IR 05000313/1980003
| ML19309G132 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 03/12/1980 |
| From: | Callan L, Johnson W, Westerman T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML19309G122 | List: |
| References | |
| 50-313-80-03, 50-313-80-3, 50-368-80-03, 50-368-80-3, NUDOCS 8005050014 | |
| Download: ML19309G132 (25) | |
Text
8005050 0/1
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U U. S. NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT
REGION IV
Report No.
50-313/80-03 License No. DPR-51 50-368/80-03 NPF-6 Licensee: Arkansas Power and Light Company P.O. Box 551 Little Rock, Arkansas 72203 Facility Name: Arkansas Nuclear One (ANO), Units 1 and 2 Inspection at: ANO Site, Russellville, Arkansas Inspection Conducted: January 22 - February 21, 1980 Inspectors:
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W. D. Jo
~ Resident Reactor Inspector
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h JYN Y th S. Dean, Reactor Inspector Date llAD0 R."SmithpeactorInsp[ctor
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s Date Approved:
M 3// 2/Pa T. F. Westerman, Chief Date Reactor Projects Sections
Inspection Summary Inspection conducted during period of January 22 - February 21, 1980 (Report No. 50-313/80-03)
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Areas Inspected:
Routine, announced inspection of Plant Operations Review, Test and Measuring Equipment Program, Follow-up on Previously Identified Items, Implementation of TMI Lessons Learned Requirements, Follow-up on 10 CFR Part 21 Reports, and Maintenance.
The inspection involved 149 inspector-hours on-site by four NRC inspectors.
Results: Within the six areas inspected, one item of noncompliance was identi fied (infraction - failure to control access to a high radiation area, paragraph 13).
Inspection conducted during period of January 22 - February 21, 1980 (Report No. 50-368/80-03)
Areas Inspected:
Routine, announced inspection of Plant Operations Review, Test and Measuring Equipment Program, Follow-up on Previously Identified Items, Implementation of TMI Lessons Learned Requirements, Follow-up on 10 CFR Part 21 Reports, Maintenance, Power Ascension Test Witnessing, Review of Power Ascension Test Data, and Review of Licensee's Authorization to Raise Power.
The inspection involved 206 inspector-hours on-site by four NRC inspectors.
Results: Within the nine areas inspected, no items of noncompliance were identifie.
DETAILS 1.
Persons Contacted Arkansas Power and Light Company Employees, J. P. O'Hanlon, ANO General Manager G. H. Miller, Engineering & Technical Support Manager B. A. Baker, Operations Superintendent T. N. Cogburn, Plant Analysis Superintendent E. C. Ewing, Plant Engineering Superintendent P.' Jones, Maintenance Superintendent F. Foster, Operations and Maintenance Manager J. McWilliams, Assistant Operations Superintendent J. Albers, Planning and Scheduling Supervisor D. D. Snellings, Technical Analysis Superintendent J. Anderson, Refueling Coordinator L. Schempp, Manager of Nuclear Quality Control T. Green, Training Coordinator R. Roderick, Human Resources Supervisor M. Bishop, Acting Plant Administrative Manager R. Elder, I&C Superintendent R. Tucker, I&C Supervisor R. Ryals, Metrology Supervisor R. Carroll, Health Physics Supervisor C. Bean, Maintenance Supervisor L. Bell, Assistant Operations Superintendent P. Kearney, Engineer J. Hebison, I&C Supervisor W. Poskey, Maintenance Supervisor L. Howard, Engineer J. Waxenfelter, I&C Supervisor B. Neal, I&C Supervisor J. Vandergrift, Training Supervisor G. Fiser, Radiochemistry Supervisor H. Roark, Maintenance Supervisor B. West, I&C Supervisor The inspectors also contacted other plant ' personnel, including operators, technicians and administrative personnel.
2.
Followup on Previously Identified Items (Units 1 & 2)
(Closed) Infraction 313/79-21-01 (Inspection Report 79-21):
Outdated Q-Lists The licensee's response to this item included revision of the distri-bution methods for Q-List revisions and ensuring that each Q-List holder has current copies. The inspector has no further questions on this item.
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(Closed) Open item 368/79-15-03 (Inspection Report 79-15):
Computer access to incore thermocouple data.
The licensee has added capability for the operator to access and display incore thermocouple data as a group.
(Closed) Open item 313/80-01-01 (Inspection Report 80-01):
Lifted leads in ESF Control Cabinets C-16 and C-18.
The lifted leads in these cabinets have been identified with tags which identify the design change under which the leads were lifted.
(Closed) Open item 313/80-02-01 (Inspection Report 80-02):
Revision of procedure 1202.11, High Activity in Reactor Coolant.
The licensee has issued Revision 2, PC 3 to 1202.11, including the I-131 concentration limit and the required action if this limit is exceeded.
