IR 05000245/1979010
| ML19256E290 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 09/14/1979 |
| From: | Conte R, Mccabe E, Shedlosky J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML19256E287 | List: |
| References | |
| 50-245-79-10, 50-336-79-13, NUDOCS 7911020057 | |
| Download: ML19256E290 (37) | |
Text
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i U. S. NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT
REGION I
50-245/79-10 Report No.
50-336/79-13 50-245 Docket No.
50-336 DPR-21 Ln.ense No.
OPR-65 Priority
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Category s
Licensee:
Northeast Nuclear Energy Company
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P. O. Box 270 Hartford, Connecticut 06101 Facility Name:
Millstone Nuclear Station Units 1 and 2 Inspection At:
Waterford, Connecticut
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Inspection Cond cted:
May 1 through June 1, 1979 9 t/ 79 Inspectors:
FOA
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S osky, Resident Inspector date g J. Cofith, Reactor Inspector 7Adn
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date Approved by:
C.k kMh 9 ff 9I79 E. C. McCabe, Jr., Chief, Reactor Projects date Section No. 2, RO&NS Branch Inspection Summary:
May 1 through June 1, 1979 (Combined Report. 50-245/79-10 and 50-336/79-13)
Areas Inspected:
Routine, onsite regular and backshift inspection by the resident inspector and one region-based inspector (17.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> Unit 1; 152 hours0.00176 days <br />0.0422 hours <br />2.513228e-4 weeks <br />5.7836e-5 months <br /> Unit 2).
Areas inspected included the licensee actions taken to address the require-ments of IEB 79-06B, Review of Operational Errors at Three Mile Island Unit 2 on March 28; the accessible portions of the Unit 1 drywell reactor, turbine, radio-active waste and intake buildings, the Unit 2 primary containment, auxiliary, tur-bine and intake buildings; radiation protection; physical security; fire protection; plant operating records; surveillanca testing; maintenance and core alterations.
Results:
No items of noncompliance were identified.
1257 744 Region I Form 12 (Rev. April 77)
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DETAILS 1.
Persons Contacted The below listed technical and supervisory level personnel were among those contacted:
J. M. Black, Superintendent, Unit 3 P. Callaghan, Unit 1 Maintenance Supervisor F. Dacimo, Station QC Supervisor E. C. Farrell, Superintendent, Unit 2 M. Griffin, Station Security Supervisor H. Haynes, Unit 2 Instrumentation and Control Supervisor R. Herbert, Superintendent, Unit 1 J. Kelly, Unit 2 Operations Supervisor E. J. Mroczka, Superintendent, Plant Services J. F. Cpeka, Station Superintendent R. Place, Unit 2 Maintenance Supervisor P. Przekop, Unit 1 Engineering Supervisor W. Romberg, Unit 1 Operations Supervisor S. Scace, Unit 2 Engineering Supervisor F. Teeple, Unit 1 Instrumentation and Control Supervisor 2.
Review of Actions on IE Bulletin 79-068, " Review of Operational Errors and System Misalignments Identified During the Three Mile Island Incident" By letter dated April 14, 1979, the NRC transmitted IE Bulletin 79-06B to the licensee.
The bulletin specified actions to be taken to avoid an event similar to the one which occurred at Three Mile Island Unit 2 on March 28, 1979. By letter dated April 24, 1979 the licensee provided their response. That response was supplemented by letters dated May 24 and 31. NRC evaluation of the licensee's response is documented in an Evaluation Report dated June 7, 1979.
The Resident Inspector reviewed station adminstrative controls to verify the implementation of the licensee's actions.
This review consisted of interviews and discussions with licensed reactor operators and plant equipment operators, inspections of system valve lineups, verification of system drawings to as built conditions, and the review of operational, administrative and surveillance procedures.
a.
Onsite Review of Operator Training Training discussions were conducted at the station on April 20 and 21 by au NRC staff team.
This review was directed toward under-standing:
(1) the extreme seriousness and consequences of the 1257 H5
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simeitaneous blocking of both auxiliary feedwater trains at the Three Mile Island Unit 2 plant and other actions taken during the early phases of the accident; (2) the apparent operational errors which led to core damage; (3) that the potential exists, under certain accident or transient conditions, to have water level indicated in the pressurizer when the reactor vessel is not full of water; and (4) the necessity of systematically analyzing plant conditions and parameters and of taking appropriate corrective action.
The training discussion was attended by all licensed operators and plant managers with the exception of one individual.
The same training was provided on May 3,1979 for that individual by the N'lC Resident Inspector.
Training sessions were conducted by the Unit 2 Operations Supervisor on April 24 and May 4 for all licensed operators and for plant management with operations responsibilities.
That training discussed: design differences between the B&W and CE designs, the order of events and possible operator errors occurring at TMI-2, the seriousness of blocking both channels or trains of a redundant system, the conditions which could lead to misleading pressurizer level indication, and the necessity for analyzing plant conditions and taking appropriate corrective actions.
Additionally, plant operating requirements which were changed or re-emphasized in the form of changes to procedures were presented.
Reco'ds of lesson plans and attendance were available to the inspector.
Tb Resident Inspector conducted additional interviews with fourteen of the twenty licensed operations shift personnel.
These interviews were conducted on May 9 and verified the following:
(1) That operators have received training on any procedure changes initiated as a result of Bulletin 79-06 ard 79-06B.
(2) That operators have been instructed on the specific measures which provide assurance that engineered safety features would be available if required, in particular, measures for returning such systems to operable status following maintenance and testing.
(3) That operators have been instructed on the s "cific and detailed measures to assure that automatic actuations of emergency safety features are not overridden except as permitted in the bulletin.
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(4) That operators have reviewed plant automatic actions initiated by reset of engineered safety features that could affect the control of radioactive liquids and gases.
(5) That plant operators and supervisory personnel have been in-structed in the provisions and directives for early NRC notifi-cation of serious events.
The resident inspector verified during these discussions that plant operators were aware of the requirements of:
(1) the criteria for operation of reactor coolant pumps stated in OP2506, Loss of Coolant Incident, Revision 4 and OP2509, Main Steam Line Rupture, Revision 3, (2) methods for determination of 50 degrees subcooling required prior to securing the HPSI pumps stated in OP2506, OP2509 and OP2515, Steam Generator Tube Rupture, Revision 4.
These procedures were evaluated by the inspectors and the results stated in paragraph 2.h of this report.
b.
Onsite Inspection of Encineered Safety Features Reviews of system alignment procedures were conducted for all safe-guards systems using current Piping and Instrument Drawings (P&ID).
This was accomplished through the use of the following drawings:
25203-26005, Revision 8, Condensate and Feedwater
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25203-26008, Sh 1/2 Revision 3/0, Circulating and Service Water
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25203-26010, Revision 0, Fuel Oil Systems
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25203-26015, Revision 1, Safety Injection and Containment Spray
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25203-26017, Revision 3, Chemical and Volume Control
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25203-26018, Revision 4, Diesel Generator Cooling, Starting Air
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and Lube Oil n
25203-26022,~Sh 1/2, Revision 2/2, Reactor Building Closed
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Cooling Water 25203-26027, Sh 2, Revision 1, HVAC Turbine Building
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25203-26028, Sh 1/2, Revision 1/1, Containment and Enclosure
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Building Ventilation 12c, vg]
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The status of outstanding drawing changes was reviewed.
Using this information, the following process flow paths were identified.
Auxiliary Feed Water System - Flow paths from condensate storage
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tank through auxiliary feedwater pumps and to the stream gener-ators, steam supply and steam line drains of steam driven auxiliary feedwater pump, condensate storage tank recirculation pump and heat exchanger, all instrument stops and piping vents and drains.
Service Water - Flow paths from the plant intake through service
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water pumps to RBCCW heat exchangers, diesel generators, vital AC switchgear room coolers and HVAC chillers, instrument stops and pressure control valves, and header cross tie valves.
