IR 05000312/1979007
| ML19261D866 | |
| Person / Time | |
|---|---|
| Site: | Rancho Seco |
| Issue date: | 05/08/1979 |
| From: | Faulkenberry B, Andrea Johnson, Johnson P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML19261D861 | List: |
| References | |
| 50-312-79-07, 50-312-79-7, NUDOCS 7906260543 | |
| Download: ML19261D866 (7) | |
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U. S. NUCLEAR REGULATORY COMMISSION
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OFFICE OF INSPECTI0rl AND ENFORCEMEf4T
REGION V
Report No.
50-312/79-07 Docket No.
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License No. DPR-54 Safeguards Group Sacramento Municipal Utility District Licensee:
P. O. Box 15830 Sacramento, California 95813 Rancho Seco F M W m e-ay a
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ornia Inspection at:
March 31 - May 4, 1979 Inspection Conducted:
a Inspectors:
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A. Johnson, Reactor Inspector
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P. Jot;n'fon, Reactor Inspector
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'ML 5,,16[ ] q H. Canter, Reactor Inspector Date Signed
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7f P. f W ill, ctor Inspector
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'V ' Miller, Reac' tor Inspector Di'te Signed
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'19 J. Carlson, Reactor Inspector Date Signed hY O S'
A. Hohl, Reactor Inspector Date' Signed Approvedbh: l'IDb dm f/y/99 B. H. Fa'ulkenberry, GhiefrReactor Projects Date Signed Section 2, Reactor 0herations and Nuclear Support Branch Summary:
Inspection on March 31 through May 4,1979 (Report No. 50-312/79-07)
Areas Inspected:
Inspection of plant operations and IE Bulletins pertaining to the "Three Mile Island" incident.
The inspection involved 464 inspector hours onsite by seven NRC inspectors.
Resul ts: No items of noncompliance or deviations were identified.
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DETAILS 1.
Persons Contacted
- R. Rodriguez, Manager, Nuclear Operations
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- P. Oubre, Plant Superintendent
- R. Colombo, Technical Assistant
- W. Ford, Operations Supervisor J. McColligan, Technical Supervisor D. Blachley, Mechanical Engineer J. Price, Engineering Technician M. Carter, Shift Supervisor J. Middletown, B&W Onsite Representative D. Comstock, Shift Supervisor J. King, Shift Supervisor W. Spencer, Shift Supervisor T. Tucker, Shift Supervisor J. Mau, Training Supervisor A. Heckert, Engineering Technician The inspectors also interviewed several other licensee employees, including members of the engineering staff, reactor operators and maintenance personnel.
- Denotes those persons present at the exit interview.
2.
Review of Plant Operations During the inspection the inspectors conducted discussions with plant operators and shift supervisors, reviewed the control room and shift supervisor logs, and conducted daily plant tours.
Control room manning and shift turnovers were observed. The jumper log, recent special orders, and operating procedure revisions were also examined. The plant tours included inspection of radiation pro-tection, plant housekeeping, fluid system conditions, valve and breaker positions, equipment lockout tags, pipe restraints, and fire protection equipment.
No items of noncompliance or deviations were identified.
3.
Reactor Trip on April 22, 1979 At 1:08 p.m. on April 22, 1979, a failure of the "A" reactor pro-tection system (RPS) inverter caused channel A of the RPS to trip.
Total reactor coolant flow indication from the "A" RPS was being provided as a control input to the integrated control system (ICS).
This signal gave an indication of no RCS flow, which caused the " BTU limits" section of the ICS to make an abrupt reduction in feedwater flow to both steam generators.
This in turn caused reactor coolant system (RCS) temperature and pressure to increase, resulting in a reactor trip on high RCS pressure at 2300 psig, 2313 231
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followed by a turbine trip. Channel A, B, and C trip points had recently been reset from 2355 to 2290 psig, and channel D was still bypassed for the setpoint change when the trip occurred.
The power-operated relief valve had also been recently reset to open at 2450 psig. The reactor trip occurred 16 seconds af ter the loss of the "A" inverter.