(0 pen) Item of Noncompliance 313/79-15-05 (Inspection Report 79-15):
Requalification program requirements not met.
The inspector reviewed the corrective action taken for the licensed operator requalification program.
These corrective actions have been taken in part in that a schedule has been provided for training, the specific requalification lectures that were not given have been administered and the annual evaluations have been accomplished.
The inspector reviewed actions that are being taken to prevent recurrence of this item. The planned actions appear adequate.
This item will remain open until this planned action has been accomplished.
3.
Test and Measurement Equipment Program The inspection of the test and measurement equipment program included the following:
A.
Calibration Control Program Review Verification by review of established controls that the following items have been accomplished:
(1) Criteria and responsibility for assignment of the calibration /
i adjustment frequency have been established.
(2) An equipment inventory list or equivalent has been prepared which identifies the following:
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(a) All test and measurement equipment which will be used for any reason on safety related structures, systems or components.
(b) The calibration / adjustment frequency for each piece of equipment.
(c) The calibration standard (national standard (s) if applicable) for each piece of equipment.
(d) A calibration procedure to be used for each piece of equipment.
(3) Formal requirements exist for marking the latest inspection /
calibration date on each piece of equipment or otherwise identifying the status of calibration.
(4) A system has been provided for assuring that each piece of equipment is calibrated and adjusted on or before the date required.
(5) A written requirement has been established which pronibits the use of test and measuring equipment which has not been inspected and calibrated within the prescribed frequency and describes controls to prevent inadvertent use of such equipment.
(6) Out-of-calibration controls have been established which require the following:
(a) When a piece of equipment is found to be out-of-calibration, the acceptability of items previously tested or measured will be evaluated and documented.
(b) Evaluation of cause of out-of-calibration.
(7) A formal system has been established to assure that new test and measurement equipment will be added to the inventory list and calibrated prior to being placed in service.
B.
Implementation (1) Verification that responsibilities have been assigned to assure that test and measurement equipment controls are being implemente.
(2)
Inspection of the actual system being used to assure that each piece of equipment is being calibrated before the date required.
(3) Verification that all standards used for calibration have adequate documentation to determine traceability back to the National Bureau of Standards.
During the review of calibration control procedures the inspector noted that procedure 1004.10 " Calibration Control," paragraph 4.3.2.1 requires that:
" Calibration histories are closely followed to indicate trends or chronic conditions requiring a reduction in calibration interval, a repair or replacement."
A review of existing records indicates that a system does not exist that provides for the retrieving of calibration history for the purpose of establishing and analyzing trends or chronic conditions. Although a regulatory requirement does not exist for performing this function, licensee representatives stated that the procedure will be revised to establish a practical means of performing this desirable analysis.
This item will remain an open item until the procedure revision is reviewed by the NRC.
(0 pen item 313/80-03-02; 368/80-03-01)
The inspector further noted that the licensee's control of vendor test equipment calibration differs from that established by pro-cedure.
Procedure 1004.10 " Calibration Centrol," paragraph 5.7.2 states that:
" Test equipment from other sciirces than ANO such as contractors, vendors and the Relay Department, will be turned over to the I&C Department where they will be checked for proper operation and calibration and reissued as needed."
In actual practice, due to the large quantity of vendor test equipment involved, the licensee allows selected vendors to control their own test equipment and depends on the licensee's Quality Assurance organization to verify the adequacy of the vendor's calibration control program.
Licensee representatives stated that their procedures will be revised to conform to the actual practice in this matter. This item will remain an open item until the procedure revisions are reviewed by the NRC.
(0 pen Item 313/80-03-03; 368/80-03-02).
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4.
TMI-2 Lessons Learned Requirements (Units 1 & 2)
On January 2,1980, the NRC Office of Nuclear Reactor Regulation issued confirmatory orders for Arkansas Nuclear One Units No. I and 2.
These orders confirmed licensee commitments to implement all
" Category A" lessons learned requirements of NUREG 0578 prior to plant operation after January 31, 1980.
On January 21-23, 1980, a lessons learned implementation team from NRC headquarters visited the ANO site to verify implementation of certain aspects of the Category A requirements of NUREG 0578 and to survey the licensee's status and methods of compliance.
The inspector continued verification of the implementation of the lessons learned requirements after the departure of the implementation team. The inspector's review of activities in this regard are summarized below.
The item numbering system of NUREG 0578 is used.
2.1 Emergency Power Supplies Unit 1, Pressurizer Heaters DCP 79-1078 was accomplished by the licensee to add 42Kw of back-up pressurizer heaters to the swing bus, which may be energized from either diesel generator. The inspectors reviewed this DCP, Job Order 5701-80-01 (Installation and Checkout of Vital Power to Pressurizer Heaters), and the following revised procedures:
1107.01 Rev. 4 Electrical System Operations 1202.05 Rev. 3 Degraded Power Procedure 1202.05 includes a procedure for connecting other pressurizer heaters to vital power if needed due to the failure of some of the 126Kw of pressurizer heaters that are normally connected to vital power.
