IR 05000369/1981036
| ML20040C184 | |
| Person / Time | |
|---|---|
| Site: | McGuire, Mcguire  |
| Issue date: | 12/15/1981 |
| From: | Bemis R, Bryant J, Falconer D, Graham M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20040C179 | List: |
| References | |
| 50-369-81-36, 50-370-81-33, NUDOCS 8201270367 | |
| Download: ML20040C184 (11) | |
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%g UNITED STATES
NUCLEAR REGULATORY COMMISSION o
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REGION 11 o,
101 MARIETTA ST., N.W., SUITE 3100 g
ATLANTA, GEORGIA 30303 Report Nos. 50-369/81-36 and 50-370/81-33 Licensee:
Duke Power Company 422 South Church Street Charlotte, NC 28242 Facility Name: 11cGuire 1 and 2 Docket Nos. 50-369 and 50-370 License Nos. NPF-9 and CPPR-84 Inspection at licGuire site near Charlotte, North Carolina Inspectors: /N
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P.,R.Bemis #
,1 Date Signed bta b
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Date Signed 0-f
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i7}/rl+t D.7 Falconer
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f Date Signed Approved by:
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J./Bryant, Setrion Chief, Division of Resident Date Signed
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[and Reactor Project Inspection SUfV1ARY Inspection on October 19 - November 22, 1981 Areas Inspected This routine, announced inspection involved 2ti0 resident inspector-hours on site in the areas of operational safety, emergency planning, maintenance, surveil-lance, power ascension testing, and follow-up on previously identified items.
Resul ts
- Of the six areas inspected, no violations or deviations were identified.
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8201270367 811215 PDR ADOCK 05000369 G
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DETAILS
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1.
Parsons Contacted Licensee Employees 11. ficIntosh, Station ibnager
- G. Cage, Operations Superintendent T. ficConnel, Technical Services Superintendent D. Rains,' Maintenance Superintendent
- R. Wilkinson, Superintendent of Administration B. Hamil ton, Performance Engineer D. Itarquis, Reactor Engineer
- W. Sample, Projects and Licensing
D. Bradshaw, Operations Engineer S. Frye, Operations Engineer
- D. Lampke, Projects and Licensing
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R. Ruth, Senior QA Engineer Other licensee employees contacted included construction craftsmen, technicians, operators, mechanics, security force members, and office personnel.
Other Organizations J. Roth, Westinghouse
- Attended exit interview 2.
Exit Interview The inspection scope and findings were summarized on November 28, 1981, with
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those persons indicated in paragraph 1 above.
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3.
Licensee Action on Previous Inspection Findings a.
(Closed) Violation 81-16-01 on the construction of scaffolding on safety-related piping is closed based on the issuance of station'
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Directive 2.10.11. The inspector noted that contrary to the licensee's
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commitment to issue the. directive by October 1, the date of issuance was November 3, 1981. This failure to meet the commitment in the violation's response was apparently the result of the preparer's belief that November 1 was the due date. A review of other outstanding canni ments by the licensee and the inspector showed no other
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deficiencies.
This deviation fran the committed schedule was therefore concluded to be an isolated case. The inspector will continue to review licensee response to violations for its timeliness, but has no further
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questions at ~ this time.
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1 b.
(Closed) Violation 81-22-04 on containment integrity. The inspector reviewed the results of local leak testing and the changes to
i procedures for containment integrity verification in all modes.
The inspector has no further questions.
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c.
(Closed) Violation 81-15-03 on tagging of systems when instrumentation was out of service.
The inspector noted that the licensee's arguments
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on semantics were correct, but that the response did not adequately address the problem or adequately describe the corrective actions taken.
In addition to the actions described, the licensee has provided the shift supervisor with a computer printout of all instruments in the
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plant and their associated technical specifications. Based on the licensee's comitment to maintain this list, up to date, in the shift
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supervisor's office, this violation is closed.
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4.
Unresolved Items Unresolved items were not identified during this inspection.
5.
