue.
RV
-
0-7 (open)
SMUD -
16a(7)
EDO -
5d(2)
Provide clearer operator guidance for pressurized thermal shock
concerns (Recommendation #15 from 10/2/85 Trip Report).
The licensee is working on technical specification changes which
they expect to present to NRR for review and approval prior to
further developing the guidance for operators.
The item remains open as a restart issue.
,
11
.
6
1
RV
-
0-9 (closed)
SMUD -
16a(9)
,
EDO -
Sd(1)
Conduct training on overcooling events including actionc_to_b,e,taken
when reactor enters PTS region. Ensure operator unde'estanding of
system response with varying rates of decay heat. Ccaduct event
'
awareness training for 10/2 and 12/26 events.
(Recommendation #21_
from 10/2/85 Trip Report #73).
The subject of operator training and retraining covered in the
discussion of this item is applicable, in part, to itcas 0-10, 0-12
.
and 0-14 below.
These items included classroom, simulator, and " hands-on" training
covering the accident sequence of events, overcooling events,
'
Emergency Operating Procedure (EOP) changes, plant modifications,
Integrated Control System (ICS) operation, entry into areas of
unknown radiological conditions, manual operation of valves, and
l
other event related training.
'
The inspection included reviews of the following:
a.
Sequence of Events Training
,
b.
Non-licensed Operator Training
c.
Classroom Training for licensed Operators
d.
Simulator Tratning for Licensed Operetors
'
.
The inspection also included operator interviews and oral
examinations on the training provided in the above areas.
The findings in these areas are as follows:
Sequence of Events Training: The licensee provided training to
a.
all licensed and non-licensed operators on the sequence of
events from the cooldown transient of Decenter 26, 1985. The
,
purpose was r.o ensure that all operations personnel had an
overall perspective of the cause of the event and the transient
'
which followed.
The class included a review ei the major
occurrences which took place and a discussion of the events
with~ emphasis on problem areas which arose. Fred .e review of
the clasc attendance sheets, the inspector verified that all
licensed and non-licensed operatcrs received the tEaining,
b.
Classroom Training for Licensed , Operators: The Idcensee
provided the licensed operators with classroom training in the
following areas:
j
Modifications to the AlWs , TSVs, and AFW va: Lues
Changes to the E0Ps
'
Recovery from SFAS Actuation'(Casunity Procedure'C.41)
,
Local P.!anual Dperatioc of ALVs, TfVs, and ABI Valves
Conduct of Shift Operations (Changs to AP.1 and AP.23)
Loss / Restoration of ICS Pcwer (Casualty ProcedcJe C.40)
.
!
.
.
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.
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'
Entry Into Areas of Unknown Radiological Conditions
Operator Traps (dif ferences between simulator and Rancho
Seco)
. P
Local training for manual valve' operation was given at the site
and included " hands-on" training. . All other classes were given.
in conjunction with the simulator training. The inspector
reviewed the clas'sroom outlines and trainee handouts and
i
concluded that the outlines appeared.to cover the significant
. !
points from the accident and plant changes. The inspector also
verified that all licensed personnel had received the. required
- training. Valve training for non licensed operators is
discussed in 0-14 below.
4
c.
Simulator Training for: Licensed Operators: The licensee
provided the licensed operators with event and modification
i
training at the Babcock & Wilcox (B&W) simulator in Lynchburg,
VA.
A B&W certified NRC license examiner observed portions of
,
the training in the following areas:
1
Overcooling Events (including actions taken to preclude
Pressurized Thermal Shoch (PTS) concerns)
i
Loss of Power railures~of the ICS (including recovery and
-
restoration)
Makeup and Purification System Operation Following SFAS
Actuation
.
Throttling and Trip Criteria for Pumps and Valdes .
'
- '
Modificationt and Control koom Operation of the ADVs,
-
.
'
Differences Setween the Simulator and Rancho Seco
Changes to EOFs
,
'
,
,
~
The examiner concluded tbat the retraining in the observed
areas. adequately addressed the issues raised asia result; of the
-
,
1
10/2 and 12/26 events.
~
d.
Operator Interviews
.
,
-
'
'
During the week'of April 7-11,'1986, a Region.V inspector, NRR
..
license examiner, and ari NRC contractor conducted interviews
'
'
with.]icensed and non-licec' sed iperating personnel at the.
-
' *
,
Epncho Seco site'.
The . purpose was to assessL the effectiveness '
-
of the training by sampling the operators knowledge,about,the;
.
.
event oi December 26, 1986 sad the subsequent training that had
i
L
been given.
'
'
'
.
'Ihe interview sample included personnel 'f rom all operating
shif ts as well. as other licensed' personnel and consisted of:
3
4
(
,
?
3 Shift Supervisers
.
.
7
I
- *.
16 Senior Control ~ 0perators (SCO)'
n
'
6 Control Operators.(CO)
,
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3 Shif t Technical Advisot:s (STA)
i
,
,
7 Auxiliary Operaters (AO).
6 Equipment Attendaots-(EA);
,'
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13
.
The questioning was derived from various sources including the
NRC Incident Investigation Team (IIT) report (NUREG-1195), the
' licensee's event Summary Report, and the classroom outlines and
,
materials from the training sessions.
Based on the results of this evaluation the NRC concluded that
j
the retraining ~of the operators in the areas of weakness
demonstrated by the event of December 26, 1985, had been
effective. However, some: items were noted which indicated
!.
operator uncertainty in specialized areas.
l
1
!
Most operators were unsure about the use of the " Balance"
'
i
pushbutton on the new Leeds and Northrop AFW controllers.
j
They noted that it was not mentioned in procedures for AFW
,
control or loss of ICS power.
4
f
- *
Most non-licensed operators and some licensed operators
were not aware of the proper method (per the vendor
manual) for restoring the AFW Flow Control Valves to the
neutral and automatic position after being manually
closed. This is necessary for a "bumpless" transfer from
manual to automatic operation.
'
.
One licensed operator did not know that the makeup. tank
outlet valve (SFV-23508) closed on SFAS initiation and was-
.
adamant that it remained open.
t
!
Several licensed operators failed to recognize symptoms
requiring the trip of all MFW and AFW pumps supplying flow
to steam generators during an overcooling event. .This
2
requirement is contained in Step 3 of E.05, Excessive Heat
Transfer. c A procedure modification cin February, '1986
,
added the criteria of pressurizer level <10", or Tcold
<525*F.', ~which were not recognized during discussions as
.
triggering, criteria.
1
.
One' licensed operator was certain that the AFW control
-
'
valves fail closed on loss of instrument air.-
Another one
said they fail: closed before thinking through physically
j
what happens and reversed himself.
-
,
t
!
LSeveral licensed operators were' unsure of how instrument
air (IA) interfaces with the accumulator bottle's at the
,
l
Atmospheric Dump Valves (ADVs). They~noted.that the
'
2 training diagrams recently provided did~not indicate
valving for these connections. One operator did not know
why, if the IA header were breached, the accumulators
.
would not_ vent to the. break. One operator'(SRO) said the
accumulators cause the Turbine Bypass Valves:(TBVs) to
lock-as-is on loss of instrument air, and one (SS) said
the TBV/ADVs fail open but.the accumulators allow them to
)
,
'
be operated for a period of time afterward, before '
!
correcting himself on additional' questioning. Two
operators did not know how the nitrogen bottles at the ADV. .
Remote Operation Panel interfaced with the IA system-if
needed on loss of IA.
!
-
.
-. - - -
-
.
. -
- - - - _ . _ - -. _ . _ . . _ . , _
- . .
. - - _ , _ - , - ,
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, , - ,
_ _ _ _ _ _ _ _ _ _ _ _ _ _
'
14
.
One licensed operator did not, on a walk-thru operation of
the auxiliary feedwater control valve, follow the posted
procedure, nor did he understand that the procedure was to
be executed in sequence.
One licensed operator did not understand that the new
Leeds and Northrop Manual controller controlled the
auxiliary feed water control valve when in manual even
when ICS power was not available.
Three licensed operators (two senior, one operator) were
not aware of the ICS annunciator alarm changes.
One licensed operator and one non-licensed operator were
unaware of the reason for the neutral position of the
manual handwheel on the TBVs/ADVs.
Although these specific areas or questions indicated a need for
some improvement (these were discussed at the exit interview on
April 11, 1985) it was the conclusion of the NRC examiners that
the licensee has been conducting an effective retraining
program. Therefore, items 0-9, 0-10 and 0-12 are closed as
restart issues. The particular weaknesses identified will be
reinspected later during a scheduled inspection (86-07-02).
No violations were identified.
RV
-
0-10 (Closed)
SMUD -
16a(10)
EDO -
n.a.
Evaluate adequacy of operator training in specific areas and conduct
retraining as appropriate. Areas to include:
ICS system, including actions to verify operability, responses
a.
to failures and recovery from failure;
b.
Make-up and letdown system to specifically include operation of
MUT, BWST, and HPI under various conditions;
Steam generator and reactor level control to include throttling
c.
and trip criteria for various valves and pumps including RCP;
d.
Operations of ADV's, TBV's and AFW throttling valves;
e.
Differences between the B&W simulator and Rancho Seco.
Operator retraining and the NRC evaluation of retraining are
discussed under 0-9 above. See also 0-12 below. This item is
closed as a restart issue.
4
,
.
15
.
RV
-
0-11 (closed)
SMUD -
16.a(11)
n.a.
-
Evaluate the significance of the incapacitated senior reactor
operator in terms of his fitness for duty.
During the December 26, 1985 event, a Senior Operator collapsed from
unknown causes. The licensee committed to review the individual's
fitness for duty and withheld the person from control room duties
until it was known what caused the individual's collapse. Region V
Operator Licensing personnel reviewed the NRC form 396 ' Certificate
of Medical Examination' that the licensee submitted to confirm that
+
the individual was fit to resume control room duties. The
information supplied was sufficient to determine that the cause of
the collapse was not related to any underlying condition that would
prohibit the individual from control room work.
This item is closed as a restart issue.
No violations were identified.
RV
-
0-12 (closed)
SMUD -
16a(12)
EDO -
5.g., 5.b.
Evaluate training on Emergency Operating Procedures including the
assignment of responsibilities for completion of various procedures
or steps during'an emergency. Assure that rules which are to be
" committed to memory" are being retained. Conduct retraining as
necessary to include:
a.
The modifications being made prior to restart, the reasons for
the changes and the effect of these changes on emergency
procedures;
b.