Diesel Generator Fuel Oil - Flow from Supply Tanks to Diesel
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Engine including header cross ties; Diesel Generator Starting Air - Flow from air compressors to the starting air tanks to the diesel engines including supply from station air and cross tie valves.
Safety Injection - From Refueling Water Storage Tank (RWST) to
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Low Pressure Safety Injection Pumps, High Pressure Safety Injection Pumps, Containment Spray Pumps to their injection points or through heat exchangers to the spray headers including instrument stops, the Safety Injection Tanks to their injection points including nitrogen supply and tank instrument stops, and the RWST recirculation pump and heat exchinger.
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Chemical and Volume Control - From the Boric Acid Storage Tanks to the Charging Pump Suction and to the charging injection points via the gravity feed and the boric acid pump feed paths.
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Reactor Building Closed Cooling Water - The closed loop from pump suction headers through pumps, heat exchangers and components back to pump suction headers for the following components:
Shutdown heat exchangers, engineered safety features room air cooling coils, seal coolers for high and low pressure safety injection pumps and containment spray pumps and containment air recirculation cooling.
Valves and other equipment were identified which could effect system operation along these flow paths.
Notation was made of piping which could short cycle or otherwise reduce the intended fluid flow.
Valve alignment procedures were audited to verify system operability for Operating License Technical Specification requirements in Modes 1, 2 and 3.
The inspectors verified that this information was correctly stated on the following procedure check off lists:
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2308-1, High Pressure Safety Injection, Facility I, Revision 6,
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cated May 4, 1979, 2308-2, High Pressure Safety-Injection, Facility II, Revision
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1, dated May 4, 1979, 2309-1, Containment Spray, Facility I, Revision 3, dated June
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24, 1976, 2309-2, Containment Spray, Facility II, Revision 1, dated June
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24, 1976, 2310-1, Shutdown Cooling, Facility I, Re.<ision 3, dated September
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26, 1978, 2310-2, Shutdown Cooling, Facility II, Revision 2, dated September
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26, 1978, 2322-1, Auxiliary Feed Water, Revision 2, dated May 11, 1978,
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2326A-1, Service Water, Facility I, Revision 4, dated May 4,
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1979, 2326A-2, Service Water, Facility II, Revision 2, dated May 4,
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1979,
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2330A-1, Reactor Building Closed Cooling Water, Facility I, Revision 5, dated May 4, 1979,
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2330A-2, Reactor Building Closed Cooling Water, Facility II, Revision 3, dated May 4, 1979, 2304A-2, Placing the CVCS in Operation from VCT to Reactor
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Coolant Loops, Facility I, Revision 1, dated March 15, 1978, 2304A-3, Placing the CVCS in Operation from VCT to Reactor
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Coolant Lnops, Facility II, Revisien 1, dated March 15, 1978, 2304C-1, Placing the Boric Acid System in Operation, Facility
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I, Revision 5, dated April 6, 1979, 2304C-2, Placing the Boric Acid System in Operation, Facility
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II, Revision 2, dated April 6, 1979, 2306-1, Safety Injection Tanks #1 and #2, Facility I, Revision
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6, dated November 22, 1978,
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2306-2, Safety Injection Tanks #3 and #4, Facility II, Revision
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2, dated December 11, 1978, 2307-1, Low Pressure Safety Injection, Facility I, Revision 4,
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dated January 15, 1979, 2307-2, Low Pressure Safety Injection, Facility II, Revision 1,
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dated January 15, 1979, 2346A-1, Diesel Generator, Facility I, Revision 5, dated December
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8, 1978, 2346A-3, Diesel Generator, Facility II, Revision 5, dated
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December 12, 1978, 2345B-1, Diesel Generator Fuel Oil, Facility I, Revision 4,
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dated January 8, 1979,
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2346B-2, Diesel Generator Fuel Oil, Facility II, Revision 1, dated January 8, 1979, 2350-1, Refueling Water Storage Tank and Containment Sump,
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Revision 3, dated December 19, 1978, 2350-2, Refueling Water Storage Tank and Containment Sump,
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Revision 1, dated December 19, 1979.
Using those procedures, the inspectors verified that the systems were correctly lined up to support plant operations in accordance with the Operating License Technical Specification requirements for Modes 1, 2 and 3.
Operability of motor and air operated valves was verified by checking that control power was available to the valve.
Availability of an air supply to air operated valves was checked where possible.
During the conduct of valve lineup verifications applicable portions of Piping and Instrument Drawings were compared to systems as built.
At the completion of the system valve lineup verification, the inspectors found no instances in which the as found position of a valve was not the same as the position recorded on the latest system valve lineup.
There were no instances in which the as found position of valves and components caused the system not to meet the requirements of the Operating License Technical Specifications for Modes 1, 2 and 3.
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The following discrepancies were notM with reference to the Piping and Instrument drawings:
(.1) Auxiliary Feedwater System - Auxiliary feedwater motor driven pump suctio,. instrument root stops are indicated open on the P&ID (25203-26005).
These stops are for temporary local instru-montation and are called out as closed on valve lineups (2322-1)
as the instrument may not be installed or in use.
(2) Reactor Building Closed Cooling Water - The P&ID (25203-26022)
indicates that the "B" RBCCW pump and heat exchanger are in stand-by, isolated from the "A" and "B" headers.
The system lineup (2330A-1) places the pump and heat exchanger on the "A" header along with the "C" RBCCW oump and heat exchanger by having valves 2-RB-211C, "C" RBCCW Pump Suction Valve and 2-RB-4.lC, "" RBCCW heat exchanger discharge valve both open.
(3) Diesel Generator Fuel Oil - Diesel generator engine fuel oil supply header cross tie valves are indicated as locked closed on the P&ID (25203-26010) but simply as closed on the valve lineup (2346B-1).
(4) Service Water - Service Water discharge from the Vital AC Switchgear room coolers (2-SW-192) and from the HVAC chillers (2-SW-197) a.a flapper valves and are identified correctly in the valve lineup (2326A-1).
The P&ID (25203-26008) has these valves incorrectly shown as check valves.
These discrepancies were identified to the licensee and are carried as an open item (336/79-13-01).
The licensee's action will be followed up during a future inspection.
The followir.g discrepancies were noted with reference to the system valve 1 4eup check off lists.
(1) 2104C-1, (C-2), Placing the Boric Acid System in Operation, page 3, Valves 2-CH-196, Blended Makeup to RWST and 2-CH-192, RWST to Charging Pump Suction. These valves are identified as hand operated, they have been modified to include an air operator to allow remote operation from control room panel CO-2.
Valve 2-CH-192, RWST to charging header isolation, is listed on 2304C-1, page 3, 2304C-2, page 4, as normally open. Because of the addition of the remote operator the valve is kept closed.
This has been corrected.
The valve list has been revised to reflect the plant design in Revision 5, Change 1, dated May 14, 1979.
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(2) 2306-1, Safety Injection Tank, page I, Valves 2-SI-800, Nitrogen to SIT, Containment isolation; 2-SI-802, SIT Nitrogen header vent and 2-SI-801, Nitrogen to SIT header stop. All have faulty valve numbers. (This has been corrected in valve list, Revision 6, Change 1 dated May 7, 1979.)
(3) 2309-1, (-2), Containment Spray page 2, Valves 2-51-657, Shutdown Cooling Heat Exchanger return to the Reactor Coolant System valve operating position is not listed on the check off list for the standby mode.
(4) 2322.-1, Auxiliary Feedwater, page 2, valve 2-FW-44, Auxiliary Feedwater Pump Discharge Cross Tie is listed on the valve check off list as normally closed. Operations personnel normally maintain the system in standby with this valve open.