Unit 1, ERV Block Valve DCP 1062 was accomplished by the licensee to provide vital power to CV-1000, the electromatic relief valve block valve.
The inspector reviewed this DCP, Job Orders 5503-80-01 and 5506-80-01 (Installation and Checkout of Vital Power to ERV Block Valve),
and revised procedure 1107.01, Electrical System Operations.
Unit 2, Pressurizer Heaters DCP-79-2167 was accomplished by the licensee to modify the
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enables the operators to re-energize 150Kw of proportional
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heaters control circuit.
This DCP enables the operator to re-energize 150Kw of proportional heaters from each diesel generator following a SIAS or loss of offsite power.
To re-energize these heaters, the operator uses handswitches 2HS-4640 or 2HS-4641 in the Control Room.
The inspector reviewed this DCP, Jo') Order 2-5701-80-01 (Checkout of DCP 2167), witnessed a functional test of the modified circuitry during the Integrated Safeguards Test, and reviewed revised procedure 2202.05 Rev. 2, Degraded Power.
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2.1.3.a Direct Indication of PORV and Safety Valve Positions Unit I and Unit 2 DCP 79-1050 was accomplished by the licensee to provida a direct indication of the opening of the Unit 1 ERV or pressur:zer safety valves with an acoustical valve monitoring system. A similar system has been installed under DCP 2164 for the Unit i pressurizer safety valves. The inspector reviewed the seismic qualification of the new equipment cabinets in the Conf.rol Rooms.
Other items reviewed by the inspector include:
(For Unit 1)
Work Plan 1408.01, Chec:out of Valve Monitoring System 1202.06 Rev. 6, Loss of Reactor Coolant 1202.29 Rev. 5, Pressurizer Systems Failure 1203.12 Rev. 3, Annunciato Corrective Action 1202.14 Rev. 6, Loss of RC Flow, RCP Trip 1202.;o Rev. 5, Loss of Steam Generator Feed (For
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Work Plaa 2408.01 Checkout of Valve Monitoring System 2202.06 Rev. 3, Loss of Reactor Coolant 2202.29 Rev. 1, Pressurizer Systems Failure The following items remain open:
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. Revision of 2203.12 Annunciator Corrective Action
. Issuance of an operating procedure for the valve monitoring systems (open item 313/80-03-04; 368/80-03-03)
2.1.3.b Instrumentation for Detection of Inadequate Core Cooling The licensee has installed DCP 1051 for Unit I and DCP 2165 for Unit 2.
These provided two channels of reactor coolant system margin to saturation measurement and indication for each unit.
The inspector reviewed these DCP's and Work Plans 1408.03 and 2408.02, Calibration of Margin to Saturation Indication System.
Procedure revisions reviewed for changes required by these design changes are listed below:
(for Unit 1)
1202.06 Revision 6 Loss of Reactor Coolant 1203.12 Revision 3 Annunciator Corrective Action 1107.01 Revision 4 Electrical System Operations 1202.14 Revision 6 Loss of RC Flow, RCP Trip 1202.26 Revision 5 Loss of Steam Generator Feed 1202.23 Revision 4 Steam Generator Tube Rupture (for Unit 2)
2202.06 Revision 3 Loss of Reactor Coolant 2107.01 Revision 1 Electrical System Operations 2202.14 Revision 1 Loss of RC Flow 2202.26 3evision 1 Loss of Steam Generator Feed 2202.23 havision 1 Steam Generator Tube Rupture The following items remain open:
. Revision of 2203.12 Annunciator Corrective Action
. Issuance of an operating procedure for the margin to saturation system.
(0 pen item 313/80-03/80-03-05; 368/80-03-04)
2.1.4 Diverse Containment Isolation Unit 1 The licensee has installed DCP 1059 to provide certain containment isolation valves (listed in items 9 through 16 of items 2.1.4 of
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the licensee's letter dated January 18, 1980, to the NRC) with a signal to close on low reactor coolant systems pressure.
The inspector reviewed this DCP and Work Plan 1409.10 which provided a procedure for checkout of the ESAS System following DCP 1059.
Unit 2 The licensee has installed DCP 2222 to provide certain containment isolation valves (listed in categories III and IV of item 2.1.4 of the licensee's letter of January 18, 1980, to the NRC) with a sig-nal to close on low reactor coolant system pressure.
The inspector reviewed this DCP; witnessed portions of Work Plan 2304.127, ESF Time Response Testing; and witnessed performance of surveillance test procedure 2105.03, Integrated Safeguards Test.
2.1.6.a Systems Integrity The licensee has performed leakage testing of the below listed systems under Work Plan series 1409 for Unit I and series 2409 for Unit 2.