Onsite and offsite notifications in an emergency; including a
clear understanding of what constitutes emergency situations
(EPIPs);
Criteria and precautions for entry into a potential highly
c.
contaminated area;
d.
Recovery from ICS or NNI failures, including recovery -from
SFAS.
EDO item 5.g. specifically addresses the necessity for a program
which assures that procedure changes are made and training. is
completed when plant modifications are made. During this inspection
a program was verified to exist for the types of changes resulting
from the modifications made as a result of the 12/26 event.
Further, the RV inspector verified that the licensee program for
accomplishing this has not varied from that existing prior to the
12/26 event.
Licensee failures in this regard, which may have
-
-
-
.
.
16
..
contributed to either the 10/2 or 12/26 events, appear to be
failures to adequately implement the program as it existed. Most
notably, during the 12/26 event, operators did not recall that the
ADVs could be operated from the Remote Shutdown Cabinet,
a
modification made during the last refueling outage.
In addition to the training and procedure reviews, Region V examined
the consistency between the ATOGs and Rancho Seco's emergency
procedures (see item 0-4 above).
Training and procedures are otherwise discussed in items 0-9 and
0-10 above. Although retraining work is continuing, and will be
further inspected, the item is closed as a restart issue.
No violations were identified.
RV
-
0-13 (open)
SMUD -
16.a(13)
EDO -
n.a.
Evaluate h'igh noise from Control Room / Technical Support Center
Emergency Filtration System (CR/TSC HVAC)
The scope of the examination in this area was expanded during the
course of this inspection, as an understanding of the complexity of
CR/TSC the HVAC problems developed. The NRC's position was that a
thorough review of the CR/TSC HVAC was required and that any
required modifications should be defined (not necessarily installed)
prior to restart. The need for operator training in this equipment
was also evident.
The item relates to the transient of December 26, 1985 because both
trains of the emergency HVAC system for the technical support center
and control room (TSC/CR) were initiated on receipt of a safety
features actuation signal. The resulting operating noise in the
control room impaired operator communications, and the operators
secured both trains in order to reduce the noise.
Th'e licensee addressed the excessive CR/TSC HVAC noise in its human
factors review following the event. The licensee's closure report
dated January 23, 1986, referenced a previous review of the control
room noise problem conducted in November, 1985.
At that time, noise levels in excess of NUREG-0700 recommendations
had been measured during operation of both trains of CR/TSC HVAC.
Prior to the December 26th event, corrective. actions for this
condition had been initiated to identify equipment support
modifications required to reduce the noise levels.
The inspector reviewed the licensee's closure report and the-
previous control room design review.
It was found that no specific
evaluation of the December 26th event-related noise problem had been
performed to determine if the problem was the same as that
previously identified in the control room design review. The
___ _
'
'17
.
inspector was concerned that the noise levels experienced during the
event may have been more severe than those measured during the
controlled conditions of the sound level survey. This concern arose
because the system reportedly does not stabilize at lower flows for
about ten minutes after it is started by an SFAS signal.
During review of the event-related essential CR/TSC HVAC operation,
the inspector identified the following concerns.
1)
Due to differences in the design of the control circuits
between the A and B trains, some confusion existed among the
licensee's staff as to the operating characteristics of the
essential CR/TSC HVAC system. During the December 26th event,
the A train HVAC was STOPPED and RESET within two minutes after
initiating on an SFAS signal. However after STOPPING the B
train, approximately 10 minutes later, the B train could not,
by design, be reset due to the continued presence of the SFAS
signal. With the A train secured and the B train STOPPED but
not RESET, the normal CR HVAC was still isolated. Furthermore,
the B train wis not rearmed for automatic initiation.
Based on interviews with representatives of the control room
staff, the inspector found that the operators were unclear as
to what actions would be required to initiate the essential
HVAC system under these conditions, if it had been necessary.
A licensee representative cognizant.of the essential HVAC
design confirmed that:
a)
Both essential HVAC trains would have automatically
initiated on a high temperature signal regardless of their
reset status; however,
~
b)
Only the A train would have automatically initiated on a
high radiation or subsequent SFAS signal since the B train
had not been reset.
Operator action within 10 minutes to manually load the A train
onto the emergency power bus would have been required under a
loss of offsite power if the B train was not reset.
The inspector reviewed the operator training. program for the
CR/TSC HVAC modifications and found that the training'did not
address the control differences between the trains. Further
the inspector reviewed the CR/TSC HVAC System Operating
Procedure, A.14, and found that there was no criteria or
guidance for securing individual trains of the essential HVAC
system to insure reset of the automatic actuation circuitry.
The absence of specific procedure guidance and training
represents further examples of procedure inadequacies revealed
during the December 26 event. These are discussed in the
enforcement action of section 2 above.
_ - _ _ _ _ _ -
'
18
..
2)
The inspector noted that the Interim Data Acquisition and
Display System (IDADS) data from the essential HVAC system
recorded an airflow of between 400 and 600 cfm in each train
when the trains have been secured. A licensee representative
stated that the erroneous data under 'no flow' conditions was a
characteristic of the instrumentation under low flow conditions
and that the condition did not affect the accuracy of operating
airflow data. The inspector was concerned that the inaccurate
IDADS data misrepresented the system operation condition to the
operators.
(Followup Item 86-07-03).
3)
In review of CR/TSC HVAC data from the December 26th event, the
inspector questioned the operability of the A train because no
flow was recorded during the time A train was actuated.
A
licensee representative stated that the IDADS system may not
have recorded the actual system flow during the short duration
the A train was actuated.
In this regard the inspector
questioned licensee representatives on the special reporting
requirements of Technical Specification 3.13.3 regarding the
inoperable status of the essential HVAC system during the
December 26th event. With the B train inadvertently disarmed
after being secured by not being reset, and questionable flow
indication for the A train, neither train may have been
operable for a period of time. The licensee is conducting
further tests to establish that at least one system was
available during the 12/26 event. Until this testing is
complete and reviewed by the NRC, this item will remains
unresolved (86-07-04)
Regarding the actual performance of the HVAC system as installed,
the excess noise led to the examination of recorded flow rates.
In
this review of CR/TSC HVAC data from the December 26th event, the
inspector found that the recorded airflow rates for the duration of
operation of the B train were in excess of the Technical
Specification requirements. Technical Specification 4.10 identifies
a system flow rate of 3200 cfm
10%. However, B train operating
airflow rates ranging from 4071 to 4575 cfm were recorded during
approximately 8 minutes of operation. A licensee representative
stated that this excessive airflow condition was an actuation
characteristic of the HVAC system design for both trains which
exists for approximately 10 minutes until equilibrium airflow was
established by the automatic system controller.
The inspector reviewed the monthly surveillance test of the A train
essential CR/TSC HVAC system (SP211.01A, Rev. 8, dated 10/1/85) and
found recorded A train airflow rates also in excess of 3200 cfm i
10% for the entire duration of the 24 minute surveillance test.
The inspector reviewed the manufacturer's specifications for the
carbon adsorber cells in the HVAC system used for adsorption of
radioactive iodine and methyl iodide gases. The inspector
determined that the HVAC system initial high air flow rate exceeded
the manufacturer's maximum rated airflow required for 0.25 sec.
residence time within the carbon tray to achieve 99.9% efficiency.
-
'
19
-.
This finding is an apparent violation of NRC requirements
(86-07-05).
Furthermore, the inspector reviewed the design basis report for the
CR/TSC HVAC modification and found that a maximum essential system
makeup airflow rate of 1000 cfm was identified as part of the design
analysis rather than the 1600 cfm system flow rate referenced in
This discrepancy was identified to
the licensee for resolution as part of their review of the control
room / technical support center HVAC operability.
This item remains open. One violation and one unresolved item were
identified.
RV
-
0-14 (closed)
SMUD -
16a(14)
EDO -
5.e.
Conduct training on proper valve operation methods including the
override of air operated valves.
This inspection area actually addressed the entire scope of
.
retraining for nonlicensed operators, since these individuals
received training other than that associated with valve operations.
See also 0-9 above.
The NRC inspector attended a series of training sessions given on
February 27-28, 1986. The material covered was:
Local' Manual Operation of the AFW Flow Control Valves,
Atmospheric Dump Valves (ADVs), and Turbine Bypass Valves
(TBVs)
Entry Into Areas of Unknown Radiological Conditions
Emergency Operating Procedure (EOP) and Casualty Procedure
Changes
ADV, TBV, and AFW Valve Modifications
Command and Control Training
The manual valve operation session included a detailed review of the
components and operations of the valves and valve operators, both
manual and automatic. The class also included " hands-on"
manipulation of each of the valves by all of the ' class attendees.
The class also covered the effects on the valves of a loss of
instrument air and a loss of the ICS. The session covering entry
into areas of unknown radiological conditions was a detailed review
of the new policy and procedure (AP.313-5) on the same subject.
The procedure changes, valve modifications, and command and control
training sessions were aimed toward providing non-licensed operators
with a general knowledge of the changes and not a detailed
understanding. This was appropriate to the duties of these
j
operators which do not require them to use the information when
i
unsupe rvised .
4
,_
-
.
-
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.
20
.
The inspector verified that all non-licensed operators had completed
the training, and concluded that the sessions covered the material
needed in each area. Therefore, this restart item is closed.
However, the inspector noted that the manual valve operations
training was limited to only the ADVs, TBVs, and AFW valves. The
inspector was concerned that there may be other valves in the plant
that operate differently than these valves that need similar
" hands-on" training. This will remain as a specific followup item
for a future NRC inspection (86-07-06).
No violations were identified.
0-15 (open)
RV
-
SMUD -
16.a(15)
EDO -
5.f.
Re-examine annunciator response procedures for technical adequacy.
This item arose directly from the finding in the IIT report
(NUREG-1195) that during the course of the 12/26 event, the Rancho
Seco operators did not use the applicable annunciator response
procedures, and that if they had used the procedure they would have
found it to be of limited value.
The licensee agreed to address the issue of re-examining all
annunciator response procedures. However, little apparent progress
on this item had been made by April 11, 1986, and thus.no inspection
has been conducted yet.
This issue remains open.
RV
-
E-1 (open)
SMUD -
16b(1)
EDO -
n.a.
Perform walkdown of the secondary steam system to determine branch
lines that have potential for contributing to an overcooling event.
For those lines whose valves do not isolate on loss of ICS, ensure
that the valve motor operators are capable of control from the
control room independent of the ICS.