This has
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beer. corrected, the valve list has been revised to require the valve to be normally open on revision 2, Change 2, dated June 12,1979.) On page 3, the following valves associated with the Turbine Driven Auxiliary Feedwater Pump were not listed on the valve checkoff:
2-MS-343, steam header trap isolation; 2-MS-344, Turbine drain; 2-MS-345, steam header trap isolation; 2-MS-256, turbine third stage drain. These valves were noted to be positioned to support turbine operation:
2-MS-343 - Open, 2-MS-344 -
Closed, 2-MS-345 - Open, and 2-MS-256 - Open.
(5) 2326A-1, (A-2), Service Water Systems Facility 1(2), page '
Valve 2-SW-88, "B" RBCCW heat exhanger service water inlet stop, is required to be closed by the Facility 1 valve check off list (2326A-1) but open on the Facility 2 valve check off list (2326A-2).
The valve was in the open position, which cupported system operation.
Page 4, Valves 2-SW9A, 98, 9C, and 90, A-D RBCCW heat exchanger service water outlet are required to be open on the valve checkoff lists. The valves were actually throttled to support plant operations.
Valves 2-SW-12A and C, "B" Service water to the "A" and "B" diesel generator heat exchangers, and valves 2-SW-12 "B" and
"D", "A" Service water to the "A" and "B" diesel generator heat exchangers. These valves are actually locked in position as required by the Diesel Generator valve checkoff lists (2346A-1 and A-3).
The service water valve check off lists do not require locking the valves in position. This has been corrected.
The service water valve list has been revised to require the valves to be locked in position, in revision 2, Change 1, dated June 12, 1979.)
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(6) 2330A-1, (A-2), Reactor Building Closed Cooling Water (RBCCW)
System, page 1, 2, Valves 2-RB-28.1 "A", "B", "C" and "0" and 2-RB-28.2 "A", "B", "C" and "D", Containment Air Recirculation Cooler "A", "B", "C" and "D", RBCCW inlet and normal outlet isolation.
Required positions for these valves are inconsistent between lineups.
Air operated inlet isolation valves (2-RB-28.1
"B" and "0") for coolers "B" and "D" are locked open, for coolers "A" and "C" the valves (2-RB-28.1 "A" and "C") are not locked.
The air operated normal outlet isolation valves (2-RB-28.2
"B" and "0") for coolers "B" and "0" are positioned open, for coolers "A" and "C" the valves (2-RB-28.2 "A" and "C") are throttled open.
Page 8, valve 2-RB-148, Shutdown cooling heat exchanger "B",
RBCCW Outlet isolatior, valve required to be throttled and locked had a typographic error on the valve checkoff list (2330A-2) of "AT".
The valve was positioned correctly.
The above list is an open item (336/79-13-02). Licensee action will be reviewed during a future inspection.
During the verification of valve alignment, the following material items were noted.
(1) Auxiliary Fuel Water - Valve 2-CN-267B, Condensate Storage Tank Recirculation Pump Discharge Vent Valve was labeled 2-CN-267A.
(2) Low Pressure Safety Injection, Valve 2-SI-142, LPSI header 28 Flow Instrument Stop Valve, handle is stuck in pipe insulation and cannot be operated.
(3) The following valves are not labeled.
Refueling Water Storage Tank (RWST):
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2-CS-027, RWST Recirculation Pump heat exchanger outlet valve 2-CS-037, RWST R6-eulation oump heat exchanger bypass
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valve 2-CS-106, RWST level transmitter 3004 stop valve
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Service Water:
2-SW-108, "B" RBCCW heat exchanger to A discharge header
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isolation valve 1257 253
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2-SW-136A, "B" Service Water Pump lubricating water isolation
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valve The above list is an open item (336/79-13-03). Licensee actions will be reviewed during a future inspection.
c.
Administrative Controls for Engineered Safety Feature System Return to Service (1) Administrative Controls, specifically in the area of procedure format requirements, were reviewed to assure that Engineered Safety Feature (ESF) Systems were properly " returned to service" following test and maintenance activities.
(2) The following documents were reviewed.
ACP-QA-9.02, Plant Surveillance Program, Revision 5,
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November 13, 1978 ACP-QA-3.02, Station Procedures and Forms, Revision 9,
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April 24, 1979 ACP-QA-2.02, Performing Category I Work. Revision 14,
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April 24, 1979 ACP-QA-2.02B, Retests, Revision 4, April 24, 1979
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ACP-QA-2.03, Performing Non-Category I Work, Revision 6,
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April 24, 1979 ACP-QA-2.08, Preventive Maintenance, Revision 2, April 24,
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1979 ACP-1.07, Communications and Outside Assistance Procedure,
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Revision 12, April 24, 1979 (3) During this review, it was noted that administrative controls did not specifically address ESF system return to operability after an extended outage.
However, an informal program of checklists were developed to support a startup after an extended outage.
These checklists consolidated the completion of modal dependent surveillance tests and the completion of valve lineups to assure systems are in standby or startup modes.
Extensive use of these checklists was noted to support the Unit 2 Startup which was conducted during the inspection.
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The inspector stated that this was fact gathering information and had no further comments in this area.
(4) No items of noncompliance were identified, however, one unre-solved item was disclosed.
In response to Office of Inspection and Enforcement Bulletin 79-06 and 79-068, the licensee revised the General Periodic Test Procedure Format (Figure 7.5) Section of ACP 3.02 to strengthen " Return to Service" requirements including notification of Operations Personnel.
The inspector noted that this revision had applicability to the Surveillance Test Format (Figure 7.7) which was not revised similarly.
The licensee stated that Figures 7.4 and 7.7 would be revised to reflect the similar revision to Figure 7.5.
This item is unresolved pending completion of action..and subsaquent NRC:RI review (336/79-13-04).
d.
Surveillance / Maintenance Procedure - Return to Operable Condition (1) Surveillance Tests including Calibration Procedures and Main-tenance Procedures were reviewed to verify that provisions exist to return systems to an operable condition following test or maintenance activities.
This also verified implementation of administrative controls addressed in the previous paragraph.
(2) The following documents were reviewed.