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Inspectors were at the site when the trip occurred and observed followup actions in the control room.
Reactor pressure peaked at 2330 psig, and reached a minimum of 1855 psig.
Pressurizer level dropped from its initial 200 inches to about 60 inches, then was stablized at,120 inches by manual operation of an HPI pump. The auxiliary.feedwater system functioned as required.
No other safety feature equipment was called upon to operate.
Operators were observed to. follow recently revised procedures covering reactor trip, particularly with regard to RCS pressure-temperature conditions.
Subseg tent investigation by the licensee established that the "A" inverter had tripped because of a failed undervoltage relay.
This was replaced and the plant resumed operation on April 23, 1979.
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No items of noncompliance or deviations were identified.
4.
Licensee Actions to IE Bulletins 79-05 and 79-05A The inspectors examined pertinent licensee documents including administrative procedures, process standards piping and instrument diagrams, standard operating procedures, special orders, emergency procedures, operating and operator training records, and minutes of the Plant Review Committee to verify that the licensee conducted a review of their facility and operations in light of the information describing the recent "Three Mile Island" (TMI) incident.
This review included the systems and component designs, corresponding operational procedures and operating events which relate to those systems and procedures involved in the TMI incident.
The results of the inspectors' examination and discussions with licensee representatives follows:
a.
Operator Training Based on the inspectors' examination of the licensee training records and discussions with two or more operators on each shif t, the inspectors verified:
(1) Operators were aware of tha specific details of the TMI-2 incident and had received training on procedure changes initiated as a result of IE Bulletins 79-05 and 79-05A.
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(2) Operators had been instructed on the specific procedural requirements to assure that sngineered safety features are available as required and, in particular, the operators were knowledgeable of the procedures for removal of a system or component from operable status for maintena-or testing purpose and for returning the system or com-ponent to an operable status.
(3) Operators had been instructed on, and were knowledgeable of, the specific and detailed procedural requirements controlling operator action subsequent to automatic actuation of engineered safety features as prescribed by the IE Bulletin.
(4) Plant automatic actions initiated by reset of engineered safety features do not affect the control of radioactive liquids and gases.
(5) Operators and supervisory personnel had been instructed and.were knowledgeable of the licensee's pr :cedures to
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assure for early NRC notification of serious events.
b.
Engineered Safety Features (1) The licensee's valve / breaker / switch alignment procedures to assure operability of all engineered safety features were verified to be adequate when compared against the systems current P&ID's and single-line diagrams.
(2) The inspectors verified by direct observation and operation of systems, where permissible, that all engineered systems were operable and valve / breaker / switch alignments were consistent with procedural requirements.
(3) The administrative control procedure, AP-3, was examined and found to be adequate to assure proper " return to service" of engineered safety feature components following test and maintenance activities.
(4) The current engineered safety features surveillance test procedures, including all recent changes, were examined and were found to include regt ;rments for returning the systems to operable status up'
completion of the test.
(5) The results of the most rece: t surveillance test on each engineered safety features s < stem showed that the specified acceptance criteria were met The inspector, however, ide i fied two concerns relating to the licensee's surveilla program.
The present testing does not appear to ut the operability of the 2313 233
-4-loss of offsite voltage sequencing relays, nor to verify that the diesel generator can start in the time period assumed by the safety analysis.
(The Technical Specifications do not require such testing, but both Regulatory Guide 1.108 and some other Region V licensees do require it.) The licensee stated that they are developing system modifications, and revisions to the Technical Specifications, in coordination with NRR, which will require surveillance of the loss of offsite power relays and which will permit this surveillance while the reactor is critical.
At the conclusion of the inspection, the licensee stated that the need for periodically measuring the start time
.of the diesel generator, as part of the surveillance test procedure, would be evaluated.
(6) The administrative control procedures for start-up of the reactor after an extended outage were examined and found '
to adequately provide for assuring that engineered safety feature systems are operable.