The licensee addressed this issue in an Addendum to a February 19,
1986 letter to the NRC, " Resolution of Issues Regarding the December
26, 1985 Reactor Trip".
In the addendum, the licensee discussed the
actions performed for this item. The actions included a walkdown of
the individual steam lines, the identification of equipment effected
by the ICS, and the assessment of the capability to control
equipment required to isolate the main steam loads from the control
room. The licensee's findings suggest that after the modifications
are installed for the turbine bypass valves, atmospheric dump
valves, and the auxiliary feedwater control valves, that the control
room operator can effectively isolate the main steam loads from the
control room with and without ICS power.
-
- -
- -
- -
-
--
. _ _ -
_ _ _ _ _ _ _ _ - _ _ _ _ _ .
'
21
.
The inspector requested the information the licensee gathered for
the above conclusions. At the end of this inspection period the
information had not been provided, theref ore the inspector could not
complete his review of the licensee's actions.
This item will remain open on the restart list.
RV
-
E-3 (open)
SMUD -
16.b.(2)
EDO -
9. (see also E-5 below)
Perform Root Cause Analysis for 12/26 event (2.a).
To date the licensee has issued two significant reports addressing
the 12/26 event.
" Resolution of Issues Regarding the December 26, 1985, Reactor
Tr' "
This report, dated 2/19/86, is generally referred to as
summary report".
It discusses the causes of the event in
'
.
of " direct cause" and " root cause".
The definitions used
te : 3
by che licensee for these terms appear to be at variance from
the usage of the term by many others.
Briefly, " direct cause"
is the immediate reason for the failure and " root cause" the
programmatic reason for the failure. The licensee's
conclusions in this report did not provide any significant new
info rmation.
" Reactor Trip and Rapid Cooldown on December 26, 1985," Root
Cause Report 85-41 dated March 19, 1986. This is generally.
referred to as the " Root Cause Report".
It is prepared by the
licensee's Incident Analysis Group. The report contains 63
recommendations. This report has been examined by. Region V and
was found to be a useful contribution to preparation of the
plant for restart. While the root causes identified are
programmatic in nature, the recommendations are normally very
specific (even to the point of suggesting the actual wording
changes to be made in procedures).
The NRC inspector found that the licensee has performed a root cause
analysis. However, the issue will remain open until a system is in
place which specifically addresses the recommendations made in the
analysis.
This issue remains open.
E-5 (closed)
RV
-
SMUD -
16b(5)
9
-
Licensee to perform troubleshooting of ICS
This issue concerned the licensee's management system for
troubleshooting of damaged equipment in-a controlled and systematic
manner to determine root cause and appropriate corrective action.
- _ _ - - _ _ _ - _ _ _ .
.
22
.
It also concerned the troubleshooting of specific equipment damaged
during the 12/26 event. The issue of troubleshooting arose because
of concerns expressed by the IIT about the original methods of
troubleshooting used by the licensee, and which the team believed
required a more disciplined approach.
In order to determine the
root cause (the licensee's ' direct cause') of the equipment failures
contributing to the December 26th event, the licensee instituted
additional controls over the troubleshooting activities to ensure
that underlying problems were discovered. This troubleshooting
program was initially implemented in response to the October 2nd
event and provided for a more structured approach to dealing with
event-related recovery activities. During the investigation
following the December 26 event and after extensive work with'the
NRC Incident Investigation Team (IIT), the licensee expanded their
troubleshooting program to provide the additional documentation
requirements of the IIT in handling quarantined equipment to ensure
preservation of "as-found" equipment conditions. This consisted
primarily in reformatting the troubleshooting action plans to
document the approach employed in developing areas of investigation.
Additionally, rigid procedural adherence was exercised and enforced
to insure that the troubleshooting activity was conducted in the
preplanned fashion designed by the troubleshooting action plan and
that all maintenance work was limited to prevent disturbance of
evidence.
In the actual troubleshooting of equipment following the December 26
event, RV supported the IIT by observing the implementation of
" maintenance instructions" which provided the detailed step by step
procedures for troubleshooting each damaged or suspect piece of
equipment. This troubleshooting resulted in the discovery of a
loosely crimped terminal lug for the ICS power monitor whicu caused
intermittent high resistance, which in turn caused the ICS power
supply to trip. The terminal lug was replaced. The licensee also
found that the existing wire routing made the ICS power supply
monitor susceptable to trip. The wire was re-routed at.the time
that the lug was replaced.
Further, the power supply monitor module
was replaced; the original power supply monitor was to be sent to an
outside testing laboratory for evaluation.
To determine the generic implication of defective terminal lug
crimps in other safety cabinets, the licensee initiated a
reinspection program for all Bailey Cabinets in the control room.
This reinspection program is i.ddressed in Restart Item MA-2.
Regarding the more subjective issue of the licensee's approach.to
troubleshooting, RV examined the issue from the standpoint of
management systems which sapported troubleshooting of the type
performed for the IIT.
It'was first found that " troubleshooting to
determine root cause" had different meanings to different groups;
,
particularly the definition of " root cause" itself. As noted in
1
Item E-3, to the licensee, " root cause" addresses the programmatic
problem or management deficiency which allowed the problem to
develop. This the licensee distinguishes from the " direct cause"
which is the immediate problem or action which caused the event.
.
23
.
With regard to the " direct causes" of the December 26th event and
the licensee's approach to such determinations, the NRC can only
measure this by the licensee's response to future events,
particularly those events which may be precursors of more serious
events.
With regard to the determination of root cause, as defined by the
licensee, the charter for the licensee's Incident Analysis Group
(IAG) is described in Inter Departmental Procedure No. NO-004. This
procedure was examined as were the Root Cause reports for the
10/2/85 and 12/26/85 events. The inspector concluded that the IAG
has performed a credible job in these analyses.
Effectiveness of
this work will, of course, depend on the responsiveness of the rest
of the organization to the initiatives of the IAG.
The inspector concluded that a final determination of the adequacy
of the licensee's approach to troubleshooting cannot be made at this
time. However, the approach, as guided by the IlT, appears sound.
The item is closed as a restart issue.
No violations were identified.
RV
-
E-7 (open)
SMUD -
16b(7)
EDO -
n.a.
Complete Post Trip Report.
The report, prepared by a different licensee organization than that
which prepared the root cause report, proved to be a significant
report for the 10/2/85 event when viewed retrospectively.
Consequently, Region V considered a review of a similar report to be
a restart issue for the 12/26 event. At the time of this report on
restart issues, the trip report had not been issued for the 12/26
event. The item remains open as a restart issue.
RV
-
E-8 (closed)
SMUD -
16b(8)
n.a.
-
Perform Analysis of Steam Lines to include stress calculations and
walkdown inspections (1.f)
The licensee has addressed this issue in closure report 1.f, " Main
Steam Line Analysis". The licensee concluded that the main steam
line is acceptable for continued operation. The licensee performed
a stress evaluation of the main steam line, and the results showed
that the thermal loads were within acceptable limits.
In addition,
the licensee walked down the A main steam line and the A main steam
bypass line to the condenser, to identify any damage of piping or
supports due to possible water hammer. The walkdown included visual
configuration checks to identify any physical changes to the
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.
.
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,
24
.
support. This walkdown did not identify piping damage due to the
event of 12/26/85.
The inspector reviewed the closure report which included the stress
calculation and the pipe supports inspected during the walkdowns.
The inspector concluded that the closure report appears to have
provided sufficient information to determine that the main steam
lines are acceptable for operation. Therefore, the licensee's
action has removed this as a restart issue.
No violations or deviations were identified.
RV
-
E-9 (closed)
SMUD -
16b(9)
EDO -
n.a.
Determine minimum level reached by the pressurizer and potential
for Reactor Vessel (RV) head void
The licensee has addressed this issue in at least two documents.
In
the summary report, the licensee stated that although the
pressurizer level was off scale (low) for approximately 5 minutes
during the 12/26 transient, this did not cause problems with the
recovery effort. However, the potential for a reactor vessel head
void was not actually addressed in this summary report.
In the
closure report, the licensee stated that the pressurizer was off
scale (low) for 10 minutes and it appears that the pressurizer was
actually empty for 3 minutes or more. Both SMUD and B&W
calculations indicated that a small (about 100 ft.3) void formed in
the reactor vessel head.
B&W concluded that the pressurizer and
surge lines.would have been drained for approximately two to three
minutes and that a small void of about 100 cu. ft. fo rmed. However,
in reviewing the analyses and data, it was evident that definitive
answers were not and probably could not, be made. For instance, the
licensee's report speculated that steam from the emptying
pressurizer surge line caused the accelerated pressure drop at 0419,
although the inspector noted that the knee in this curve could have
been formed from the cooling effect of HPI pump flow which was
initiated two minutes earlier.
The review by the NRC inspector indicated that insufficient data was
available to adequately analyze the formation of voids in the
reactor vessel head. The absence of two improvements was evident:
a.
The requirement from NUREG 0737 Item II.f.2. that the licensee
install a reactor vessel level monitoring system.
b.
The recommendation from NUREG 0667 (6) (b) that plant operators
have the parameter of wide ranga pressurizer level available to
assess plant status. This has been under review by B&W for
some time.
In addition, the possibility existed for Control Rod Drive
Mechanisms (CRDM) operation in a gaseous rather than a water
.
25
.
environment af ter the formation of a void in the head, since Group 1
control rods were withdrawn approximately three hours after
pressurizer level was restored. A closure report readily
established that "any steam would have condensed well before the
rods were withdrawn". However, there was no assurance that
noncondensible gases from emptying the pressurizer had not been
carried into the RCS, collected in the reactor vessel head, and
entered the CRDM's.
In the present instance, since no rod drop
occurred after rod withdrawal, there was no possibility of CRDM
damage.
Limits for the collection of noncondensibles in the RCS
have been established to prevent gases from collecting in the CRDM's
during normal operation, but there was no way of determining how
much, if any, noncondensible gases may have collected in the CRDMs
during a transient such as the one of 12/26/85.
The inspector concluded that the licensee needs to review his
procedures as listed in short term recommendation number 2 of the
closure report'(1.g) to establish actions to be taken with regard to
noncondensible gases following a loss of pressurizer level.
No violations were identified and this issue is closed as a restart
issue.
The longer term open items for followup are:
1.
Installation of the NUREG 0737 item II.f.2 concerning RV level
measurement.
2.
Installation of wider range pressurizer level measurement
should be investigated.