SP 2401C, RPS Turbine Loss of Load Test, Revision 0,
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January 4, 1979 SP 2402A, Reactor Coolant Flow, Revision 0, January 4,
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1979 SP 24028, Pressurizer Pressure Transmitter, Revision 1,
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January 4, 1979 SP 2402C, Steam Generator Pres:.are, Revision 0, January 4,
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1979 SP 2402D, Steam Generator Level, Revision 0, March 28,
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1979
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SP 2402E, Pressurizer Level Indication, Revision 0, February 16, 1979 SP 2402F, Remote Shutdown Panel Steam Generator Pressure
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Calibration, Revision 1, June 20, 1978 1257 755
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SP 2402G, Reactor Coolant Cold Leg Temperature Instrument
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Calibration, Revision 0, January 31, 1979 SP 2402H, Pressurizer Pressure Instrument - Low Range,
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Revision 0, May 22, 1978 SP 24030, Containment Pressure, Revision 0, May 31, 1978
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SP 2403E, Refueling Water Storage Tank Level, Revision 0,
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December 22, 1978 SP 2403F, Hydrogen Recombiner Instrument Calibration,
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Revision 0, May 31, 1978 IC 2416A, Turbine Trip Pressure Switch Test, Revision 0,
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January 31, 1979 IC 24188, Calibration of Reactor Coolant Temperature
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Instrumentation, Revision 0, January 4, 1979 IC 24180, Pressurizer Level Contrcl Calibration, Revision
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0, December 14, 1977 SP 2601A, Borated Water Source and Flow Path Verification
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and Boric Acid Pump Operability Test, Revision 3, Change 1, October 3, 1978 SP 2601B, Borated Water Source Flow Path Verification
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-Monthly, Revision 1, June 26, 1975 SP 2601C, Boric Acid System Valve Operability Test (Shutdown),
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Revision 0, July 3, 1975 SP 2601G, Facility I Charging Pump Operability Test,
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Revision 1, March 18, 1976 SP 2601H, Facility II Charging Pump Operability Test,
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Revision 1, March 18, 1976 SP 2602A, Reactor Coolant Leakage, Revision 1, January 20,
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1977
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SP 2602C, Reactor Coolant System Leak Test / Hydrostatic Test, Revision 2, October 23, 1978
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SP 260SA, Safety Injection Tank (SIT) Isolation Valve
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Test - Safety Injection Actuation Signal (SIAS), Revision 1, August 19, 1976 SP 2603B, Safety Injection Tank (SIT) Isolation Valve
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Test (Pressurizer Pressure), Revision 1, March 30, 1976 SP 2604A, Facility I High Pressure Safety Injection
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(HPSI) Pump Operability Test, Revision 2, December 11, 1978 SP 26048, Facility II High Pressure Safety Injection
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(HPSI) Pump Operability Test, Revision 2, December 11, 1978 SP 2604C, Facility I !ow Pressure Safety Injection
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(LPSI) Pump Operabili.'.y Test, Revision 2, November 22, 1978 SP 2604D, Facility II Low Pressure Safety Injection
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(LPSI) Pump Operability Test, Revision 1, March 30, 1976 SP 2604E, High Pressure Safety Injection (HPSI) System
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Alignment Check and Valve Operability Test - Facility I, Revision 2, December 26, 1978 SP 2604F, HPSI Alignment Check Operability Test -
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Facility II, Revision 2, February 20, 1979 SP 2604G, Facility I Containment (CTMT) Sump Outlet
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Isolation Valve Operability Test, Revision 2, December 26, 1978 SP 2604H, Facility II Containment (CTMT) Sump Outlet
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Isolation Valve Operability Test, Revision 2, December 26, 1978
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SP 2604I, ESAS Automatic Logic Check Using ATI, Revision 1, December 27, 1977
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SP 2604L, Low Pressure Safety Injection (LPSI) System Alignment Check and LPSI/ Safety Injection Tank (SIT)
Valves Operability Test - Facility I, Revision 1, May 15, 1976
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SP 2604M, Low Pressure Safety Injection (LPSI) System
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Alignment Check and LPSI/ Safety Injection Tank (SIT)
Valve Operability Test - Facility II, Revision 1, June 15, 1976 SP 2604N, ECCS Valve Operability Test, Revision 1,
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January 31, 1979 SP 2604P, ESF Equipment Response Time Testing,~ Revision
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1, October 24, 1978 SP 2604Q, ECCS Flow Verification Surveillance Test,
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Revision 1, January 31, 1979 SP 2604R, Safety Injection Actuation Signal (Manual),
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Revision 0, December 7, 1977 SP 2605A, Verifying Containment Integrity, Revision 1,
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September 22, 1975 SP 2605E, Containment Personnel Airlock Leak Test,
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Revision 2, March 1, 1979 SP 2605F, Leak Test of Containment Fersonnel Access
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Door Gaskets, Revision 2, March 5, 1979
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SP 2605G, Containment Isolation Valve Operability
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Test -Operating, Revision 1, August 13, 1975 SP 2606A, Facility I Containment Spray (CS) Pump Opera-
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bility Test, Revision 2, May 2, 1978 SP 2606B, Facility II Containment Spray (CS) Pump
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Operability Test, Revision 2, May 2, 1978 SP 2606C, Facility I Containment Spray System Alignment
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and Operability Test, Revision 1, June 29, 1976 SP 2G06D, Facility II Containment Spray System Alignment
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and Operability Test, Revision 1, June 29, 1976 SP 2606E, Containment Spray Nozzle Flow Verification,
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Revision 1, June 29,1976 or'
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SP 2606F, Containment Spray Actuation Signal Manual
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Pushbutton Test, Revision 0, December 7, 1977 SP 2607A, Facility I containment Air Recirculation and
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Cooling Unit Operability Test, Revision 2, April 11, 1978 SP 26078, Facility II Containment Air Recirculation and
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Cooling Unit Operability Test, Revision 2, April 11, 1978 SP 2608A, Hydrogen Recombiner Operability Test - Operating,
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Revision 1, August 15, 1975 SP 2608C, Post Incident Recirculation System Operability
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Test Facility I, Revision 0, January 9, 1975 SP 26080, Post Incident Recirculation System Operability
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Test Facility II, Revision 0, January 9, 1975 SP 2608E, Hydregen Purge System Operability, Revision
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1, August 25, 1975 SP 2609A, Facility I Enclosure Building Filtration and
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Control Room Ventilation Operability Test, Revision 2, November 8, 1978 SP 26098, Facility II Enclosure Building Filtration and
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Control Room Ventilation Operability Test, Revision 2, November 9, 1978 SP 2609C, Enclosure Building Integrity Verification,
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Revision 1, August 25, 1975 SP 26090, Enclosure Building Filtration System (EBFS)
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Filter Testing - Annual, Revision 2, December 26, 1978 SP 2<09E, Enclosure Building Filtration System (EBFS)
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Ten ng - Refueling, Revision 1, November 21, 1978 SP 2609F, Control Room Ventilation System (CRAC) Filter
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Testing - Annual, Revision 0, October 14, 1976 SP 2610A, Motor' Driven Auxiliary Feedwater Pumps Opera-
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bility Test, Revision 1, March
'4, 1977
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SP 26108, Turbine Driven Auxiliary Feedwater Pump
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Operability Test, Revision 2 April 26, 1978 SP 2610C, Auxiliary Fecdwater System Lineup and Opera-
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bility Test, Revision 1, March 26, 1978 SP 26100, Main Steam Isolation Valve Operability Test,
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Revision 2, November 12, 1976 SP 2610E, Main Steam Isolation Valve Closure, Revision
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1, November 12, 1976 SP 2611A, Facility I Reactor Suilding Closed Cooling
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Water Pump Operability Test, Revision 1, April 23, 1976 SP 26118, Facility II Reactor Building Closed Cooling
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Water Pump Operability Test, Revision 1, April 23, 1976 SP 2611C, Facility I Reactor Building Closed Cooling
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Water Alignment and Operability Test, Revision 1, June 24, 1976 SP 2611D, Facility II Reactor Building Closed Cooling
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Water Alignment and Operability Test, Revision 1, July 16, 1976 SP 2611E, RBCCW Valve Operability Test, Revision 0,
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July 17, 1975 SP 2612A, Facility I Service Water (SW) Pump Operability
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Test, Revision 2, March 30, 1976
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SP 26128, Facility II Service Water (SW) Pump Operability Test, Revision 2, March 30, 1976 SP 2612C, Facility I Service Water System Lineup and
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Operability Test, Revision 1, August 13, 1975
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SP 2612D, Facility II Service Water System Lineup and Operability Test, Revision 2, March 22, 1978 SP 2612E, Service Water Power Operated Valves Operability
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Test, Revision 0, July 24, 1975 o f. R
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SP 2613A, Facility I Diesel Generator Operability Test,
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Revision 4, March 12, 1979 SP 26138, Facility II Diesel Generator Operability
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Test, Revision 4, March 12, 1979 SP 2613C, Engineered Safety Feature System (ESF) Integrated
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Test, Revision 4, April 4, 1979 SP 2613E, Diesel Generator Fuel Oil Sampling, Revision
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0, March 12, 1979 SP 2614D, AEAS Operability Verification (Auxiliary
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Exhaust Acutuation Signals), Revision 1, January 15, 1979 SP 2616A, Containment Sump Recirculation Manual Pushbotton
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Test, Revision 2, January 11, 1979 SP 2618A, Fire Protection System Fire Pump Auto Start
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Test, Revision 0, March 16, 1978 SP 2618K, Fire Protection System Valve Lineup Chack,
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Revision 0, March 16, 1978 SP 2619A, Control Room Shift Checks, Revision 3, February
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20, 1979 SP SSC, Control Room Weekly Checks, Revision 0, July
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28, 1975 SP 26190, Startup Surveillance Check List, Revision 1,
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March 7, 1979
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SP 2619E, Control Room Monthly Checks, Revision 3, February 20, 1979 SP 2630A, Main Steam Safety Valve Testing, Revision 2,
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June 21, 1976 SP 2654, Periodic Checks, Revision 1, December 8, 1976
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SP 2655, Control Room Chlorine Monitor Checks, Revision
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0, January 8, 1976 12c'. %1 a
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SP 2656, Control Room Annunicators Operability Check,
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Revision 0, January 5, 1979 SP 2659, Steam Generator Feed Pumo Periodic Testing (SGFP),
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Revision 1, September 1, 1977 SP 2660, Auxiliary Feed Pump Turbine Periodic Testing,
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Revision 0, August 24, 1977 SP 2661, D/G Overspeed Trip Test, Revision 1, January 11,
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1978 SP 2663, Venting Charging Pump Suction Stabilizer, Revision
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0, February 20, 1979 SP 2669A, PE0 Rounds, Revision 1, November 9, 1978
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SP 2676, Engineered Safeguards Actuation System Under-
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voltage Trip Calibration, Revision ':, July 26, 1976
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SP 2676C, Manual Testing of the Automatic Actu: tion Logic,
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Revision 0, February 7, 1977 (3) A review of selected Maintenance Procedures indicated that restoration was addressed primarily for the maintenance techni-cian in the area of cleanliness, tool control and supervisor information.