Operational History i
l At the beginning of this inspection period the unit was in an outage-to repair a body to bonnet leak on valve N01. This valve is the first in a series of suction valves in the residual heat removal (ND) system off the
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reactor coolant system (NC). This is the second time this valve has been found to be leaking and the leak was stopped after adding Funnanite through
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nine different holes drilled in the valve casing (outside the pressure boundary).
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As the plant increased pressure and temperature, prior to 1900 psig the
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upper head injection system (UHI) had to be reinstated. When the isolation valves were opened there was a surge in the system and the membrane which acts as an interface between the borated water and nitrogen overpressure was punctu red. This was the fourth time this has occurred. The licensee installed a temporary system to monitor pressure drop across the isolation valves and the puncturing of the membrane has not since occurred.
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During this period the reactor has had five unplanned trips.
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been other trips required by the power ascension testing program. All six of these trips we initiated by Lolo Steam Generator (S/G) water level and the Lolo water level was caused for different reasons in each case.
In addition, the reactor was intentionally tripped by the or.erator due to a transient on the plant. Each of the trips will be discussed in subsequent paragra phs.
Other significant events occurring during the reporting,)eriod are as followes and will. be discussed in more detail in subsequent paragraphs:
There was a rupture of the discharge header on the fi'e protection system;
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there was a fuel building evauction; there was a cor.cainment evacuation; both a practice and a yearly emergency drill were held; and due to problems
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in foreign nuclear plants with S/G's similar to those at licGuire, the licGuire unit was shut down and perform cddy current on S/G tubes.
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The unit is presently shut down in mode 5.
All tests have been completed and the unit is in the process of raising temperature and pressure to i
operating conditions.
During the reporting period, al,130% and 50% tests were satisfactorily completed and when the unit achieves criticality it will
be taken to 75% to for testing at that power level.
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6.
Operations Safety Verification
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During the inspection interval the inspectors observed operations in a.
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the control room and throughout the plant.
Control room, key control, tagging and modification logs were reviewed and the status of instrument calibration, equipment tags and annunciators was verified.
Compliance with selected technical specification parameters was independently verified where possible during each mode of operation.
j b.
Inspection of certain Unit 1 systems was perfomed to verify operabil i ty. System lineup was verified in the control room and in the plant for the upper head injection system and the residual heat removal system (ND).
The inspector verified that the safety system challenges which occurred c.
during the inspection period were handleri according to procedure and received the required followup by the licensee.
Five of the reactor trips were unintentional and one was intentional. The trips are discussed in the following paragraphs.
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Lolo Steam Generator Level Trips.
r (a) An electro hydraulic (Dell) fluid leak to an intercept valve caused DEH fluid pressure to go low which tripped the turbine; the S/G level shrink due to the turbine trip caused a reactor trip.
(b) Due to an incorrect low setpoint on the relief valve on the feedwater pump suction line, the.feedwater pumps were put in manual and feedwater was reduced to the point that feedwater flow
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barely met steam flow with approximately a zero delta pressure across the S/G's. The control rods were in manual, automatic rod control had not been fine tuned, and the operator allowed average-reactor coolant to increase which caused steam pressure to increase which retarded feed flow. When the operator received the S/G Lolo level alam he recognized the problem, but fed the S/G's too fast which caused further shrink of levels and a reactor trip.
(c) While one S/G level channel was in trip due to surveillance testing a fuse on a 7300 relay card blew, causing another level
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channel to trip-giving 2/3 coincidence which tripped the reactor.
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(d) During the swap of feedwater from auxiliary feedwater to main feedwater at approximately 30% power, steam flow increased to steam dump due to primary temperature increase and the auxiliary feedwater pump could not keep up with steam flow, giving Lolo level in the S/G.
(e) During 50% power testing with only one main feedwater pump in service, a spurious main feedwater pump trip left the S/G's producing 50% steam flow without feedwater flow, giving a Lolo S/G level.
licGuire has the model
"D" steam generators which are the first of a kind in this country.