3.
Examination of procedures to assure that operators are aware of
actions to take to control noncondensible gases whenever the
pressurizer empties (86-07-07).
Items 1. and 2. are already listed as open items on other open items
lists.
RV
E-10 (closed)
-
SMUD -
16b(10)
n.a.
-
Test condition of pressurizer heaters (1.i)
The licensee's closure report on action item 1.1, " Pressurizer
Heater Operation" was examined. The NRC inspector concluded that no
damage occurred to the heaters during the nine minutes of the
transient on 12/26/85 that the heaters were uncovered. The licensee
stated that there was a long term program to provide IDADS .
indication of electric current to the pressurizer heaters so that a
record would be available on such a question in the future.
However, an immediate concern to the NRC inspector was that the
report did not address preventive maintenance (PM) checks of the low
pressurizer level interlock, LSLL-21503, which was designed to
I
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,
e
c
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_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
'
26
.
protect the heater coils.
It was determined that there was no PM to
provide assurance that the low level interlock would continue to
function as designed when a transient caused the pressurizer to
empty. From discussion with the licensee, it was learned that no
single test established that the low level interlock was actually
functioning as designed.although periodic recalibrations of
components were performed.
The licensee stated that such a
functional test would be relatively simple to perform during
refueling outages and the matter will be evaluated.
No violations were identified.
The licensee's action has removed this as a restart issue.
Two open items remain outstanding:
1.
Add pressurizer heater current to IDADS.
(86-07-08)
2.
Evaluate preventative maintenance of the interlock between
pressurizer heater current and pressurizer low level.
(86-07-09)
RV
-
E-11 (open)
SMUD -
16b(11)
EDO -
supports 3.9.
Determine and identify CR instruments which fail on loss of ICS
power (1.j ) .
The licensee addressed a portion of this issue in the closure report
1
item 1.j.13.e.1 " Control Room Instruments Which Fail on Loss of ICS
Power / Loss of ICS Procedure:
Equipment Input".
The inspector
reviewed the closure report.
In addition, the inspector observed
the effects of a loss of ICS power while the plant was in a cold
shutdown condition and at various times when power to the ICS had
been secured and then compared the observed condition of certain
instruments against those identified; no discrepancies were noted.
Therefore, the inspector concludes that the licensee has identified
the equipment which fails on loss of ICS power.
l
Although the equipment that fails in the control room has been
identified, nothing is available to the operators which identifies
such equipment for ready reference during an emergency. The
licensee committed to providing some means of identification in the
control room (possibly identifiers on the equipment) which would
readily permit the operators to identify the equipment which fails
on loss of ICS and NNI.
This item will remain on the restart list for further inspection.
-
- -
- -
-
- - - -
- -
.
-.
-
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.
3
.
27
.
RV
-
E-12 (open)
SMUD -
16b(12)
EDO -
n.a.
Investigate main feedwater (MFW) block valve operation in main steam
logic as shown by IDADS.
During the transient, the main feedwater and startup feedwater
valves automatically closed as a result of the signal from the main
steam line failure logic. The IDADS system indicated that the
valves closed above 370-psig, 65 psig below the setpoint of 435
psig.
The+ licensee evaluated this apparent discrepancy and found that the
vendor manual M19.56.2-7, switch actuation setpoint tolerances were
determined to be 15% of the full gauge range of 1425 psi which
included a total 3% for all errors and 2% drift over a one year
period. This tolerance would cause an uncertainty of approximately
1 71 psig, resulting in a possible accuation point as low as 364
psig.
Thus, the licensee concluded that the main steam line failure logic
operated as required and closed the MFW valves within the expected
range of pressure. The licensee has proposed to increase the IDADS
scan rate to less than one minute to provide more accurate IDADS
indication. The implementation schedule is still under
consideration at this time.
To preclude condensate pumps from feeding a steam generator at
higher pressures than the point of actuation for main steam line
failure logic, the licensee proposed to increase the setpoint of
actuation. This change has been implemented.
The inspectors reviewed the ECN and completed Work Request packages
to verify that the set point of the pressure switches was readjusted
to 575 psig from the former setting of 435 psig and the reset of the
actuation switches remained at 725 psig. Furthermore, the operation
procedure was being revised to direct the operator to manually
enable the actuation logic at 790 psig (Procedure B.2 " Reactor
Coolant System Heatup to Hot Shut Down", page 20, Rev. 36), instead
of the old set point of 650 psig. The actuation logic manual bypass
or inhibit point remained at 650 psig (Procedure B.4 " Plant
Cooldown", Rev. 37). The operators will be trained on the setpoint
and procedure changes.
The final revised procedures and operator retraining record will be
reviewed by the inspector prior to restart and, therefore, this item
will remain open as a restart issue.
-
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. -
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28
.
RV
-
E-13 (open)
SMUD -
16b(13)
ED0 -
n.a.
Examine operator reference to strip charts vs. Safety Parameter
Display System (SPDS) for OTSG level (1.0).
The licensee addressed this item in closure report 1.0, "SPDS vs.
Strip Chart for OTSG Operate Level".
The licensee developed three
conclusions from their review:
(1) the SPDS manual listed an
incorrect temperature compensation algorithm, and the calculation
performed by the SPDS was a revised algorithm; (2) from simulation
testing and calculations the SPDS operate range level indication is
generally about 1% to 2% less than the strip chart recorders; and
(3) the SPDS was probably indicating 98% to 99% during the transient
while the strip chart recorders were indicating 100%.
The inspector reviewed the licensee's conclusions and concluded that
this item remains open because the licensee has not addressed the
actual discrepancy, noted by the operators, between strip charts and
SPDS indications of the OTSG levels.
Even though the SPDS-0TSG
1evels have been tested to agree with the strip charts with only a
small error, this error is smaller than the discrepancy observed by
the operators.
In addition, no review of why the SPDS manual had an
incorrect algorithm for the OTSG level has been performed.
Therefore, the extent of the incorrect information in the SPDS
manual is . undetermined.
This item will remain open on the restart list.
RV
-
E-15 (closed)
SMUD -
16.b(15)
EDO -
n.a.
Determine cause of makeup (MU) pump (P-236) failure (4.b).
The licensee addressed this issue'in his root cause report on the
December 26, 1985 transient. The pump failure was attributed to the
absence of adequate procedures for recovery from SEAS initiation.
Contributing to this pump failure was a lack of operator
understanding, which led to personnel error.
,
,
The licensee has written an event-related procedure on recovery from
SFAS initiation and has conducted training; see items 0-4, 0-9, 0-10
and 0-12, above.
l
The inspector reviewed the licensee's analysis in the root cause
report and concluded that the licensee adequately addressed the
causes of this failure. The inspector concluded that the
contributing cause may not have been present if the licensee had a
plant specific simulator in place, as presently planned, since the
Rancho Seco configuration of the Makeup Tank and Borated Water
Storage Tank (BWST) has not been cimulated on the B&W simulator.
.
,
29
.
No violations were identified, other than as discussed in section 2
of this report.
This item is closed as a restart issue.
RV
-
E-16 (closed)
SMUD -
16.b(16)
EDO -
n.a.
Licensee to modify procedures to permit operation without makeup
(MU) pump (4.c).
The NRC has been informed that the licensee now intends to repair
the makeup pump prior to restart of Rancho Seco. This makes the
question of procedures for operation without the make-up pump moot
as a restart issue.
This item is closed as a restart issue. However, should delays
arise in the delivery of makeup pump components, such that the
schedule for replacement is the only factor controlling start up,
this and other makeup pump issues will need to be reexamined.
,
RV
-
E-17 (closed)
SMUD -
16b(17)
EDO -
n.a.
Licensee to provide schedule for repair / replacement of MU pump.
This item was originally established to obtain a commitment for
repair or replacement of this pump in an expeditious manner
following restart of Rancho Seco. The subsequent decision to have
the pump in service prior to restart of the plant closes the issue.
RV
-
E-18 (open)
SMUD -
16b(19)
n.a.
-
Prepare LER on RCS overcooling (6.a).
The licensee submitted Licensee Event Report LER-85-25 per 10 CFR 50.73(a)(2)(i), 50.73(a)(2)(iv) and 50.73(a)(2)(v), to describe the
December 26, 1985 overcooling event. SMUD indicated that the
corrective actions to prevent recurrence would be submitted in a
supplement by 03/17/86.
The LER was reviewed against applicable 10 CFR 50.73 requirements
and found satisfactory. However, the supplement had not yet been
received as of May 12, 1986. A licensee representative stated that
a new commitment date to complete the supplement would be provided
by May 16, 1986.
i
i
.
.
l
i
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30
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l
i
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i
RV
-
E-19 (closed)
SMUD -
16b(19)
EDO -
n.a.
B&W to analyze potential for core lif t during 12/26 transient
(6.b.1).
The transient which occurred on December 26, 1985 resulted in the
operation of all four reactor coolant pumps longer than allowed by
normal operating procedures.
One reactor coolant pump should have
been shut off before reactor coolant cold leg temperature decreased
below 500 F.
The operation of four reactor coolant pumps at reactor
coolant temperature below 500 F. could result in excessive core lift
forces. The licensee evaluated this concern.
The licensee's NSSS supplier, Babcock and Wilcox, analyzed the
incident for possible excessive core lif t conditions. The analysis
of the possible core lif t due to a fourth reactor coolant pump
operating below 500 F. showed that based on the " bounding analysis"
some of the fuel assemblies could have undergone lifting.
No damage
was predicted to have occurred from the possible core lift, since
the lif t height and geometry would not misalign fuel ~ assemblies or
damage the fuel hold-down springs. The possibility of vibration is
not expected to increase due to the analyzed lift forces.
Babcock
and Wilcox has also determined that the " fuel-in compression" limits
were not exceeded at any time during the transient.
The inspector reviewed the licensee's closure' report 6.b for the
analysis, conclusions and recommendations of possible excessive core
lift forces during the incident and found them satisfactory.
The licensee has stated that the fourth reactor co'olant pump was not
shut off at 500 F. during 12/26 transient, as r'equired by operating
procedure B.4 step 3.11, Plant Shutdown and Cooldown, because of
operator preoccupation with other matters during the emergency.
This is to be corrected by revising, emergency operating instructions
to direct operators to shut off the fourth reactor coolant pump when
reactor coolant cold leg temperature-decreases to 500 F.
(E.05,
,
Excessive Heat Transfer),
No violations were identified.