Unit 1 Unit 2 Makeup & Purification High Pressure Injection Liquid Radwaste Liquid Radwaste Containment Spray Reactor Building Spray Decay Heat Removal Low Pressure Injection Waste Gas Waste Gas Chemical & Volume Control The inspectors reviewed the completed leak tests and verified the implementation of a Preventive Maintenance program to re-perform the leak tests at least once every 18 months.
The inspector also reviewed Revision 3 to administrative procedure 1004.02, Initiation and Processing of Trouble Tickets.
This procedure revision requires that observed leakage in potentially radioactive systems be reported on a Trouble Ticket.
2.1.6.b Plant Shielding The licensee performed no short term modifications under this ite.
2.1.7.a Automatic Initiation of Emergency Feedwater Systems, Unit 1 The licensee has accomplished DCP 1049 in order to provide automatic initiation of the emergency feedwater system independent of the Integrated Control System. The inspector reviewed this DCP and the following additional items:
Work Plan 1408.06 Checkout of EFW controls after Installation of DCP 1049 and 1049A Work Plan 1408.05 Functional Check of ICS after Removal of EFW Control Functions 1106.06 Rev. 6 EFW System Operations 1102.02 Rev. 8 Plant Startup 2.1.7.b.
Emergency Feedwater Flow Indication, Unit 1 The licensee has accomplished DCP 1069 in order to provide redundant indication in the Control Room of flow in each emergency feedwater line to the two steam generators. The inspector reviewed this DCP and Work Plan 1408.02, which provided for system cali-bration.
2.1.8.a Post Accident Sampling The licensee performed no short term modifications under this item.
2.1.8.b Increased Range of Radiation Monitors The licensee has accomplished IDCR 2-79-119, providing a system for collecting post-accident iodine and particulate samples from either auxiliary building exhaust duct and for monitoring the gaseous activity of the effluent.
The inspector reviewed this design change, the work plan for calibration of the detector, Work Plan 1408.04, and the system operating procedure, 1903.15.
The licensee plans to install a similar system for the Unit 1 Hydrogen Purge System by May 1, 1980.
2.1.8.c Improved Iodine Instrumentation The licensee has ordered two dual unit single channel analyzers which can be used to analyze air samples for Iodine during an accident.
These are expected to be available by May 1, 1980.
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2.2.1.a Shift Supervisor Responsibilities The licensee's Vice President, Generation and Construction, issued a management directive on December 26, 1979.
This directive, entitled ANO Shift Operating Supervisor Responsibility, has been distributed to ANO operations personnel. The licensee has issued Revision 1 to Standing Order No. 44, Conduct of Control Room Operations, to implement the provisions of the above directive.
The administrative function of key issuance has been deleted from Shift Supervisor duties and assigned to a guard.
2.2.1.b Shift Technical Advisor (STA)
The licensee has implemented a STA program using plant staff engineers on a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> rotating duty day basis.
The STA wears a telephone beeper and is available within 10 minutes of being summoned.
Standing Order 45 has been issued to outline the STA duties and responsibilities. Standing Order 44 requires that the Shift supervisor or the Control Room operator notify the STA as soon as practical during the onset of transients or upsets.
2.2.1.c
[hift Turnover Procedures The licensee has strengthened shift relief and turnover procedures by issuance and implementation of Revision 3 to Standing Order No. 41, Use of Shift Relief Sheets During Shift Turnover.
The Assistant Operations Superintendents have been assigned to observe a shift turnover once per month at regular intervals and to audit the documentation and verbal turnover.
The audit results are noted in the Station Log.
2.2.2.a Control Room Access The licensee has issued and implemented Revision 1 to Standing Order No. 44 to control access to the Control Room during both routine and emergency situations.
2.2.2.b Technical Support Center (TSC)
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The licensee has established a TSC in the Plant Administrative Building as described under item 2.2.2.b of the licensee's letter of January 18, 1980, to the NRC. The inspector reviewed Emergency Plan Procedure 1903.01, Revision 0, Response and Accountabilit This procedure requires that specified personnel report to the TSC upon Emergency Plan implementation.
The inspector also reviewed Emergency Plan Procedure 1903.03, Revision 0, Evacuation.
This procedure includes provisions for evacuation or.other pro-tective measures to be taken if radiation levels in the TSC reach specified levels.
2.2.2.c Operational Support Center (OSC)
The licensee has established an OSC in a conference room adjacent to the TSC. The activation of the OSC is provided for by Emer-gency Plan Procedure 1903.01.
The Emergency Plan revision which the licensee has submitted to the NRC for approval recognizes the existence of the OSC.
5.
Follow-up on IE Bulletin 79-06C (Unit 2)
A.
Background IE Bulletin 79-06C was issued on July 26, 1979.
This bulletin required that the licensee take certain actions to alleviate the concern over delayed tripping of the reactor coolant pumps after a Loss of Coolant Accident (LOCA).