In thi; model S/G, the level program and reactor trip signal on Lolo level are also different from all previous Westinghouse S/G's.
The original Precautions, Limitations and Setpoints (PLS) requirement on programmed level had the programmed level too close to the trip setpoint at lower power levels and this was the cause of four of the five trips discussed above.
Duke requested and received from Westinghouse a PLS change which raised there low power S/G level. Since the change in the program level there have been two transients similar to the ones discussed and neither caused a reactor trip.
7.
flatural Circulation Operation On flovember 11,1981, at 15:08 a failed fuse caused the inboard isolation valve of the nuclear cooling water system to fail shut.
This removed the heat sink for the reactor coolant pump stators. All four pumps immediately began to heat up.
The operators began a controlled decreased of power to mode 3 (Hot Standby), planning to trip the reactor coolant pumps as necessary once power was below the P-10 (10%) trip setpoint.
At 1510, stator temperature required tripping of the "B" and "D" Reactor coolant pumps at 10% power.
The transient caused by the pump trip caused s sell in the "D" steam generator to above the Hi-Hi level setpoint. Turbine trip, feedwater isolation, and autostart of the motor driven aux feed pumps resul ted.
A surge in the suction side of the feedwater systems in con-
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junction with feedwater isolation caused the suction line relief valves to lift.
Steam from the relief valves set off the turbine building sprinkler system. Water pressure on the fire protection system blew off two sprinkle heads. Operators opened the feed water section valves to allow the relief valves to reseat.
At 1S19, with two pump.; in service but with very high temperatures, the operators decided to trip the reactor.
Power was at approximately 3"., the maximum setpoint for allowable operation with aux feed alone, but flux was extremely skewed due to the full insertion of one shutdown rod (Start up physics testing had been in progress at the beginning of the transient).
The operators decided to enter mode 3 prior to establishing natural circulation. They tripped the reactor at 1519, the "A" RCP at 1520, and the
"C" RCP a t 152 _.
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flatural circulation was established and maintained with a minimum saturation margin of 86*F.
During repair of the failed fuse, power was lost to portions of the control room annunicator panels.
Equipment operators were Conditions were dispatched to auxiliary panels to observe indications.
corrected and reactor start up begun at 1747.
The inspector was in the control roen while natural circulation was established and maintained.
The inspector noted that appropriate emergency, The abnormal and operating procedures were in use througout the event.
cause of the failed fuse was mechanial separation of internal components rather than an electrically " blown fuse". This has been a recurrent problem The licensee's consideraton of the fuse for with fuses on other systems.
possible generic implications and reportability is inspector follow-up item 369/81-36-01; 370/81-33-01.
The During the inspection period there was a fuel building evacuation.
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building was evacuated per procedure when the control room received a fuel building area monitor alarm.
Health Physics (HP) immediately began air samplers and after analyzing the samples, the building was cleared for reentry.
The cause of the alarm was determined to be gases purged out of a spent fuel cask. 11cGuire is receiving spent fuel from Oconee and prior to opening the cask it is filled with water to purge the nitrogen used for inerting. Since there was a spent fuel element in the cask there was also a small amount of radioactive noble gas, the procedure calls for the gas to be directed at the area monitor during the purge to insure knowledge of any radioactivity present.
The licensee has changed their annunciator procedure so that a fuel building evacuation is not required when an alarm is received during this purging process.
Two days after the fuel building evacuation the licensee had a e.
containment evacuation.
The building was evacuated when the control room operators realized that a relief valve on a pressurizer sample line was relieving. The operators knew this water (steam) could be radioactive and that same H.P. and instrument technicians were in containment; therefore, as a precautionary measure, the evacuation alarm was sounded.
H.P. immediately started air sampling, but noticed that the instrument technicians were not leaving containment.
An individual was dispatched to find the instrument technicians and bring them out of containment. When the technicians were brought out of containment they had bio-assays and body burdens run and the results were negative, as was the air sample that was run.