This item is closed as a restart issue.
E-20 (open)
RV
-
SMUD -
16b(20)
EDO -
n.a.
Evaluate acceptability of closing maintenance valves during a
In an attempt to reduce AFW flow to the A OTSG during the-
overcooling event of December 26, 1985, operators were directed to
close a manual isolation valve (FWS-063) after encountering problems
.
, . - - -
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,,,
,-,-m.
,%_.
,_,,,mm..,-..,r_.,,--
.e-
_ ,
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,
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31
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in securing ArW flow utilizing the AFW control valve (FV-20527).
The licensee deouribed the manual isolation valve as a " maintenance
valve" since it was )nly intended to isolate the AFW control valve
during maintenance activities.
During operation FWS-063 is locked
open and controlled by the licensee's locked valve list. Since the
component performed to active safety function as an operation valve,
the valve manual operating mechanism was categorized as Quality
Class 2.
Periodic surveillance of the valve extended only over the
static features of the valve required to insure its safety function,
i.e. verifying the valve to be open and not leaking.
When the valve was called upon to be closed during the event, the
manual operating mechanism was inoperable and the valve could not be
operated from its open position.
In discussions with licensee representatives, the inspector
determined that the programmatic issue of operators using
maintenance valves was being evaluated and would be addressed in an
upcoming closure report.
This item will remain open on the restart list pending review of the
licensee's closure report.
RV
-
HA-1 (open)
SMUD -
16c(1)
4a. (see also MA-4 below)
Implement a valve preventive maintenance program (ll.e.h) (Not
restricted to safety related valves).
The need for an improved preventive maintenance program for valves
was evident from events during the 12/26/85 transient. This was
also recognized by the licensee but in a more limited fashion as it
related specifically to manually operated valves. There were two
manual valves which failed to perform properly during the incident,
which demonstrated the need for better preventive maintenance. One
of these two valves was the manual maintenance isolation valve in
the AFW line (FWS-063) which was completely stuck in the closed
position due to lack of maintenance; the other valve was SIM-003
which needed to be closed to isolate the damaged Makeup pump, but
could only be operated with considerable difficulty. The licensee's
investigation into the SIM-003 valve situation revealed that the
problem with the valve had been previously identified. The limited
maintenance which had been performed on the valve was known by the
licensee to be ineffective in correcting the problem (Section
III.A.2 of Root Cause 85-41).
,
In examining the preventive maintenance (PM) program,-the NRC
concluded that although a program existed, the program did not
adequately address all valves in the plant.
In particular, the
program did not provide and apply criteria for inclusion of any
valve in a PM program or apply criteria as to the type and frequency
of PM for any particular type of valve or service condition.
I
,
.
~
,
32
.
1
The licensee noted that there are approximately 15,000 valves _in the
Rancho Seco plant and that the full development of a rational PM
program would require some time. The licensee has stated that
documentation of the direction of their PM efforts will be previded
in the near future.
This item remains open as a restart issue.
'
MA-2 (open)
RV
-
SMUD -
16.c.(2)
'
EDO -
n.a.
Implement program to assure integrity of plant electrical
terminations.
The licensee determined, through trouble shooting of the ICS power
supply, that the ICS power failure which led to the overcooling
,
transient of December 26, 1985, was caused by a defective
termination. Tbe licensee found that a terminal lug was improperly
crimped and resulted in a loose connection between the wire and the
lug. The terminal was replaced by the licensee and inspected by the
NRC.
In order to. determine whether there is a generic problem with plant
terminations, the licensee initiated an effort to reinspect all
.
,
terminations in the ICS, Non Nuclear Inscrumentation (NNI), Reactor
Protection System (RPS) and Safety Feature Actuation System (SFAS)
cabinets- in the control room area. The inspection acceptance
criteria were based on Construction Specification NEPM 5304.8C,
which became effective after 1/1/86.
This specification appears to
be more specific and stringent than that us.d when the pis.nt'was
built. Perhaps as a consequence, the reinspection identifi'ed a
number of crimped termination lugs that did not meet the current
construction specification. NCR's were written, and were being
dispositioned by replacement of the rejected lugs or accep' ance
t-
based on engineering judgement.
'
In order to determine the significance of the rejected crimped
terminals, and the conservatism in the specification, SMUD initiated
Special Test Procedure STP-950 to test samples ~of'the worst case
crimped lugs which had been cut out for rework. The first test was
a pull test.
The lug and attached wire were pulled gradually with
up to 8 pounds of force for one minute. The 8 pounds force was
empirically determined by SMUD to be the worst; case force that any
single conductor could experience when accidentally pulled or jarred
during the performance of Work on adjacent terminations or
components, or when the lug itself is disconnected from the
terminal. Subsequent to the pull test, an electrical resistance
test was conducted on the lugs to determine cent'act resistance
between the lug and the wire.
The acceptance criteria'for lug wire
sizes AWG Nos. 16 thru 14 and 12 thru 10 were 0.004 chm and 0.001
ohm, respectively. All of the lug samples passed both tests. The
inspector observed some of the reinspections, rewcrk to disposition
the NCRs, and both types of tests and found them satisfactory. The
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33
..
reinspection and rework on the cabinets in the control room will
last through June, 1986. Furthermore, SMUD was considering
inspection of the terminations outside the control room after
evaluating the results of the control room cabinet reinspection.
While examining terminations in the field, the inspector found that
shielding terminations on some instrumentation wiring were
improperly secured. This was contrary to SMUD Construction
Specification NEPM 5304.8C, effective 1/1/86, section 5.9.3
Instrumentation and Control which states that:
"A bare shield drain
wire shall be insulated with Kynar heat shrinkable tubing if the
'
wire can possibly come in contact with other uninsulated. wire, metal
components, or metal devices. Unterminated shield drain wires (i.e.
" floating" shields) shall be insulated with a Kynar heat shrinkable'
end cap."
IEEE Std 422-1977, IEEE Guide for Design and Installation
of Cable Systems in Power Generating Stations, Section 6.2.3.b.,
Instrumentation Cable Shield Grounding states that:
" Connect shield to ground at only one correctly selected point, for
example: Where the signal is grounded...If shield is grounded at
more that one point, differences in ground potential will drive
current through the shield."
Rancho Seco Nuclear Generating Station Updated Safety Analysis
Report (USAR) Chapter 10, Steam and Power Conversion System, 10.1
Design Bases states that:
"The steam bypass-valves to the condenser, atmospheric dump valves
and main-steam safety valves are used, as necessary, following loss
of external load and subsequent turbine and reactor trip."
In addition, USAR Chapter 7. Instrumentation and Controls, 7.2.3
Integrated Control System, 7.2.3.1 Design Bases states that:
"The combined actions of the control system, the turbine bypass to
the condenser, and the atmospheric dump valves permit a 50 percent
load rejection without safety valve operation."
Contrary to the above, the inspector found unterminated shield drain
wire left uninsulated and in contact with the metal container in the
'
following field terminations:
'
Turbine Bypass Valves E/P transducers nos. PY-20561, PY-20563
and PY-20566
Atmospheric Dump Valves E/P transducer no. PY-20571
This condition could have created ground loops in the circuits, and
could have degraded the quality of the signal.
The licensee
indicated that NCRs would be written to disposition these
discrepancies.
This appears to be a deviation (86-07-10).
-
-
.,
. _ .
-.,
, , - - , -
-
_ ---
.
.- - ._
,
-
,,
-
.
. .
-
..
.
--. .
.
- -
- -
._- -
.
34
. .
1
The previous revision of the construction specification did not
specifically address unterminated shield drain wire.
To assess the effect of calibrated crimping' tool program on the
terminal lug installations, the. inspector conducted a -limited review
i
on SMUD's tool room and measurement and test equipment (M&TE)
j
control.
10 CFR 50 Appendix B, Criteria V Instruction, Procedures.and
i
Drawings states that:
" Activities affecting quality shall be
prescribed by documented' instructions, -procedures, or drawings of a
type appropriate to the circumstances and shall.be accomplished in
accordance with these instructions, procedures, or drawings.
-
Instructions, procedures, or drawings shall include appropriate
quantitative or qualitative acceptance criteria for determining that
important activities have been satisfactorily accomplished."
10 CFR 50 Appe'n' dix B Criteria XII Control of Measuring and Test
Equipment states'that: - " Measures shall be. established to assure
,
,
i
that tools, gauges, instruments,,and other measuring and testing
devices used in activities affecting quality are properly
controlled, calibrated, and. adjusted at specified period to maintain
accuracy within necessary limits."
.
,
Rancho Seco Technical Specification 6.'8 Procedures, 6.8.1 states
'
that:
" Written procedures shall be established, implemented and maintained-
covering the activities referenced below:
The applicable procedures recommended in. Appendix "I" of
a.
Regulatory Guide 1.33, November 1972."
i
2
Regulatory Guide 1.33, Section H, Procedures for Control of
~
Measurement and Test Equipment, states that:
j
1
l
i
t
" Procedure of a type appropriate to the circumstances should be
provided to assure that tools, gauges,Linstruments, controls, and
'
1-
other measuring and testing devices are properly controlled,
calibrated, and adjusted at specified period ~ to maintain accuracy."'
,
-
SMUD Administrative Procedure'AP.604, Tool Room,'Rev."7, paragrams
.
3.0.1.2 states-that:
"The orderly condition and cleanliness < of the~
-
.
Tool Room shall be maintained and tools shall be segregated and
properly ' stored."
_
i
Contrary to the- above, the licensee,could n'ot provide the inspector:
1
- with-procedures'specifically' addressing-crimping tool calibration.
i
and usage'at the time of the inspection. Furthermore, when the-
inspector asked to see random samples, of crimping tools 'in the s tool
.
room, three crimpers were found which were overdue for calibration
but'which were not segregated from the properly, calibrated crimping
tools. The three~ crimpers identified were AMP Model 68042 Model B.
-
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4
r
a
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- . +
,
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.
35
.
'
SMUD control numbers CTE 30832, 30833 and 30834. Work performed
with these crimpers was not readily traceable through the usage log.
Prior to the inspection exit meeting, SMUD took the following
actions to assess the safety impact:
1
1.
Reviewed recent modifications Work Request packages on RPS,
SFAS and NNI and found that these three crimpers were not used.
2.
Recalibrated the three overdue crimpers and found them within
specification.
Although there were apparently no unsafe terminations resulting
directly from the use of these crimpers, the absence of control over
this equipment is considered to be a violation (86-07-11).