The licensee's letter of August 29, 1979, provided responses to short-term action items 1 through 4 of the bulletin.
The C-E Owners Group letter of November 8, 1979, submitted revised Post-LOCA guidelines. These guidelines were approved for use at cer-tain plants (including ANO-2) by the NRC letter of November 14, 1979, to the Chairman of the C-E Owners Group.
B.
Scope The inspector had previously verified the licensee's action in response to IE Bulletin 79-06C short term action item number 1.
During this inspection period, the inspector reviewed the licensee's emergency procedures for conformance to the approved Post-LOCA guidelines.
The inspector also reviewed the training the licensed reactor operators received for the Small Break Loss of Coolant Accident (SBLOCA) procedures.
The inspector interviewed several operators to determine the adequacy of the procedures from a functional standpoint and the effectiveness of the training program.
The inspector also reviewed system-related aspects of the procedures to ensure that the operator actions could be performed, i
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C.
Findings (1)
Procedure Implementation Procedures reviewed in this effort included:
2202.06 Rev. 3, Loss of Reactor Coolant 2202.23 Rev. 1, Steam Generator Tube Rupture 2202.14 Rev. 1, Loss of Reactor Coolant Flow 2202.24 Rev. 1, Steam Supply System Rupture The symptoms, immediate actions, followup actions and pre-cautions of procedure 2202.06 were compared to the approved guidelines. The current revision of this procedure (Rev. 3, dated February 21, 1980) is adequately responsive to the guidelines.
Procedures 2202.23 and 2202.24 include a require-ment to trip all reactor coolant pumps after the reactor has been tripped for greater than five seconds following initia-tion of safety injection caused by low reactor coolant system pressure.
This is based on item 1.a. of IEB 79-06C as modified by the approved guidelines.
(2) Training The inspector attended a classroom lecture given by the licensee on SBLOCA analysis and procedure guidelines and reviewed training records to verify that each licensed operator had attended a similar lecture. The inspector also reviewed records of SBLOCA procedure walk-throughs in the control room by each licensed operator with their immediate supervisor.
(3) Operator Interviews The inspector interviewed four licensed operators (including two senior operators) to determine whether they had an adequate knowledge of the SBLOCA analysis and procedures.
The follow-ing topics were included in these interviews:
. Diagnostic chart usage
.Importance of heat sinks
. Recognition of:
adequate core cooling core voiding inadequate core cooling natural circulation l
. Instrumentation abnormalities encountered during the TMI-2
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.SBL0CA Symptoms
. Conditions requiring the use of the Emergency Core Cooling
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System (ECCS) vents.
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. Hot leg injection
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Reason Flow measurement
. Protection of high pressure injection pumps after the Recirculation Actuation Signal (RAS)
. Control room indications of a primary safety valve being stuck open
. Reactor Coolant Pump Operation during a LOCA
. Heat sink after RAS
. Monitoring post-accident auxiliary building stack activity
.Immediate actions for steam supply system rupture
.Immediate actions for steam generator tube rupture
. Criteria for terminating high pressure injection
. Considerations for resetting Safety Injection Actuation Signal (SIAS)
.Immediate actions for SBLOCA
. Followup actions for SBLOCA The operators' knowledge level for the topics covered in the j
interviews was generally good with two exceptions. The j
operators interviewed were not familiar with the recently
installed system for post-accident high range auxiliary building stack effluent activity monitoring. The licensee
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i plans to conduct training in this and other recent design
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changes prior to startup from the current outage.
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weakness was knowledge of emergency procedure immediate actions.
j Two of the four operators interviewed could not correctly I
I state from memory all of the immediate actions required by emergency procedure 2202.24, Steam Supply System Rupture.
Three of the four operators could not correctly state from i
memory all of the immediate actions required by emergency procedure 2202.23, Steam Generator Tube Rupture. Two of the i
four operators interviewed could not correctly state from l
memory all of the immediate actions required by Section II of emergency procedure 2202.06, Loss of Reactor Coolant, Break Within HPSI Pump Capacity. The observed weak area of immediate
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action knowledge was discussed with the Assistant Operations Superintendent for Unit 2 and the Training Supervisor. These licensee representatives agreed to consider what methods could be used to improve operator knowlege in this area.
(0 pen Item 368/80-03-05)
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(4) Systems Considerations a.
Instrumentation
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The inspector reviewed the instrumentation needed to carry out operator actions in the SBLOCA procedure to ensure that the procedure is viable in this regard.
The instrumentation reviewed is listed below:
Steam Generator (SG) levels Reactor Coolant System (RCS) Pressure RCS Temperatures Margin to Saturation Containment Pressure Containment Spray Flow (see note 1)
Penetration Room Ventilation Flow (see note 2)
Penetration Room Pressure (see note 3)
SG Pressures ECCS Vent Valves (see note 4)
Emergency Feedwater Flow High Pressure Injection Flow (see note 5)
High Range Containment Area Monitors Safety Injection Tank Pressures Pressurizer Level Refueling Water Tank Level Notes:
1.