The instrument technicians said they did not hear the alarm. The licensee has committed to an interim and long tem solution to the problem. The interim solution is to have a person stationed in the lower containment where the alarm can be heard who will notify anyone in containment if the alarm sounds. Until the licensee derives a long L
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term solution, this will be carried as an open item, (369/81-36-01, 370/81-33-02).
Duke was notified by Westinghouse that plants in Sweden and Spain with f.
S/G's similar to McGuire and Catawba had experienced massive tube degradation in a large number of tubes in the preheater section of the S/G. This degradation appears to be induced by flow vibration.
Westinghouse requested Duke to shut down when they finished 50% power testing and perfonn eddy current testing on one steam generator in the
!!cGuire was shut area where damage had appeared in the foreign plants.
down at the end of 50% testing and the eddy current examination showed no detectable degradation. While the unit was shutdown, Westinghouse added three accelerometers on each S/G to monitor for vibration; this data will be analyzed when the plant returns to power.
7.
flaintenance Selected maintenance activities were observed in progress or reviewed after Procedures were examined to verify that all required test completion.
prerequisites, preparations, instructions, and acceptance criteria were adequate to perfonn the required function and were met in carrying out the procedu e.
Witnessed activities were examined to verify that current, approved procedures were in use, that individuals performing them were qualified to do so, and that equipnent was adequately tested and returned to service following maintenance.
The following activities were observed; 1.
f1P0 A 7150 28, UHI gas / water interface membrane removal and replacement f1P0 A 7150 55, S/0 nozzle cover installation and removal 2.
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ItP0 A 7150 64, Spent fuel cask short lift adaptor inspection 4.
IIP 0 A 7200 08, Feedwater isolation valve corrective maintenance 5.
flP0 B 7450 03, Fans and air handling unit preventive maintenance 6.
I1P0 A 7450 03, Upper head injection isolation valve corrective maintenance The inspector has no questions in this area at this time.
8.
Surveillance Testing Selected surveillance tests were observed in progress or reviewed after Procedures were examined to verify that all required pre-completion.
requisites, preparations, instructions, and acceptance criteria were met and Witnessed tests were were adequate to perfonn the required function.
examined to verify that current, approved procedures were in use, that
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individuals performing them were qualified to do so, that test equipment in use was calibrated, and that system restoration was completed.
The following activities were observed:
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PT 1A 4350 02A, D/G 1A operability test 2.
PT 1A 4200 20, Verification of positive pressure in piping between BIT and RCS 3.
PT 1A 4250 04G, Reactor trip on turbine trip functional test 4.
PT 1A 4209 03P, flV valve stroke training test 5.
PT 1A 4200 02B, Cold shutdown containment integrity verification 6.
PT 1A 4200 01A, Upper air lock leak rate test
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PT 1A 4300 10, Heat tracing operability test 8.
PT 1A 4206 01A and 1B N1, Pump 1A and 1B performance test.
The inspector has no questions in this area at this time.
9.
Emergency Planning On flovember 12 and October 26, 1981, the licensee held emergency drills in accordance with 10 CFR 50, Appendix E requirements for annual exercises.
The October 26 drill was limited in scope, but the second met the definition of the required "small scale exercise" including involvement of the station emergency organization, the corporate emergency organization and the five county emergency management agencies in the 10 mile EPZ.
The inspectors witnessed both drills at the plant and the corporate crisis management center (Ci1C). At the first drill, the inspectors noted that assembly of the communications equipment at the TSC and CMC was time consuming and confusing.
By the November 12 drill, boxes to hold phones had
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been placed on the walls of the TSC, alleviating the problem.
The licensee plans sfmilar in place storage of phones in the CitC. The inspector will follow up on this item at a later date (IFI 369/81-36-05; 370/81-3305). The licensee is also considering more back-up radios for communications 'in the
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event of loss of phones. Additional radio sets for plant-Cf1C communications without inclusion of the counties and field teams are under review. This is inspector followup item IFI (369/81-36-03, 370/81-33-03).