Further, it was noted that, for safety systems, a Job Order / Maintenance Request is always used in coajunction with Maintenance Procedures for interfacing with the Operations Department.
Administrative Controls were established for the use of Job Orders / Maintenance Requests including system opera-bility verification by Operations Personnel prior to return to service.
In light of this, a detailed review of Maintenance Procedures in the area of return to operable conditions was not pursued.
(4) No items of noncompliance were identified. One unresolved item was disclosed.
The library copy of facility procedures was used to support this review and several discrepancies were observed with respect to incorporation of revisions into this copy of the procedures.
Some examples are noted below.
SP 2602K, P and Q and SP 2603G.1 through.4 dealt with
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instrument calibration and were replaced by 2400 series procedures.
The index for Unit 2 Surveillance Procedures indicated these orocedures still existed as 2600 series procedures.
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Previous revisions (besides.the lastest revisior of the
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following procedures / forms) wert still in the p ocedure binders:
SP 2604I; Forms 2612A-1, 26128-1, 26',2D-1.
It appeared that these old revisions were not taken out because they were not in the proper sections (designated by tabs), but in an adjacent section where they were overlooked during the incorporation of the latest revision.
SP 2676 and 2676C were not listed on the Unit 2 Surveil-
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lance Procedures index.
The licensee representative acknowledged the above and stated that a review of this area would be conducted and the items noted above would be corrected.
The licensee has completed this review.
Further NRC inspections will check the implementation of administrative controls in the future.
e.
Review of Lates Safecuards System Surveillance Test for Verification that Acceptance Criteria was Met The inspectors reviewed the surveillance procedures test data sheets for the last test performed.
That data was compared to the stated test acceptance criteria.
This review did not verify technical adequacy of the test procedure nor compatability of procedure acceptanca criteria with the Technical Specification requirements.
The following test data sheets were reviewed:
Station Form Date of Test 2401 A-1, Manual Reactor Trip 1/14/79 2401C-1, RPS Turbine Loss of Load 5/17/79 2402A-1, Reactor Coolant Flow 4/24/79 24028-1, Pressurizer Pressure 4/17/79 2402C-1, Steam Generator Pressure 3/24/79 24020-1, Steam Generator Level 3/24/79 2402E-1, Pressurizer Level 3/26/79 2402F-1, Remote Shutdown, SG Pressure 3/13/79 2402G-1, Reactor Coolant Cold Leg Temp 4/4/79
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2402H-1, Pressurizer Pressure - Low Range 4/25/79 2403A-1, ESAS Bistable Trip 5/1/79 24038-1, ESAS Under Voltage S/1/79 2403C-1, Pressurizer Pressure - Low Range 4/25/79 2403D-1, Ovatainment Pressure 3/13/79 2403E-1, Refueling Water Storage 'iank Level 4/15/78 2403F-1, Hydrogen Recombiner Instruments 4/3/79 2416A-1, Turbine Trip Pressure Switch 4/18/79 24180-1, Pressurizer Level 5/4/79 2601A-1, Borated Water Source and Flow Path 5/8/78 Verificatit.n and BA Pump Operability Test Data Sheist 26018-1, Boric Acid Flow Path h eification 5/8/78 26018-2, Borated Water Source Flow Path 4/10/78 2601C-1, Boric Acid System Valve Operability 4/10/79 Test (Shutdown)
260lG-1, Facility I Charging Pump Operability 5/9/79 Test 260lH-1, Facility II Charging Pump Operability 5/9/79 Test 2602C-1, Reactor Coolant System Leak Test /
4/19/78 Hydrostatic Test U 03A-1, Safety Injection Tank (SIT) Isolation 4/17/78 Valve Test - Safety Injection Actuation Signal (SIAS) - Data Sheet 26038-1, Safety Injection Tank Isolation Valve 4/17/78 Test (Pressurizer Pressure)
2604A-1, Facility I High Pressure Safety 3/1/79 Injection (HPSI) Pump Operability Test - Data Sheet 7bb
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26048-1, Facility II High Pressure Safety 2/17/79 injection (HPSI) Pump Operability Test - Data Sheet 2604C-1, Low Pressure Safety Injection Pump 3/8/79 Oor ability Test - Facility I 2604D-1, Low Pressure Safety Injection Pump 2/22/79 Operability Test - Facility II 2604E-1, HPSI Pump Electrical Alignment Check -
3/1/79 Facility I 2604E-2, High Pressure Safety Injection (HPSI)
3/1/79 Systen Valve Alignment Check 2604E-3, Facility I High Pressure Safety 3/1/79 & 4/22/79 Injection (HPSI) System Valve Operability Data Sheet 2604F-1, Facility II High Pressure Safety 2/16/79 Injection (HPSI) System Electrical Alignment Check Data Sheet 2604F-2, Facility II High Pressure Safety 2/17/79 Injection (HPSI) System Valve Alignment Check - Data Sheet 2604F-3, Facility II High Pressure Safety
'/17/79 Injection (HPSI) System Valve Operability - Data Sheet 2604G-1, CTMT Sump Outlet Isolation Valve 5/10/79 Operability Test - Facility I 2604H-1, Facility II Containment Sump 5/10/79 Isolation Valve Operability Test -
Data Sheet 2604J-1, Containment Sump Inspection - Data 5/10/79 Sheet 2604K-1, Containment Phosphate Baskets 3/21/79 & 4/19/79 2604L-1, Facility I Low Pressure Safety 3/8/79 Injection (LPSI) System Electrical Wgnment Check - Data Sheet E'
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2604L-2, Facility I Low Pressure Safety 3/8/79 Injection (LPSI) System Valve Alignment Check Data Sheet 2604L-3, Facility I Low Pressure Safety 3/8/79 Injection (LPSI) System and Safety Injection Tank (SIT) Valve Operability Test - Data Sheet 2604M-1, Facility II Low Pressure Safety 2/22/79 Injection Pump Electrical Alignment Check - Data Sheet 2604M-2, LPSI Alignment Check and LPSI/ SIT 2/22/79 Valves Operability Check 2604M-3, Facility II Low Pressure Safety 2/22/79 Injection (LPSI) System and Safety Injection Tank (SIT) Valve Operability Test - Data Sheet 2604N-1, ECCS Valve Operability Test 4/22/79
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2604Q-1, ECCS Flow Verification Surveillance 4/23/79 Test 2604R-1, Safety Injection Actuation Signal 4/1/79 2605A-1, Verifying Containment Integrity 2/22/79 2605F-1, Leak Test of Containment Personnel 4/5/79 Access Door Gaskets 2605G-1, Containment Isolation Valve Operability 5/10/79 Test - Operating 2605G-2, Containment Isolation Vaive Operability 5/2/79 Test - Operating 26051-1, Containment Inspection 1/16/79 2606A-1, Facility I Containment Spray Pump 3/8/79 Operability Test 2606B-1, Facility II Containment Spray Pump 2/22/79 Operibility Test i f -
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2606C-1, Facility I Containment Spray System 3/8/79 Alignment and Operability Test 2606C-2, Facility I Containment Spray System 3/8/79 Alignment and Operability Test 26060-1, Facility II Containment Spray System 2/22/79 Alignment and Operability Test 2606D-2, Facility II Containment Spray System 2/22/79 Alignment and Operability Test 2606F-1, Containment Spray Actuation Signal 3/31/79 Manual Pushbutton Test 2607A-1, Facility I Containment Air Recirculation 5/9/79 and Cooling Unit Operability Test 2607B-1, Facility II Containment Air 5/9/79 Recirculation and Cooling Unit Operability Test 2608A-1, Hydrogen Recombiner Operability 3/1/79 & 5/17/79 Test - Operating 2608C-1. Post Incident Recirculation System 3/1/79 Operability Test Facility I 26080-1, Post Incident Recirculation System 4/16/79 Operability Test Facility II 2608E-1, Hydrogen Purge System Operability 4/2/79 2609A-1, Ventilation Operability Test -