Not redundant, one flow channel per spray header 2.
Not redundant, one flow channel per penetration room ventilation train 3.
Not redundant, one pressure channel per penetration room 4.
The ECCS vent valves, 2CV-4697-2 and 2CV-4698-1 are in series in a line between the pressurizer steam space and containment atmosphere.
The power supplies for these valves are the green station bat' cry bus and the red station battery bus, respectively. Thus, loss of one station battery bus would cause loss of capability to use the ECCS vent valves.
Through the NRC/NRR Project Manager, the inspector learned that this arrangement is approved to ensure closure of the vent line when desired. This interim system is to be modified during the first refueling outage.
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(5) Not redundant, one flow channel is provided for each high pressure injection header and one flow channel is provided for each cold leg injection path, b.
PORV Position Indication ANO-2 has no PORV.
However, during the current outage, a system for direct position indication of the pressurizer code safety valves has been installed.
The alarm from this system, Pressurizer Relief Valve Open, has been added to the SBLOCA procedure as a possible symptom.
c.
RCS Loop Isolation Valves ANO-2 has no RCS loop isolation valves.
d.
Resetting SIAS The licensee has the following caution statement in procedure 2202.06:
"D0 NOT RESET SIAS AFTER BONA-FIDE ACTUATION UNTIL PIANT IS COOLED DOWN AND DEPRESSURIZED: PREMATURE RESETTING COULD RESULT IN LOSS OF ALL PREVIOUSLY ACTUATED COMPONENTS IN THE EVENT OF LOSS OF POWER UNTIL REACTUATED AND START TIME DELAYS HAVE ELAPED."
e.
Containment Isolation During the current outage, the licensee installed a design change which adds a SIAS signal to close the valves listed in Categories III and IV of Item 2.1.4 of the licensee's letter of January 18, 1980 to the NRC.
f.
Switchover from Injection to Recirculation At ANO-2, this switchover is automatic upon reaching a specified low level in the Refueling Water Tank.
g.
High Pressure Injection Pump Protection in the Recircula-tion Mode The licensee has the following caution statement in the SBLOCA section of procedure 2202.06:
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"HPSI FLOWRATES MUST BE MONITORED CLOSELY AFTER RAS RECIRC MOV CLOSURE TO PREVENT DEAD-HEADING A HPSI PUMP.
ENSURE AT LEAST 30 GPM IS INDICATED PER TRAIN; IF ONE TRAIN FALLS BELOW 30 GPM, SECURE THE RESPECTIVE HPSI PUMP ON RE-OPEN HPSI INJECTION M0V'S AS NECESSARY TO MAINTAIN MINIMUM FLOWRATE."
Due to the scale of the installed analog flow meters, it would be necessary for the operator to use the plant computer to obtain readings of HPSI header flow when flow is near 30 gallons per minute.
6.
10 CFR Part 21 Followup (Unit 2)
A.
Ruskin On January 21, 1980, the Ruskin Man..acturing Company reported a deficiency in their NIBD vertical type fire dampers.
Eight of these units were reported to have been sold to Arkansas Power and Light for use in Arkansas Nuclear One, Unit 2.
Upon followup of this item, the inspector learned that the deficiency was identified prior to shipment of the AP&L order.
AP&L has been informed by Ruskin that the dampers will have the recommended modification installed prior to shipment.
B.
Borg-Warner In Jenuary, 1980, McGuire Nuclear Station submitted a deficiency report on Borg-Warner three inch motor operated gate valves failing to fully shut. At ANO-2, the ECCS vent valves, 2CV-4698-1 and 2CV-4697-2, are the type identified in the report.
The Plant Safety Committee, on February 12, 1980, determined that continued use of these valves at ANO-2 without modifica-tion was acceptable since the valves are used in a different application at ANO than at McGuire and would not be called upon to close against a large differential pressure.
In a letter to AP&L dated February 12, 1980, Borg-Warner included the following statement:
"This letter is written to certify that the subject valves will operate from the closed to open position at any differentialpressureuptoamaximumof2485psiat 658 F.
The subject valves will also operate from the open to closed position at any differential pressure up to a maximum of 1320 psi at 600 F."
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10 CFR Part 21 Followup (Unit 1)
On August 27, 1979, the G. H. Bettis Company supplied the NRC with a list showing:
"All the ASCO solenoid valves which have been furnished as accessories on GH-Bettis actuators mounted on Henry Pratt Company butterfly valves supplied to nuclear power plants for containment or related service in which the environmental conditions may exceed the ratings for the solenoid valve plastic parts."
The valves listed for ANO-1 were CV-7401 and CV-7402.
These valves are the isolation valves on the containment purge lines outside of containment.