In the October 26 drill, the corporate emergency team manned both the i
alternate and the near-site CitCs. This resulted in some -loss of effectiveness in aiding the station. The alternate CMC did not completely take the designed role as it was also being used as a staging area for manning the near site Cf1C. The near-site Cf1C was not manned until very late in the drill, and then with insufficient manpower. The scenario may have contributed to the problem in that it did not demand large contributions
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During the November 12 drill, the near-site CitC was manned promptly and completely, and took a greater part in the exercise.
Based on performance of the second drill, the inspector has no further questions in
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10.
Power Escalation Testing i
The inspector witnessed portions of the 50% power plateau testing performed
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during the initial startup sequence. Within the areas inspected, there were no vialations or deviations identified.
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The following testing was observed 1.
Neutron noise baseline data recording performed at 43% rated thermal power 2.
Calibration of the steam and feedwater flow instrumentation 3.
Core power distribution determination by incore flux mapping 4.
Preliminary incore and nuclear instrumentation correlation 5.
Nuclear instrumentation calibration to set the full power detector vol tages.
The above testing was witnessed to verify the following:
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That a procedure of the appropriate revision was in use by all crew members.
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That all prerequisites were met j
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That the test was performed as required by the procedure d.
That the applicable technical specifications and license conditions were met, e.
That crew action appeared to be correct and timely f.
That all data were documented when required g.
That the test results were evaluated to verify that all acceptance criteria were met or that corrective action was initiated.
The licensee anticipates that the acceptance criterion on total RCS flow will not be met when the total RCS flow is determined during the latter portions of the 50% power plateau.
Based on anticipated figures, the
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licensee requested and received a change to the technical specifications to pennit operation to 90% of full power.
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a 11.
Radwaste Releases On October 22, 1981, maintenance personnel were performing repairs on a condensate cooling system drain valve. When repairs were suspended due to changing plant conditions, the drain valve was inadvertently left open.
Because the plant was in cold shutdown, the valve position was not apparent for several days. On October 25, + 7 days the unit was returned to service and the open valve was the path fo'r a continuous flow of condensate cooling water to the holdup ponds.
The water flowed into the holdup ponds at a greater flow rate than the
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capacity of the outlet lines. On October 26, + 7 days, the "A" pond began to overflow its banks so that water went unmonitored to the yard drains and thus to the lake. Tha unmonitored flow was stopped when found by diverting input flow to the "B" holdup pond.
The drain valve was found, closed, and flow dropped to normal.
The licensee sampled the water remaining in the "A" holdup pond and found no radiation above background.
It was concluded that the radwaste released was not radioactive.
Prior to the event, the licensee had recognized that the output line from the waste hold up tanks was inadequate for any flow in excess of normal.
A modification was written and will be expedited. The inspectors will review the change at a later date (inspector followup item 369/81-30-04; 370/81-33-04).
In order to return the now brimming holdup ponds to a configuation to handle normal waste water flows, it was necessary for the licensee to pump the contents of the "A" pond to the environment at a greater flow rate than the capacity of the outlet line. This was done with submersible pumps and fire hoses, and the water sent to the yard drains.
The inspector verified that sampling was done per the action statement for conventional waste water with the continuous composite sampler out of service.
Releasing the water unmonitored through the floor drain is not in accordance with technical specification, however, because of the insignificance of this violation to the health and safety of the public, the licensee's role in identifying it, and the prompt and adequate corrective action taken, this item is closed.
12. During the inspection interval the inspector reviewed selected licensee event reports.
Reports were reviewed to verify the report content met requirements and adequate corrective actions were described.
In add. tion, the inspector reviewed selected internal logs and event documentation, interviewed involved individuals, and verified corrective actions. The following event reports are now closed:
81-53 81-144 81-156 81-54 81-145 81-157 81-55 81-152 81-158 81-56 81-155 81-159
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Followup on open items Inspector followup item 81-13-01 on conditional surveillances item is now closed based on inspector review of changes to the procedure for reactor start up.
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