5/10/79 Facility I 26098-1, Ventilation Operability Test -
5/10/79 Facility II 2609C-1, Enclosure BJildinc Integrity 5/9/79 Verification 26090-1, EBFS Filter Testing - Annual 9/7/78 26090-2, EBFS Filter Testing - Annual 9/7/78 2609E-1, EBFS Filter Testing - Refueling 4/28/79 9 C, 7
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2609F-1, Control Room Ventilation System 1/12/79 (CRAC) Filter Testing - Annual 2609F-2, Control Room Ventilation System 1/14/79 (CRAC) Filter Testing - Annual 2610A-1, Motor Driven Auxiliary Fee.dwater 5/9/79 Pumps 26108-1, Turbine Driven Auxiliary Feedwater 2/16/79 Pump Operability Test 2610C-1, Auxiliary Feedwater System Operability 5/9/79 Test 2610C-2, Auxiliary Feedwater System Lineup 5/9/79 26100-1, Main Steam Operability Test Sheet 3/10/79 2610E-1, Main Steam Isolation Valve Closure 1/17/79 2611A-1, Facility I Reactor Building Closed 5/6/79 Cooling Water Pump Operability Test 26118-1, Facility II Reactor Building Closed 5/6/79 Cooling Water Pump Operability Test 2611C-1, Facility I RBCCW System Alignment 5/6/79 and Operability Test 2611C-2, Facility I RBCCW System Alignment 5/5/79 and Operability Test 26110-1, Facility II RBCCW System Alignment 5/6/79 and Operability Test 26110-2, Facility II RBCCW System Valve 5/6/79 Alignment 2611E-1, RBCCW Valve Operability Test 5/4/79 2612A-1, Facility I Service Water Pump 5/9/79 Operability Test 26128-1, Facility II Service Water Pump 5/9/79 Operability Test
-,el2C-1, Facility I Service Water System 5/9/79 Lineup and Operability Test 12r '7
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2612D-1, Facility II Service Water System 5/9/79 Lineup and Operability Test 2612E-1, Service Water System Power Operated 4/13/79 Valves Operability Test 2613A-1, Facility I D/G Operability 5/8/79 26138-1, Facility II D/G Operability 5/9/79 2613C-1, Engineered Safety Feature System 4/2E/79 Intsarated Test Data Sheet 2613E-1, Diesel Fuel l)il Sampling / Analysis 4/1/79 26140-1, AEAS Operability Verification 5/2/79 2616.'.-1, Containment Sump Recirculation 5/2/79 Manual Pushbutton Test 2618A-1, Fire Protection System Fire Pump Auto 4/18/79 Start Test 2618K-1, Fire System Valve Lineup Check 5/9/79
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2619A-1, Contrcl Room Shift Checks 3/10/79 2619A-2, Control Room Daily Surveillance 3/10/79 2619C-1, Control '<oo,1 Weekly Checks 5/9/79 2619A-3, Control Rocm Daily Surveillance 5/5/79 26190-1, Startup Surveillance Check List 1/16/79 26190-2, Start' p Surveillance Check List 1/16/79 26190-3, Stirtup Surveillance Check List 1/18/79 2619E-1, Control Room Monthly checks 5/16/79 2656-1, Control Room Annunicators Operability 9/7/78 Check 2669A-1, PE0 Rounds 5/16/79 2669A-2, PE0 Rounds 5/16/79 2669A-3, PE0 Rounds 5/16/79 C '7 '09
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2730A, Pressurizer Safety Valve Test, Revision 2, October 23,
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1978 - Data:
April 20, 1979 2730R, Main Steam Safety Valve Test, Revision 1, March 9,
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1979 - Data:
March 10, 1979 and April 19, 1978 2735, Diesel Inspection, Revision 0, November 18, 1977 - Data:
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March 16 and April 3,1979 2736A, Battery Pilot Cell Surveillance, Revision 1, September
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22, 1976 - Data:
May 11, 1979 2736B, Complete Battery Cell Measurement, Revision 1, September
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22, 1976 - Data:
March 19 and April 2, 1979 2736C, Battery Inspection - Refueling, Revision 0, March 8,
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1979 - Data:
March 18 and April 12, 1979 The inspectors found that the data recorded on the above listed data sheets met the stated test acceptance criteria with the following exception.
TS 1.6.4.2.a requires that the Hydrogen Recombiner be demon-
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strated operable by verifying minimum sheath temperature increases to > 700 F within 90 minutes and is maintained for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
SP 2608A implements these requirements.
This test, applicable to Modes 1 & 2, was conducted on March 1, 1979 while the reactor was in Mode 5 ts support plant startup and comply with the semiannual frequency requirements.
However, the test was completed one-half hour shcrt of the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> requirement to maintain temperatures > 700 F.
The licensee representative acknowledged the above and performed the test again on May 17, 1979 prior to the plant startup.
A review of the test results indicated satisfactory completion in accordance with the TS and Procedure acceptance criteria.
The inspectors had no further comments in this area.
f.
Administrative Controls to Prevent Common Operator.. Errors from Disablina Safeauards Systems The licensee does not require a second operator to perform an addi-tional lineup of safeguards systems to accomplish an independent verficiation of system availability.
The licensee does address the problem of common operator errors by requiring that redundant por-tions of systems are lined up by different operators.
This policy is implemented by statements on each valve lineup check off list.
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The inspectors had no additional questions at this time.
g.
_ Auxiliary Feedwater System - Control of Valves through the Use of Lockina Devices The licensee has chosen to lock open only the auxiliary feedwater pump minimum flow recirculation line stop valves, 2-FW-52A, B and C; and to lock shut the cross tie supply line valve providing Auxiliary Fradwater to the Spent Fuel Storage Pool, 2-FW-54.
The inspectors had no additional questions at this time.
h.
Assessment of Operating Procedures (1) The inspectors determined, through personnel interviews, that the licensee had never required the actuation of the high pressure safety injection pumps to assist in the control of pressurizer level during any transient.
The three HPSI purros are seveli stage centrifugal pumps with a design pressure and flow of 1600 psig and 315 gpm per pump.
(2) The inspectors determined that the licensee has established operating conditions and precautions for the operation and securing of reactor coolant pumps.
These were evaluated by the inspectors in paragraph 2.h(5), Bulletin section 6C of this report.
(3) Control of the Feeding of Steaai Generators with Low Indicated Level.
The licensee has no specific operating procedures for the control of feeding of dry steam generators Lecause of design considerations of these components.