Thus their actuators would not be subjected to adverse post-LOCA environmental conditions.
8.
Maintenance (Units 1 and 2)
The inspector reviewed the licensee's maintenance program by selectively examining Quality Control Procedures, Administra-tive Procedures, completed Job Orders and Trouble Reports, supporting logs and records to determine:
a.
That during maintenance on satety-rela ed systems all
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license limiting conditions for operation were met.
b.
That maintenance activities on safety-related systems were properly documented.
That maintenance procedures were technically adequate.
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That reporting requirements for selected maintenance activities had been met, if applicable.
No items of noncompliance or deviation were identified.
9.
Inspector Witnessing of 100% Plateau Testing (Unit 2)
During this inspection, the inspector witnessed the performance of six tests at the 100% power plateau. The test witnessed were:
2.300.01 Appendix R Variable Tavg.
2.800.01 Appendix GG PLCEA Xenon Control 2.800.01 Appendix E Nuclear and Thermal Calibration
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2.800.01 Appendix I NSS Calorimetric 2.800.01 Appendix RR 100% Turbine Trip 2.800.01 Appendix U Unit Load Transient Test The following items were verified by the inspector during the performance of these tests:
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. Latest procedure revision in use
. Minimum crew requirements met
. Test prerequisites and initial conditions met
. Test equipment calibrated
. Procedure is adequate
. Crew actions correct and timely
. Adequate test coordination
. Test data assembled for analysis
. Acceptance criteria met (preliminary)
. Licensee's preliminary evaluation is adequate 10.
100% Turbine Trip (Unit 2)
While conducting a turbine trip test from 100% reactor power on January 29, 1980, in accordance with procedure 2.800.01, Appendix RR, an atmospheric steam dump valve downstream of the main steam isolation valves failed to close. Additionally, the pressurizer spray valve failed to shut completely. The rapid cool down and depressurization which followed resulted in the automatic initiation of the safety injection system.
The dump valve was manually closed after approximately 5 minutes and a plant recovery followed.
Pressurizer level indication was lost for approximately 4 minutes.
The lowest plant pressure achieved was approximat'ely 1330 psig and the minimum plant temperature was 510 F (Hot Leg Temperature).
A resident NRC inspector was in the control room throughout the event.
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The licensee's letter of February 5,1980, to NRC Region IV, described the transient; the spray valve failure and proposed corrective action; the atmospheric dump valve failure and interim administrative ccatrols; and the intent to perform a 20% turbine trip test following the current outage.
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The NRC Region IV letter of February 6, 1980, to AP&L indicated
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NRC Region IV concurrence for operation beyond Mode 3 would be based on satisfactory completion of the following items:
"At least one pressurizer spray valve will be modified by installation of a Limitorque motor actuator prior to start up and that testing will be performed prior to going beyond Mode 3 operation.
Until further modifications to improve operation of the steam dump valves are made, 2CV-0301, 2CV-0305, 2CV-1001, and 2CV-1051 will be operated manually during power operation and will be controlled administratively."
Design Change Package (DCP)-D-2017 has been implemented by the licensee. This change replaced the Borg-Warner operators on 2CV-4651 and 2CV-4652 with Limitorque electric operators, type SMB 000. The design provides for manual or automatic control of the pressurizer spray valves from panel 2CC4 in the control room and for manual control from the Remote Shutdown Panel, 2C80. The inspector reviewed this DCP and job orders 3542B and 3542C which performed the Limitorque operator checkouts and the bistable controller checkout, respectively. The inspector also reviewed the following procedures to verify that appropriate revisions had been made to reflect this design change:
2107.01 Rev. 1 Electrical System Operations
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2202.29 Rev. 1 Pressurizer Systems Failures 2202.33 Rev. 2 Remote Shutdown 2102.02 Rev. 3 Plant Startup Revision of procedure 2103.05, Pressurizer Operations, and
performance of a functional test of the spray valves in Mode 3 remain to be done.
The mode control switches for 2CV-0301, 2CV-0305, 2CV-1001, and 2CV-1051 have been placed in "0FF."
Caution tags with the following notation have been attached to the mode control
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switches:
" Leave permissive switch in off during normal operation.
May be used when bypass valves are unavailable."
11.
Inspector Review of Test Data (Unit 2)
During this inspection, the inspector reviewed certain tests performed at the 80% power level plateau.
Items considered in this review included resolution of test deficiencies, licensee evaluation of test results, acceptability of test data and administrative control of testing.
Test reviewed during this inspection included the following:
Test Title 2.800.01 Appendix L Process Variable Intercomparison 2.800.01 Appendix M Chemistry and Radiochemistry Test 2.800.01 Appendix P Core Performance Record 2.800.01 Appendix R Variable Tave 2.800.01 Appendix DD Dropped CEA 2.800.01 Appendix GG PLCEA Xenon Control Appendix L was performed in December,1979, at 80% power.