(7) The licensee's program of " independent verification" of valve / breaker / switch alignments of engineered safety feature systems and other safety related systems requires an operator to perform a check of the alignments and manipulate all valve breakers and switch associated with safety related equipment following extended outage and after maintenance / test activities.
The program does not, however, require that an independent and separate individual witness operator action.
(8) The valves in the auxiliary feed system identified in the licensee's procedure as being locked were observed to be locked in the position indicated by the procedure.
The locking mechanism was a wire and seal.
c.
Operating Procedures (1) The reactor trip procedure (D.3) directs the operator to immediately " monitor pressurizer level and maintain > 45
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inches, start an HPI pump if necessary." According to the licensee's operations persor.nel, the pumps are started immediately subsequent to a trip to maintain the level in the pressurizer.
(2) An emergency procedure (D.12) directs the securing of a reactor coolant pump under prescribed conditions such as low oil, excess vibration, loss of seal flow and over temperature.
On April 13, 1979, a special order was issued by the Plant Superintendent that clearly directs 2313 234
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that emergency procedure D.5, Loss of Reactor Coolant /
Reactor Coolant System Pressure, takes precedent over the emergency procedure for reactor coolant pumps (D.12) if pump combinations would be reduced below one reactor coolant pump in operation per loop during execution of emergency procedure D.5.
(3)
Based on a discussion with reactor operators, the in-spectors determined that the operators were well aware of the need to continue operation of reactor coolant pumps during execution of emergency procedure D.5.
(4) The licensee's emergency procedure D.14, Loss of Steam Generator Feed, prescribes that "if an OSTG has gone completely dry, trip the reactor, insure any water inflow is via the auxiliary feed nozzels." The inspectors verified from discussions with reactor operators that operations personnel were knowledgeable of the emergency procedure requirements.
(5) Based on the inspectors' observations, the licensee's tagging practices on control panels does not provide a potential for obscuring s+atus indicators, such as valve or switch positions, meters, indicators, and alarms.
(6) Observations of Reactor Operation During the period of March 31 through April 27, 1979, inspectors conducted observation of operations and sub-sequent to April 3,1979, observation of operations were conducted during each shif t of operation.
Operator actions and responses to observed events were considered by the inspectors to be appropriate.
d.
An evaluation of the licensee's response to IE Bulletin 79-05 and 79-05A confirmed the validity of the information provided.
5.
Licensee's Response to IE Bulletin 79-05B The licensee responded to Bulletin 79-05B on May 4,1979.
The inspectors verified by direct observation and review of the pertinent records and procedures that:
a.
On April 22, 1979, the reactor protection system trip setpoint for high pressure was reset from 2355 psig to 2290 psig, and the electromatic (pilot) operated relief valve was reset to open at 2450 psig.
It had been set to operate at 2; ; psig.
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b.
The procedural changes directed by the Bulletin had r.ot been completed as of May 4,1979.
However, most of the draf t revisions to the procedures addressing the Bulletin's require-ments have been reviewed by the Plant Review Committee.
The inspectors will verify the completion of the procedural revisions and scheduled training, and document this verification in the next inspection report.
c.
An evaluation of the licensee's response to IE Bulletin 79-05B confirmed the validity of the information provided.
6.
Exit Interview The inspectors met with licensee representatives (denoted in Para-graph 1) at.the conclusion of this inspection on May 4,1979. The inspectors summarized the purpose, scope and findings of this in-spection.
The licensee representatives requested clarification of five NRC requirements.
a.
The meaning of an "open, continuous communication channel."
b.
The meaning of " controlled or expected condition of operati 'n."
c.
The correct interpretation of Paragraph 2 of IE Bulletin 79-05B insofar as determining when high pressure injection pumps can be turned off.
d.
The rationale for NRR's request for copies of all procedures revised by IE Bulletin 79-05B.
e.
The requirement of IE Bulletin 79-05A to run reactor coolant pumps whether or not forced flow is present.
The inspectors gave their understanding of the meaning of each of these requirements and invited the licensee to seek further clarifi-cation, if desired, with NRR or IE Headquarters.
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