Proc > dural controls over fceding of steam generators with low water level have been established because of the considerations of a feedwater line water hammer stated in Amendment 32 (dated October 27, 1977) to the unit operating license (dated October 27,1977.) Those requirements are stated in OP2321, Feedwater System, Revision 4, Change 1 dated August 21, 1978 and OP2322, Auxiliary Feedwater System, Revision 4, Change 1 dated November 9, 1978.
These procedures require that, when steam generator water temperature is above 212 F and steam generator water level is below the feedwater sparger (less than 45%), the feedwater flow shall be limited to 600 gpm.
If reactor power is greater than 5% and steam cenerator level decreases to less than 45%, then the reactor wst be manually tripped.
Also, if feedwater flow is lost for greater than 15 minutes and the conditions of level r..id temperature stated above exist, flow shall not exceed 168 gpm.
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(4) Tagging Practices - The licensee's safety tagging program is implemented through ACP-QA-2.06, Station Tagging and Bypass / Jumper Control, Revision 6, dated October 20, 1978.
Section 6.1.3.3 of that procedure allows the use cf a mini-tag on control room boards.
Those mini-tags are about one inch square and are used in lieu of a full sized tag to keep the control boards uncluttered.
The decision to place mini-tags or full sized tags is left to operators.
Full sized tags are used if that tag is the only tag placed on a component or if the tag is a caution tag which must have space for the cautioning statement.
The inspectors observed the implementation of the tagging program during this inspection.
No instances were found in which tags on control room panels obscured plant status indicators or plant instrumentation.
(5) Actions taken in Response to Bulletin 79-068.
(a)
Prevention of Conditions which may lead to voiding -
Operating procedures OP2506, Loss of Coolant Accident, Revision 4, dated April 24, 1979; OP2509, Steam Line Rupture, Revision 3, dated April 24, 1979 and OP2515 Steam Generator Tube Rupture, Revision 4, dated April 24, 1979 specify parameters to be verified by the gerators to insure that plant conditions are not leading to void formation in the core.
Hot leg temperature is to be at least 20 F cooler than saturation temperature for the indicated pressurizer pressure.
The operator is cautioned that the upper limit of in-core thermocouples is 650 F and that the process computer will only print out the value of the last update before exceeding the upper limit.
Proper reactor coolant pump operation it verified by pump and motor parameters, current greater than 400 amps, steam generator differential pressure (greater than 10 psid - 2 pumps running, 20 psid, 3 pumps running, 30 psid - 4 pumps running); reactor coolant system differential temperature less than 5 F and no reactor coolant pump vibration alarms.
(b) Prevention of Voids - Procedures 2506 and 2509 include cautions to the operator to control the feeding of steam generators to ensure that the cooldown rate does not adversely affect pressurizer level and pressure.
(c) Reduction of voids if formed - Procedures 2506, 2509, and 2515 address core cooling in the event that voids are recognized.
Operators are instructed that reactor coolant pumps are operating and charging pumps, HPSI and LPSI 12rf 272
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pumps are injecting.
Leak isolation in PORV, letdown and RCS sample lines is addressed. (Reactor Coolant pump operation limitations have subsequently been addressed pursuant to IE Bulletin 79-06C.
See subparagraph 2.h(5)(g)
of this report.
(d)
Indications of a stuck open PORV - Procedures OP2502, Emergency Shutdown, Revision 6, dated April 24, 1979 and 2506 address the indications of a stuck open PORV as increasing quench tank level and temperature and PORV discharge pipe temperature.
The operator is cautioned to monitor these parameters if the PORV's have operated and pressure has been reduced below the set pressure.
The procedures contain instructioru to the operator to locate the possibly stuck open valve and maintain it isolated.
(e) Continual operation of Safeguards Systems-Frocedures 2506, 2509 and 2515 caution the operator that securing specified equipment is permittad only after carefully evaluating the indicated parameters.
The operators are instructed that, prior to securing any equipment, the safeguards system actuation module should be reset and, after securing equipment, if conditions worsen to the point where the prerequisites are no longer met, the equipment shall be restarted.
The HPSI pumps may only be secured if all of the following conditions exists:
HPSI pumps are aligned to the RWST,
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HPSI pumps have been run for 20 minutes,
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All hot and cold leg temperatures are at least 50 F subcooled, Pressurizer level is restored and responds to charging
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pump operations, Pressurizer pressure is normal and responds to heater
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and spray actuation, The reactor is shutdown as indicted by rod positions,
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boron concentrations and power level, 1257 273
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Core cooling is being provided by the steam generators
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or shutdown cooling.
Steam generators may be operating in forced flow, as indicated by reactor coolant pump differential pressure greater than 3 psid, pump motor current grea'.er than 100 amps and reactor coolant differential temperature less than 10'F or steam generators may be in natural circulation, as indicated by reactor coolant differential temperature 50 F and stable.
The steam generators must have steam and feed flow.
HPSI pumps are to be secured if minimum pressure
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temperature limits are approached.
(f) Charging pumps may be secured only if they have run longer
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than 20 minutes, hot leg temperature is more than 50 F below saturation temperature and system pressure is greater than 1600 psid and increasing.
(g) Procedures 2506, 2509 and 2515 were revised to add require-ments requiring continued operation of reactor coolant pumps.
However, in accordance with IEB 79-06C the licensee has issued a procedural change requiring that, upon a reactor trip and initiation of the HPSI system caused by low reactor coolant system pressure, the operator is to trip all operating reactor coolant pumps.
(h) Operational significance of pressurizer level in recogniz-ing RCS loss of coolant.
Procedure 2506 aids the operator by stating the following symptons of a loss of coolant accident.
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Rapidly changing pressurizer level, Rapidly decreasing pressurizer pressure,
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Increasing containment pressure, High containment radiation,
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Auto start of all standby charging pumps,
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Safety Injection actuation signal,
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Containment isolation,
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Enclosure building filtration actuation,
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Thermal margin low pressure reactor trip, q}f y
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Auto start of diesel generators.
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Procedure 2515 aids the operator by stating the following symptoms of a steam generator tube rupture.
High radiation alarms on steam generator blow down
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tank, or steam Jet air ejec'.or off gas, Feedwater/ steam flow mismatch,
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Level spike in steam generator,
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Changing pressurizer level and decreasing pressurizer
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pressure, Safety injection actuation signal,
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High conductivity in steam generator.
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By procedure, the operator has been given additional plant parameters for observation in the event that a loss of coolant accident on the pressurizer steam space causes inaccurate pressurizer level indication.
(i)
Inadvertant pumping of highly radioactive liquids from the containment - review by the inspectors identified no paths which would allow pump %g radioactive material from the containment if a containment isolation signal were not received.
In addition, the licensee has processed a plant design modification to remove the automatic actuation of contain-ment sump pumps.
(j) Reactor Coolant System Degasification - The reactor coolant system is degased by the use of the radioactive waste system degasifier.
The gas stripped from the reactor coolant system is stored in the gaseous radioactive waste system decay tanks.
The inspectors ceviewed OP23358, Degasifier, Revision 2, dated July 3, 1978 to verify procedural coverage of degasifier operation.
Additional methods of RCS degasification include purging the volume control tank with nitrogen to the gaseous radioactive waste system. This is addressed in OP23358, E
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Change number 1 dated March 9, 1979, and OP230F, Volume Control Pnrtion of the Chemical and Volume Control System, Revision 4, October 17, 1978.
A second method involves venting the pressurizer steam space to the radioactive waste system.
This is addressed in OP2304.
This is accomplished through sample valves aligned at the Primary Sample Sink.
(k) Containment Post Incident Hydrogen Control-Hydrogen gas generated during an accident may be recombined in one of two hydrSgen recombiners located in containment and operated remotely.
These gases may be purged from the containment using the hydrogen purge system which vents to the Unit 1 stack through the Enclosure Building Filtration System.