This item remains open as a restart issue.
RV
-
MA-3 (closed)
SMUD -
16.c.(3)
EDO -
n.a.
Failure of "B" control rod drive breaker to trip (NRC LER 82-19
IR 82-86 possible generic item).
LER 82-19 described a failure with "B" Control Rod Drive (CRD)
circuit breaker (G.E. type AK-2A-25-1).
This item was first
addressed in Inspection Report 82-36, but was retained as open item
LER 82-19-LO.
On June 5, 1985, while the licensee was performing
surveillance and calibration on the
"C" channel of the reactor
protection system, the reactor trip breaker failed to trip open when
the undervoltage trip attachment- (UVTA) was actuated (LER 85-06).
Th.is event became the subject of IE Notice 85-58 published July 17,
1985. Supplement One to this notice, issued November 19, 1985,
'dentified similar problems with AK-2-25 breakers experienced at
Calvert Cliffs and Oconee Nuclear Power Plants. Since these CRD
breaker problems are all similar and closely associated they are
addressed together under this section.
To 'his end, the CRD breaker
t
problems along with the identifying event / source are summarized in
the following paragraph.
Inspection Report 82-36 identified two other problems:
The open/close spring of a CRD breaker fell off its locator pin
a.
a number of times.
The relocation of the spring prevented
resetting the breaker which would preclude closing the CRD
breaker after it has tripped open.
b.
An out-of-adjustment shunt trip paddle prevented the breaker
from opening.
IE Notice 85-58 described two other issues:
.
-
..
. - _.
,
_.
.-.
._
_,
e
-
.
96
.
>
-
c.
'The clearance between reller rivet and armature within the
undervoltage trip attachment (UVTA), when significantly greater
than specified, could cause the breaker to fail to trip,
d.
A need for procederes to verify critical paraseters of the CED
bre,ahers to insure preper breaker operation..
Supplement one of IE Notice 85-58 characterizes two a-dditional
problems:
The slipping of armature laminated sectiper on to pole face
e.
resulted in slow trip responce time 6f the updarvoltage trip
device,
f.
Larger than hormal heads on mounting studs for undarvoltage
trip device, reduced cleara.nces which resultad in slow trip
response time.
'
The six concerns were examined as follots:
,
Item a
"
l
The event where an open/close spring of a CED breaker fall off its
locator pin was Fritten up in Noncetforman.ce report A-114, dated
November 15, 1974. A second incident where a spring came off a CRD
_
circuit breaker was written up on work naquest (W/R) 61902 in
September 1952.
Cn. this occasion, the spring war. retuructl to its
normal position and the breaker was tested and returned to service,
The cause of the first event was an improperly formed spring
(hooking device). This event was coceunicated te the General
!
Electric Company {GE) who supplied two replacement. spric15 Phic'h
,
were installed in the CRD ' breaker to torrect the problera.
GE, who
'
maintains a ' performance histot:y of each breaker part' in order to
i
replace or modify those parts Khich display a history of failures,
,
stated that the-closing /cpening spring mechanism has, during the-
i
past twenty years, displayed a failure. rate of such negligible
,
proportions that its desiga has remained unchanged.
,
i
The supplier was also of db2 epinion that if the spring, whose
dimensions fall within Specified tolerances, is properly
reinstalled, no spring-related brecker problem would be encountered.
,
The issue was also reviewed and discussed at length et a B&W ownecs'
group rea<ctor trip breaker symposiura held December ll' and 12,.1985
at the Arkansas Nuclear One Trai7ing Center. During this meeting;it
was found of six participating licensees, cne other licensee (APEL) '
had experienced .a similar occurrence with loss of an oper/close
'
spring. The ESW owners'aroup concluded that -It was potentially e
generic problem and could only 'ae corrected by replacement 'of tbc
improperly formed spring.
Surveillance requirements for these CED circuit breakers require-
that they be operated once each month Nhen the plant is in oper& tion
and since the installation of shunt trip devices on the circuit
- - -.- -....-..-.--.-.
.
37
.
breakers, surveillance requirements demand two operations per month
of CRD breakers during plant operation.
The quality assurance (QA) section of the licensee's organization
has performed four QA surveillances on the CRD AK-2 circuit breaker
activities between June 6, 1985 and February 11, 1986.
The inspector examined two type AK-2-25 circuit breakers (an AC
breaker and a DC breaker) and reviewed the above identified NCR,
W/R, associated correspondence, owner's group report and QA reports.
The inspector concluded from the infrequent occurrence of the event,
the regular operational surveillances to confirm operability, the
fact that the springs become disengaged only in the tripped mode
(safe position), and the fact that the problem is being actively
followed by the licensee, that the issue has been properly
addressed.
Item b
The issue of an out-of-adjustment shunt trip paddle which prevented
the breaker from opening also developed from the review of
LER-82-19-LO.
Electrical maintenance procedure EM.175 " Control Rod
Drive Low Voltage Power Circuit Breaker Maintenance" was revised to
include sections in this procedure to require adjustment of the UVD
armature and verify it moves freely and does not jam on the trip
paddle which will preclude the recurrence of this problem. The
inspector reviewed maintenance procedure EM.175, Revision 5, and
~
specifically examined the applicable sections which describe the
maintenance and testing of the shunt trip device. The inspector
concluded that the maintenance procedure adequately addresses this
problem.
Items e and d
The two items which are described in IE Notice 85-58:
Item c, the
,
clearance between roller rivet and armature within the undervoltage
trip attachment (UVTA) when significantly greater than specified
could cause the breaker to fail to trip; and item d, establish
procedures to verify critical parameters of the CRD breakers to
insure proper breaker operation were adequately addressed in
inspection report 85-16 dated August 14, 1985.
Items e and f
The inspector verified that measures were included in section 6.13
of revision 5 to Electrical Maintenance Procedure EM.175 to prevent
the occurrence of slipping of armature laminated sections onto the
pole face (Item e).
The inspector noted that the licensee inspected the undervoltage
trip devices on circuit breakers at Rancho Seco concerning the issue
of larger than normal mounting stud heads (Item f).
To prevent this
type of problem from occurring at Rancho Seco, section 6.12.1.3 was
incorporated into Maintenance Procedure EM.175 under Revision 5
l
.,.
---
.
38
.
which became effective February 19, 1986. The inspector examined
the Maintenance Procedure EM.175 6.12.1.3 and concluded that this
revision adequately addressed item f.
The inspector reviewed the history of recent maintenance on the CRD
circuit breakers. During the last refueling outage, the six
inservice breakers (2 AC/4 DC) along with the only spare circuit
breaker (AC) were shipped to the factory in Atlanta for general
overhaul. During this period (spring 1985), the licensee purchased
two additional spare circuit breakers (1 AC/I DC). The licensee
presently has three spare breakers (2 AC/1 DC). The undervoltage
trip devices (UVTDs) on the six inservice circuit breakers and the
two spare AC circuit breakers have been inspected and found to meet
the recommended requirements of IE Notice 85-58.
Twelve spare UVTDs
were held in stores, plus one additional UVTD, and were shipped back
to the factory to be refurbished to assure that they would be free
of possible defects listed in G.E. Service Directive 300.0 and meet
the requirements of the IE notice. To date, three UVTD's have been
received back from the factory.
One of these devices was to be
installed in the spare DC' circuit breaker. The remaining ter UVTD's
were scheduled to be shipped to the licensee during July 1986.
No violations or deviations were identified.
The concerns of items a, b, c, d, e and f above, and of IE Notice
85-58 are closed and the item is closed as a restart issue.
RV
-
MA-4 (open)
SMUD -
16c(4)
EDO -
4a
Verify operability of manual valves and remote operated valves.
Perform inspections to assure integrity of packing and verify proper
assembly of manual operators including setting of " neutral" position
and mounting devices.
During the December 26, 1985, operators were unable to close AFW
manual valve FWS-063.
Subsequent investigation disclosed that the
valve operating mechanism was rusted due to lack of lubrication.
The licensee replaced the rusted operator components and verified
valve operability by stroke testing of the valve. The licensee
determined that no damage to the valve stem or packing had resulted
from the attempted operation of the valve during the event. The
inspector observed the repairs to FWS-063 and subsequent stroke
testing of the valve.
The licensee checked the operability of five identical manual valves
in other systems and found no other instances of binding in valve
operation. However, the licensee's Root Cause report did identify a
problem with manual valve SIM-003.
See item MA-1 above.
During the December 26, 1985 event, the manual operator of AFW
control valve FV-20527 was damaged due to the use of a valve wrench,
causing a loss of manual control of the valv .
. -
-
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39
.
P
6
The licensee replaced the daceged mattual operator on valve FT-20527
and issued specific guidance and restrictions on the use of welve
wrenches on manual valve operatons.
As noted in item MA-5 below, the inspector reviewed the licensee's
repair activities and observed the proper reassembly of the faanual
operator. The inspector reviewed the manufacturer's instructions
for manuel operation of FV-20527 and observed that the operators did
follow the instructions with rega rd to isolation of the air supply
to pneunatic oper.ator. The licensee conducted training on the
proper manual operation of the valves .and posted instructions on the
valve as gaidance to the eperatort to ensure prcper operation.
I
The licensee has embarked on an expanded program to address tabe
maintenance and operability of over cne hundred manual valves which
the operations department has identified as critical.
This item will remain opes on the restart list pending completion >of
,
the licensee post maintenance testing of the AFW control valve and
'
completicn of the licensee's expanded inspection of manual v.alve
operability.
RV
-
MA-5 (closed)
SMUD -
16c(5)
EDO -
n.a.
Perform repairs to ICS and valves which were damaged daring the
12/26 transient.
The repairs to the manual valve operator for the air eperated
auxiliary feedvatet valve damaged during the 12/26 transient were
examined by the NRC inspector, as were the repairs to the manual
maintenance valve which was found stuck and inoperable during the
transient. No problens were noted with these repairs-
,
The repairs of the ICS system components which were the direct cause
of the 12/26 event was also examined. The loose terminations on
manufacturer supplied equipment led to a more extensive examination
of termications elsewhere in the plant; see MA-3 above.
No violations were identified with this item.
.
The item is closed as a restart issue.
.
RV
-
MA-6 (open)
SMUD -
(see belcw)
'
n.a.
-
r
Determine diseasition of deeraded 125V station batteries.
The degraded condition of the 125 VDC station batteries was
discovered during this inspection.