This test compares process instrumentation readings obtained from the plant computer, the plant protection system, the core protection calculators, and console meters to verify proper agreement between systems. The inspector identified no test deficiencies which had not already been identified by the licensee.
Appendix M was performed in November,1979, at 80% power.
This test involves the recording of RCS chemistry and radio-chemistry data and comparing results with the process radiation i
monitor for correlation. The inspector reviewed the data and found no deficiencies.
i Appendix P was performed in December,1979, at 80% power with equilibrium Xenon. The test included measurement of core radial power distribution and axial power distribution.
Test data was obtained in an INCA verification file which
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was transmitted to Combustion Engineering for use in the CECOR code to obtain the power distributions.
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These measured distributions were then compared to the pre-dicted values. The inspector performed independent comparison calculations for the axial and radial power distributions and confirmed the results obtained by the licensee.
Appendix R was performed in January,1980, at 80% power.
This test determined the isothermal temperature coefficient and the power coefficient. From these two, the moderator temperature coefficient was calculated.
The inspector performed independent comparison calculations on a sample of the data and confirmed the results obtained by the licensee.
Appendix DD was performed in January,1980, at 50% power.
This test measured the power distributions following a dropped CEA and compared the results to computer predicted values. The inspector reviewed the data and found no deficiencies.
Appendix GG was performed in January, 1980, at 65% power.
The test consisted of a demonstration of a technique for damping Xenon oscillations with partial length CEA's (PLCEA's). The inspector reviewed the data and found no deficiencies.
12.
Authorization to Raise Power (Unit 2)
The inspector reviewed the licensee's evaluation of the 80%
power plateau test results and his authorization to proceed
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to the next test plateau (100%). The Plant Safety Committee (PSC) and the Test Working Group (TWG) met jointly on
January 18 and 19, 1980. The following tests were reviewed and discussed:
2.800.01 Appendices A, B, E, I, J, L, M, P, Q, R, U, AA, CC, DD, GG, LL, QQ, XX, KK 2.800.03 2.800.04 2.800.05 2.800.06 2.800.07 2.800.10 2.800.12 2.800.13
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The PSC found the results of these tests to be acceptable or, in the case of discrepancies, not to be a restraint upon further power escalation. Authorization was given to proceed to the 100% power test plateau.
13.
Review of Plant Operations (Units 1 & 2)
The inspector reviewed plant logs and records to verify con-formance to plant procedures and to confirm that Technical Specifications were met.
The inspector also conducted a plant tour of accessible areas which included Unit I reactor bdilding, cable spreading room and the reactor auxiliary building to observe general housekeeping and to verify selected component configurations. The inspector also reviewed the records for performing fire protection inspections.
The following logs and records for the fourth calendar quarter 1979 were reviewed in part. Also, the current inplant logs were reviewed.
Station Log - Operations Station Battery Daily Check Shift Instructions (Night Orders)
Jumper and Bypass Log Shift Turnover Log Radiochemistry Log Hot Lab Technical Surveillance Report Daily Hot Lab Water Report Caution Tag Log Hold Card Log Auxiliary Log CPC/CEAC Auto Restart and Sensor Failure Log (Unit 2 only)
CEA Position Log (Unit 2 only)
During the tour of the reactor building and reactor auxiliary building it was noted that there was an excessive amount of construction materials and anti "C's" throughout both areas.
The licensee stated these areas would be cleaned prior to startup of the reactor.
The following general observations were made during the plant tour.
.No excessive fluid leaks or piping vibrations were observed.
. Seismic restraints and pipe hangers appeared to be in satisfactory condition.
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. Selected valves were observed to be in the required positions.
. Selected equipment caution and hold tags were verified to be correct.
. Control room operators were knowledgeable in annunciator status.
. Selected recorders were recording properly.
. Control room manning was in accordance with Technical Specifications.
. Fire extinguishers were unobstructed and had been recently inspected.
. Shift turnover was satisfactory.
During the tour of the Unit I reactor auxiliary building, the inspector noted that door 194 to the Unit 1 North Piping Penetration Room was unlocked and open. The North Piping Penetration Room was a posted high radiation area with accessible whole-body radiation in excess of 700 millirems per hour, and therefore door 194 was required by 10 CFR Part 20.203(c) to be ".
equipped with a control device
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which shall energize a conspicuous visible or audible alarm signal in such a manner that the individual entering the high radiation area and the licensee or a supervisor of the activity are made aware of the entry; or.
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locked except during periods when access to the area is required, with positive control over each individual entry."
Door 194 was not equipped with an alarm system and positive entry control did not exist. This an apparent item of noncompliance. (313/80-03-01).
14.
Exit Interviews The inspectors met with Mr. J. P. O'Hanlon (Plant General Manager) and other members of the AP&L staff at the end of various segments of this inspection. At these meetings, the inspectors summarized the scope of the inspection and the findings.
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