The Inspectors reveiwed the procedural coverage of these isolations which is stated in OP2313C, Containment Post Incident Hydrogen Control, Revision 5, dated Arpil 10, 1979.
(1)
Licensee Review of Three Mile Island Accident.
The licensee has established a Task Force within its Nuclear Engineering and Operations Departments to coordinate the review of operating procedures, plant design and response to transient conditions in light of the Three Mile Island Accident for Millstone Units I and II and the Haddam Neck Plant.
3.
Review of Plant Operations - Plant Inspections The inspector reviewed plant operations through direct inspection and observation during scheduled refueling outages of Units 1 and 2; and the return to power operation of Unit 2.
Inspections were made of the accessible portions of the Unit 1 control room, drywell, reactor, turbine and radioactive waste buildings, the intake structure and the Unit 2 control room, primary containment, auxi-liary and turbine buildings, the condensate polishing area and the intake structure.
During this inspection, activities in progress were refueling outages of Units 1 and 2.
The inspector observed operations in the control room including shift turnovers and backshift activities.
a.
Instrumentation Control room process instruments were observed for correlation between channels and for conformance with Technical Specification requirements.
No unacceptable conditions were identified.
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b.
Annunciator Alarms The inspector observed various alarm conditions which had been received and acknowledged.
These conditions were discussed with shift personnel who were knowledgeable of the alarms and actions required.
During plant inspections, the inspector observed the condition of equipment associated with various alarms.
No unaccept-able conditions were identified.
c.
Shift Manning The operating shifts were observed to be staffed to meet the operating requirements of Technical Specifications, Section 6, both as to the number and type of licenses.
Control room and shift manning were observed to be in conformance with Technical Specif.ications and site administrative procedures.
d.
Radiation Protection Controls Radiation protection control areas were inspected.
Radiation Work Permits in use were reviewed, and compliance with those documents, as to protective clothing and required monitoring instruments, was inspected.
There were no unacceptable conditions identified.
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e.
Plant Housekeeping Controls Storage of material and components was observed with respect to prevention of fire and safety hazards.
Plant housekeeping was evaluated with respect to controlling the spread of surface and airborne contamination.
Tb re were no unacceptable conditions identified.
f.
Fire Protection / Prevention The inspector examined the condition of selected pieces of fire fighting equipment.
Combustible materials were being controlled and were not found near vital areas.
Selected cable penetrations were examined and, thus, fire barriers were found intact.
Cable trays were clear of debris.
g.
Control of Equipment During plant inspections, selected equipment under safety tag control were examined.
Equipment conditions were consistent with information in plant control logs,
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h.
Instrument Channels Instrument channel checks were reviewed on routine logs.
An inde-pendent comparison was made of selected instruments.
No unacceptable conditions were identified.
i.
Equipment Lineups The inspector examined the breaker position on all switchgear and motor control centers in accessible portions of the plant.
Equipment conditions were found in conformance with Technical Specifications and operating procedure requirements.
j.
Technical Specifications for Refueling During the inspection period the inspectors made frequent observa-tions in the control room and in the plant to verify that the Technical Specifications for the Shutdown or Refuel Modes, at Unit 1 or Modes 5 or 6, at Unit 2 were being met.
There were no unacceptable conditions identified.
4.
Review of Plant Operations - Logs eiid Records During the inspection period, the resident inspector reviewed operating logs and records covering the inspection tin:e period against Technical Specifications and administrative procedure requirements.
Included in the review were:
Shift Supervisor's Log May 1 to June 1, 1979
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Plant Incident Reports May 1 to June 1, 1979
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Jumper and Lifted Leads Log all active entries
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Maintenance Requests and Job Orders all active entries
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Safety Tag Log All active entries
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Plant Recorder Traces
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daily during control room surveillance Plant Process Computer Printed daily during control room
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Output surveillance Key Control Log May 1 to June 1, 1979
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Several entries in these logs were the subject of additional review and discussion with licensee personnel.
No unacceptable conditions were identified.
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5.
Inoperable Control Rod Drive Mechanism (Unit 1)
During weekly control rod drive operability surveillance testing conducted on January 25, 1979, control rod 2207, which had been fully withdrawn at position 48, became stuck between positions 46 and 48.
This was reported to the NRC as LER 245/79-04.
The event was reviewed and documented in NRC inspection report 245/79-02, paragraph 3.
The plant was operated until one April 29, 1979 refueling outage using a modified control rod pattern to comply with Technical Specfication require-ments for shutdown marCin.
The licensee conducted his investigation of this occurrence in accordance with Special Procedure 79-1-19, Stuck Rod Removal, Revision 0, dated April 30, 1979. This procedure was reviewed and accepted by the onsite safety committee in PORC meetira 79-36.
The procedure was reviewed by the resident inspector.
The control rod and control rod drive mechanism for position 22-07 was removed on May 3, 1979.
A rebuilt drive mechanism replaced the mechanism at pos Pion 22-07.
During evaluation, the licensee found no interference between the control rod Velocity Limiter and the Guide Tubes.
The drive mechanism would not move with the control rod uncoupled.
Upon disassembly of the drive mechanism, a small piece of material, which had contact radiation readings of 500 Rem / hour, was found wedged between the index tube and the guide cap.
The wedged piece measured about 1.75 inches long and 0.375 inches wide; and appeared to be a portion of the neutron source holder was originally located at core position 24-09.
Position 24-09 is adjacent to control rod 22-07.
That source holder was discovered to be broken during the Fall 1976 Refuel Outage and was reported to the NRC as LER 76-33.
During the 1978 Refuel Outage, all service holders were removed from the reactor.
During this (1979) shutdown, the licensee removed full support castings and control rods from 23 control rod locations.
Inspections were made using an underwater television camera and those areas of the core and guide tubes were drained using an underwater vacuum.
This inspection included attempting to locate and recover a fuel channel fastener which wa, dropped from the top of a fuel assembly at core position 13-02.
That fuel assembly was one which had its channel replaced during this outage.
The licensee's analysis concluded that during tha rechanneling of irradiated fuel in the fuel pool fuel preparation machine, it was possible that, in the case of fuel equipped with finger springs, the finger springs could hang the channel up prior to seating.
If an operator
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was not aware of this, the channel fastener could be placed in position but the cap screw would not properly engage the threads of the fuel assembly upper tie plate.
The lictasee corrective action was to inspect and check the tightness of all channel fasteners in finger spring fuel which had been rechanneled during this outage.
In addition, a sample of non-finger spring fuel was inspected and no problems were identified.
The area of examination included the inside of the core barrel in the southwest corner and a section of the cor,. bounded by core positions 13-02, 13-08, 17-08, 17-16, 21-16, 21-20, 35-20, 35-14, 31-14, 31-02 and 13-02.
The results of the examination of fuel and the core area were reviewed by the resident inspector as it took place.
There were no unacceptable conditions identified.
6.
Linear Power Range Channels A and D Found Inoperable (Unit 2) -
(LER 79-12)
On May 22, during the first power ascension into the power range during this operating cycle two of the four linear power range channels were noted inoperuble.
The reactor was made critical on May 18 after a refueling outage.
Low power physics testing was in progrese until May 22. At that time it was planned to commence a power ascensica to 30 percent for turbine testing.
At about 10 percent power, during the verification of overlap between the loganithmic and linear power range channels, channels
"A" and "0" remained down scale.
They were declared inoperable. the power ascension was stopped, channel "A" was tripped and channel "D" was bypassed.
The licensee made a containment entry to examine the connectors for the detectors associated with those channels.
Those detectors, which are uncompensated ion chambers, were repluced during this refueling outage.
Upon inspection, the licensee found that the center pin on the field wired side of the high voltage connector had been pushed into the connector body during reassembly. Since there is no neutron' source provided for testing the detectors, operability cannot be verified without a neutron flux from reactor power operation.
The resident inepector discussed maintenance procedures and test methods with licensee representatives.
There were no unacceptable conditions identified.
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