Since the Tatteries were
visually severely degraded, and appeared to need replacement, this
F
S
w
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-
e
_ _
_
_
,
40
Q
became a restart issue, and the licencee proceeded to promptly
resolve the matter.
i
,
The licensee's 125 VDC nuclear batteries were originally installed
l
in June of 1971. At that time, their expected life, per the
,
manufacturers informatier., was 20 years. To date all four banks, A,
B, C & D, of the 125 VDC nuclear batteries are at the end of their
useful life and needed immediate replacement, according to the
vendor representative.
The inspector expressed concern that under the present battery
maintenance program there was no credible means of establishing the
battery condition in terms of remaining useful life.
The inspector also noted several other concerna relating to the
battery maintenance and surveillbace programs.
a.
Weekly Surveillance Program
The cell in the bank which has the poorest performance during
the p revious. monthly surveillance was selected by the licensee
as the pilot cell. The pilot cell was selected in a series
string to reflect the Feneral candition of all cells in the
battery regarding specific gravities, float voltage and
temperature.
It served as an indicator of battery condition
between sche,duled overall individual cell readings. For bank
BD, cell #12 was designated as the pilot cell.
Upon
inspectica, it was observed that the cell had excessive cell
degradation, especially in the plate lug area.
It was apparent
from the condition of the cell, that it was a poor performer.
It repeatedly failed the weekly surveillance criteria, and
consequently, the whole bank was placed on equalizing charge.
This condition existed periodically from June 17, 1985 to the
p res e.nt.
During this period the pilot cell failed the
acceptance criteria 18 times, which resulted in an undesirable
overcharge of the entire battery. This has the effect of
causicg excessive plate wear and shortening battery life. No
mechanism had been provided to identify and replace the
degraded cell. Under the present program, one bad cell has the
capability to degrade and shorten the life of the entire
battery.
Morecver, EM 104A, Weekly Station Battery Pilot Cell Test,
January 23, 1986 Step 5.1.1 reads, "If corrected specific
gravity of the pilot cell falls more than .005 below previous
weeks reading or when the value is less than 1.205, bank shall
be placed on equalize." Contrary to the above on June 17, 1985
and November 4, 1985 Bank BD was not placed on equalize when
the pilot cell specific gravity was below 1.205.
This item
will remain unresolved pending review of the technical
jastification to be provided by the licensee (86-07-12).
.
41
.<
,
b.
Monthly Surveillance Program
Specific gravity was routinely measured in order to indicate
the state of charge of a cell.
Both the cell temperature and
electrolyte level affect the specific gravity reading. A loss
of water from evaporation or electrolysis results in a lower
electrolyte level and a more concentrated electrolyte (higher
specific gravity reading).
Both the electrolyte temperature
and level'should be recorded and used to correct specific
gravity at the time the specific gravity is being taken, so
that a true indication of the cell condition is established.
The licensee does not correct for level. Without the level
correction, the specific gravity may not be sufficiently
accurate. This is a non-conservative practice _by the licensee
and needs to be addressed in future revisions of maintenance
procedures.
(86-07-13).
c.
Service Testing
At each refueling interval the licensee is required to conduct
a battery service test. This test demonstrates the battery's
ability to meet the bus design loads (duty cycle). The testing
profile should follow as closely as practicable to the actual
design load prot 11e.
A review of the profiles showed that the
licensee's service -test was adequately profiled, and, in many
cases, conservative in nature. However, when reviewing
procedure EM.106, " Station Battery Test Discharge and Equalize.
Charge, Rev. 4, June 13, 1983, one concern was identified:
Step 6.0.3 reads, " Examine electrolyte level'in each cell.
If
water is needed, add distilled water to level marked on cell,
and allow batteries to recharge before conducting test."
The
licensee stated that if water was added, the battery would be
equalized prior to starting the service test.
Recommended Practice for Maintenance, Testing and Replacement
of Large Lead Storage Batteries for Generating Stations and
Substations, 1980, recommends that starting conditions be as
close as practicable to those.found during normal operation.
In short, the battery should not be prepared for the test, but
rather, tested in_the "as found" condition.
By equalizing the
battery before the service test the validity of the test
results can not be substantiated for the worst case condition.
This item is considered open (86-07-14).
d.
Training
l
It was apparent from interviews with the personnel performing
the battery surveillance procedures that adequate training was
not provided in the area of battery maintenance. Personnel had
little training in battery operating characteristics, early
warning signs of degradation, or proper- preventive maintenance.
The lack of adequate training was evident in the performance
maintenance procedure of EM-105A, Monthly Station Class I
Battery ICV, Specific Gravity and Temperature Test, January 14,
1986.
Enclosure 7.1 of the procedure entitled, Monthly Class I
4
,
I
c
.
1
42
-
.
1
Battery Report, has a comment section headed by " Physical.
Integrity of All Cells Checked." This. corresponded to Step 6.12
of the procedure.
In the many surveillance records ~ reviewed,
by the NRC inspector, no battery degradation was identified,;
although numerous examples existed. The licensee stated'that
increased training on the batteries was-being proposed. .This
additional training will be reviewed during a subsequent
inspection (86-07-15).
2
e.
Battery Replacement Criteria
.
Under the present program, the battery will be given a service
test to show design capability once every refueling. .The
batteries would be reevaluated, retested or replaced in the
' event of a failed service test. The service test, however,
offers ~little information as to the' actual capacity of the
battery, and is, therefore, of little use in predicting when
' the battery should be replaced. The graph of a battery's
~
capacity vs. time is, for' the most part, a flat line. The line
changes only at the knee of the curve where battery capacity
drops off sharply in a short period of time. The battery,
should be replaced when it starts entering the knee of the
capacity-time curve. This is generally represented by a-
' capacity of 80% of the manufacturer's rating. When replacement
is required, the recommended maximum time for replacement is
. ithout. running a battery capacity test, assurance
W
one year.
cannot be provided as to the overall condition of 'the battery
and'the ability to meet design loads. The licensee is
considering this item. This item is open and the issue has-
been referred to NRR for technical evaluation (86-07-16).
-
F.
Seismic Qualification of Battery Racks
.
,
I
At another facility, battery end gaps (the gap between.the.last
battery in a rack and the rack)' measured approximately.three
inches. The facility contacted Gould Inc., the. supplier of the
equipment, as to the proper end gap.
Gould responded that
seismic testing for qualification had been done'with gaps not
,
greater than a quarter of an inch. NRC requested that Gould
inform the affected facilities 'of the same. On April 1,1985~
the licensee received a letter from Gould dated March 27, 1985
describing the end gap situation.' Upon receiving the letter-
the licensee took no immediate action to survey the nuclear
batteries with respect to rack installation and end gap. The
inspector observed numerous ~ examples of end gap; greater than a
quarter of an inch. The. average end' gap measured approximately
one inch.
It appears that the licensee was aware of the
j
potentially unqualified configuration of the: station battery
1
racks for.several months and neglected to take corrective-
action. This will be an unresolved item pending review of the
licensee's analysis of the battery rack installation
(86-07-17).
,
,p
.
- _ _ _ - _ _ - - _ _ _ _ _ _ _ _ _
.
43
.
The subject of battery maintenance surveillance programs,
testing and installation remains open as a restart issue.
RV
-
M0-1 (closed)
SMUD -
16d(1)
EDO -
n.a.
Examine alternatives to ADVs and TBVs opening to midposition on loss
of ICS (3.f.4).
The actions resulting from this review are addressed in the
following section; MO-3.
Accordingly this specific restart issue is
closed.
RV
-
MO-3 (open)
SMUD -
16d(2)
EDO -
supports 3.b.
Establish the capability for control room control, independent of
the ICS, of ADVs, TBVs and AFW flow control valves.
The licensee's closure report on open Action Item 3.f.4, 5 was
reviewed. This report concerned modifications to the atmospheric
steam dump valves (ADVs), turbine bypass valves (TBVs), controls and
auxiliary feedwater (AFW) flow control valves. The modification
would allow control of the ADVs, TBVs and AFW control valves
independent of the integrated control system (ICS) on loss of ICS
power.
The modifications were designed to prevent a recurrence of the
overcooling event which occurred on December 26, 1985. The December
26, 1985 event involved an inability to control the ADVs, TBVs and
AFW flow valves, and this contributed to the depressurization and
cooldown of the secondary and consequent overcooling transient of
the primary system.
The existing control signals from the ICS to the ADVs, TBVs and AFW
flow control valves are -10 VDC to +10 VDC with a zero voltage
representing a 50% open signal. Therefore, loss of ICS power (zero
voltage) causes the ADVs and TBVs to fail to the 50% open position.
The existing plant configuration allowed control operators to
manually close the ADVs and TBVs from the remote shutdown cabineti
H2SD, in the west switchgear room on grade level in the Auxiliary
Building. This remote location requires dispatching an operator to
the remote shutdown cabinet.
Loss of ICS power (zero voltage) also caused the AFW flow control
valves to go 50% open; this in turn represented a fixed valve
position and effective loss of AFW flow control. Operators take
manual control of both AFW flow control valves in the tank farm.
This location also represented a considerable delay in regaining
adequate AFW flow control and could exacerbate any transient
involving AFW flow.
.-,
_
.
-
. .
.
44
.
The licensee has initiated modifications to control room panels HIRI
and H2PS to provide new control stations for the ADVs, TBVs and AFW
flow control. Prior to the modifications, the licensee conducted a
safety review of the proposed facility changes and determined that
the modifications would not result in an unreviewed safety question
or require Technical Specification changes.
The modification to HIRI will provide a new control station for the
ADVs, and the TBVs in the Control Room. This new station will:
A.
Allow automatic closure of the ADVs and TBVs from the control
room.
B.
Provide manual closure of the ADVs and TBVs.
4
C.
Override of the automatic closure of the ADVs and TBVs and
allow the operator to open the ADVs or TBVs (50% open) while
ICS power is lost.
The modification to H2PS will provide a new control station for AFW
.
flow control. This new station will:
A.
Provide automatic means to position the AFW flow control valves
to a pre-determined position on loss of ICS power.
B.
Provide Hand / Auto Controllers to provide manual control of the
AFW flow control valves independent of the ICS.
C.
Provide startup range level indication for both steam
generators (operating range and AFW flow is presently provided
on H2PS).
l
The new control stations for the ADVs, TBVs and AFW flow control
valves will be independent of ICS power. The loss of ICS power
signal will be provided by an existing auxiliary relay in the ICS
that will monitor both the AC and DC power in the ICS cabinets. The
new control circuit for the AFW flow control will also be
independent of ICS.
The licensee has indicated that:
1.
The TBVs will remain under ICS control and the modification to
their control will become permanent to provide control
independent of ICS.
2.
The control of the ADVs will be removed from ICS and
transferred to the new emergency feedwater initiation and
control (EFIC) system during the next refueling outage. This
will make the ADVs independent of the ICS. The temporary
modification to the ADV control system, previously described,
would be removed with the installation of EFIC.
3.
Control of the AFW flow control valves will be transferred from
the ICS to the new Emergency Feedwater Initiation and Control
-
-
-
-
-
-
-
-
- -
-
-
-
e
'
45
.
(EFIC) system after the EFIC system is installed during the
next refueling outage.
The transfer of the AFW Flow control to
the EFIC system will make the AFW flow control independent of
the ICS. The short-term modification, as previously described,
would be removed.
The licensee has indicated that these modifications will make the
ADVs, TBVs and the AFW flow control valves perform in a manner
similar to the same valves in other B&W plants.
The inspectors reviewed the Engineering Change Notices ECN No.
R-0357, R-0357A, R-0357B and samples of the completed Work Request
packages. Further, the inspectors visually inspected the completed
modifications in the control room and on the AFW regulating valves.
The inspector found the licensee's changes to be satisfactory.
However, the restart issues identified remain open for the following
reasons.
1.
The design basis report will be reviewed by NRR and until this
,
review is completed RV cannot conclude its inspection activity.
2.
The testing of the modifications remains to be examined.
3.
Training in the modifications and associated procedure changes
is still under review.
RV
-
MO-6 (closed)
SMUD -
16d(6)
n.a.
-
!
Determine feasibility of splitting annunciator signal for ICS
trouble into two or more components including an "ICS power failure"
signal.
The licensee, to improve the annunciation of faults that occur in
the integrated control system (ICS), determined it was feasible to
rearrange the annunciation of two windows to clarify the
interpretation of the ICS power failure alarms.
At present, annunciator window H2PSB-34 annunciates "ICS Fuse Fail"
and H2PSB-64 annunciates "ICS or Fan Power Failure". This change
will redefine window H2PSB-34 as "ICS Trouble". This window will
alarm on the following conditions:
1.
Any blown fuse in the ICS system
2.
Any ICS cabinet fan failure
3.
Any ICS DC power supply failure
Annunciator window H2PSB-64 will be redefined as "ICS SYSTEM
FAILURE". This window will alarm on the loss of the + or -24 VDC
power busses only. Therefore, on a total loss of DC power the
control room will have a definitive alarm alerting the operator. On
conditions of a less critical nature, such as fan failure or blown
-_ -
_ _ _
_ _ _ _ _
a
4
46
.
fuse, the ICS trouble window will alert the operator.
In addition,
indicating lights will be installed on the ICS cabinets to indicate
which power supplies are supplying voltage to the DC busses.
The licensee issued a design change package to rearrange the
annunciation in the control room. The inspector examined the design
change package documents in detail and concluded that the change was
being adequately managed.
This item is closed as a restart issue.
No violations were identified.
RV
-
M0-8 (closed)
SMUD -
16.d.(8)
EDO -
n.a.
!
Examine IN 85-94 (minimum flow for ECCS pumps) for applicability to
!
Rancho Seco (4.h).
Potential for Loss of Minimum Flow Paths
Leading to ECCS Pump During a LOCA
The NRC Information Nocice was provided to alert licensees of recent
instances where it was discovered that minimum flow requirements
might not or could not be met for some emergency core cooling system
(ECCS) pumps under small-break loss-of-coolant-accident (SBLOCA)
conditions.
System Arrangements at Rancho Seco
The system arrangements at Rancho Seco with regard to the notice are
!
described below:
a.
DHR pumps are well protected with respect to miniflow. The
miniflow line has no valves in it.
It takes the flow
downstream of the DHR cooler and delivers it to the pump
suction. The only valve, which if closed would stop any
discharge from the pump, is loc'ated between the pump and DHR
cooler. This valve is locked open.
Refer'to P&ID M-522, Rev.
25, Decay Heat Removal System.
It is concluded that nothing in the Information Notice applies
to the DHR pumps,
b.
HP injection and makeup pump miniflows all go to a common line
which contains two SFAS valves in series'(SFV-23645 and
SFV-23646). The common-line discharges into the RC pump seal
return line upstream of the coolers (E-240A and B). The seal
return line leads to the makeup tank (MUT). All valves in this
line are locked open. Normally both SFAS miniflow valves are
open. They close automatically on SFAS initiation. When
recovering after SFAS initiation, the operator opens these
w
- - _ _ _ _ _ _ _ _ _ _ _ _ _ .
,
'
47
O
valves again when net flow to the RCS is reduced. Refer to
P&ID H-521, Makeup and Purification System, Sheet 1, Rev. 8,
Sheet 2, Rev. 11, and Sheet 3, Rev. 6.
Specific Information Notice Concerns and Effects
Concern 1:
Miniflow valves perform dual function of miniflow and
containment isolation.
Response:
SFAS valves (SEV-23645 and SFV-23646) perform single
functions and are automatically closed by SFAS only.
Concern 2:
Miniflow valves open to perform their safety
function.
Response:
Rancho Seco valves perform their safety function by
closing. Opening them after a SFAS initiation is
done manually.
Concern 3:
Single element failure in the miniflow controls could
close the valves and make all ECCS pumps fail on SFAS
initiation.
Response:
Because Rancho Seco valves close on SFAS initiation,
the safety function would not be affected.
Concern 4:
Valves were deactivated in closed position when the
plant was at power.
Response:
At Rancho Seco, the miniflow system is shared between
HPI and makeup pumps. Because the makeup system
requires these valves to be opened in order to'
function, the Peach Bottom situation, where the
valves were closed for a long time with plant at
power, could not happen at Rancho Seco.
Concern 5:
Miniflow valves failed closed on loss of power or
air.
Response:
At Rancho Seco the valves are motor operated, not air
operated. They fail "as is" on power failure.
The inspector reviewed in detail with the licensee the following two
concerns identified in the discussion of the notice but not fully
addressed above:
(1) the operability of various ECCS pumps was
jeopardized by loss or potential loss of recirculation of flow
paths; and (2) the importance of minimum flow recirculation systems
to ECCS pump operability may not yet be fully reflected in design
and operation because adequate attention has not been focused on the
effects of SBLOCA sequences until relatively recently (i.e.,
following the Three Mile Island accident).
As identified above, these problems do not apply to the DH pumps.
With regards to HPI injection pumps, these pumps function during
<
,.
.
- _ _ _ -
_ _ _ _ - _
,
48
.
safety injection without miniflow since SFAS which initiates
starting of the HPI pumps also initiates opening of the injection
valves to the primary system (one valve for makeup is always open
during normal plant operation) and closes the miniflow valves
SFV-23645/646. The shutoff head of the HPI pump of approximately
3100 psi, which is in excess of the primary system code safety valve
settings, will assure some flow into the vessel; and will not be
affected by slow bleed-down of primary system pressure because of
Small Break LOCA. The HPI pumps are designed to operate at 105 gpm
continuously, at 40 gpm for a maximum of 15 minutes and at less than
40 gpm for 15 seconds before the pumps are damaged. However, it is
necessary to re-establish miniflow as early as possible to protect
the pumps which, as described above, is accomplished by operator
action.
The inspector reviewed the December 26, 1985 event where the makeup
pump lost suction which resulted in major damage to the pump. The
cause for loss of suction was due to failure to open the suction
valve to the makeup tank before closing the suction valve from the
borated water storage tank (BWST) in re-establishing miniflow and
normal makeup flow. To preclude a similar occurrence in the future,
the licensee has prepared procedure C.4 " Recovery from SFAS
Actuation". The inspector examined this procedure and has concluded
that the procedure appears to provide sufficient guidance in
re-establishing miniflow and normal makeup flow when recovering from
a SFAS actuation.
It is concluded that the concerns raised in IE Information Notice No. 85-94 to have been properly addressed by the licensee.
This item is closed as a restart issue.
No violations were identified other than as previously discussed in
Section 2.
4.
Management Meeting
On April 4 the NRC inspectors met with Mr. S. Redeker and other members
-
of the licensee's staff to discuss the results of the restart inspection
to date.
In addition, meetings have been conducted with a member (s) of a
licensee group designated as Action List Response Team (ALRT). These
meetings were on a daily basis whenever inspection work was ongoing at
]
the site.
When the oral examinations to verify operator retraining were completed
on April 11, 1986 another exit meeting was held with Mr. S. Redeker and
other members of his staff directly concerned with training.
5.
Status of Restart Issues
The status of the 38 items addressed in this report are tabulated in the
4
summary attached.
- -
-
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-
- -
- -
.
.
- -
-
-
.
.
. .
.
- - .
- - -
(
.*
49
.
Items which have been assigned open item designators in this report are
not necessarily restart issues. Accordingly an item may be closed as a
restart issue but some aspects of the issue may remain open for future
examination and, therefore, have an open item designator.
.
1
i
4
'
k
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- - - - -
.
-
.
f
l
o
, ' '
50
RESTART ITEMS STATUS
'
ITEM
STATUS
ITEM
STATUS
0-1
CLOSED
E-1
OPEN
'
0-2
CLOSED
E-3
OPEN
0-3
OPEN
E-5
CLOSED
0-4
OPEN
E-7
OPEN
0-7
OPEN
E-8
CLOSED
0-9
CLOSED
E-9
CLOSED
0-10
CLOSED
E-10
CLOSED
0-11
CLOSED
E-11
OPEN
0-12
CLOSED
E-12
OPEN
0-13
OPEN
E-13
OPEN
0-14
CLOSED
E-15
CLOSED
0-15
OPEN
E-16
CLOSED
E-17
CLOSED
E-18
OPEN.
E-19
CLOSED
E-20
OPEN
MA-1
OPEN
M0-1
CLOSED
MA-2
OPEN
MO-3
OPEN
MA-3
CLOSED
MO-6
CLOSED
MA-4
OPEN
MO-8
CLOSED
MA-5
CLOSED
MA-6
OPEN
'
TOTAL RV ITEMS THIS REPORT
38
-
CLOSED
20
-
OPEN
18
-
..
4
5
0
h
!
_
- .
-
- - -
-
- - -
- -
- - -
-
-
-- - ---