IR 05000317/1985028
| ML20137U517 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 11/27/1985 |
| From: | Elsasser T, Foley J, Trimble D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20137U500 | List: |
| References | |
| RTR-NUREG-0660, RTR-NUREG-0737, RTR-NUREG-660, RTR-NUREG-737, TASK-2.F.1, TASK-2.K.3.25, TASK-TM 50-317-85-28, 50-318-85-28, NUDOCS 8512090337 | |
| Download: ML20137U517 (26) | |
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U. S. NUCLEAR REGULATORY COMMISSION Region I Docket / Report:
50-317/85-28 License: DPR-53 50-318/85-28 DPR-69 Licensee: Baltimore Gas and Electric Company Facility: Calvert Cliffs Nuclear Power Plant, Units 1 and 2 Inspection At:
Lusby, Maryland Dates: October 1, 1985 - November 4, 1985
. n /te m s N/21/p h.Foley,SEhforReidentInspector date
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. C. Trimble, RsYident Inspector date Approved:
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Reactor Pro s Section 3C Summary: October 1 - November 4, 1985 Inspection Report 50-317/85-28, 50-318/85-28.
Areas Inspected:
Routine resident inspection of the Control Room, accessible
. parts of plant structures, plant operations, events reported to the NRC, physi-cal security, Licensee Event Reports, maintenance, surveillance, refueling activities, TMI Action Plan Items, radiological effluent, post accident effluent monitoring, Emergency Operating Procedures, SFP cooling, Hydrogen Recombiners,
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organizational' changes and Measuring and Test Equipment program.
Inspection Hours totalled 237 hours0.00274 days <br />0.0658 hours <br />3.918651e-4 weeks <br />9.01785e-5 months <br />.
Results:
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Although no violations were found, significant concerns were identified regarding the testing of Steam Generator. Safety Valves (Section 11).
The inspection in-
'cluded a review of previous corrective. action regarding failures of safety valves'and determined that appropriate corrective action had been initiated at r
the time.
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Results of the licensee's corrective action for the current, repetitive and more significant failures remain unresolved pending completion of a planned corrective action program and demonstration of adequate assurance of valve i
operability.
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Additional concerns were identified regarding the potential for bypassing administrative controls (Section 5) when using the discretion afforded in CCI-200I (permitting exceptions in the use of a detailed maintenance pro-cedures) and CCI-117 (reduced prior review of jumpers installed and removed in the same shift).
Permitting this discretion resulted in the loss of a vital cooling system, discussed under reports to the NRC.
These are areas where the licensee may denote additional attention.
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l OETAILS 1.
Persons Contacted Within this report period, interviews and discussions were conducted with
.various licensee personnel, including reactor operators, maintenance and surveillance technicians and the licensee's management staff.
2.
Summary of Facility Activities
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Unit 1: On October 1, the unit returned to power operation following a plant trip due to an undetermined electrical problem, associated with the feedwater heater level circuit. On October 3, the unit tripped '.glin ap-parently due to the same previously unidentified problem. This time, the cause was identified to be due to electrical grounds on the 11 DC Bus and grounds within the feedwater heater level control circuit.
The grounds were corrected and the unit returned to power. On October 9, RCS uniden-tified leakage increased from.5 gpm to.8 gpm. An investigation identi-
=fied a cracked control bleed off line weld on 11A RCP. The licensee commenced an orderly shut down and declared an Unusual Event due to a plant shut down required by Technical Specification for a leak which now had increased to approximately 1 gpm.
The nlant was cooled down and drained to repair the cracked weld.
Flanges from all four RCP control bleed off lines were replaced with a light weight coupling. On October 13, during the fill of the RCS, after repair of the RCP lines, a valve which had not been properly shut leaked and caused approximately 500 gal-
'lons of water from the Refueling water Tank to drip out of the Containment spray header spray rings, wetting several primary system components. On October 15-Unit I returned to service and remained at power operation throughout.the period.
Unit 2:
Routine operation characterized performance until October 19 when the plant shut down to commence its sixth refueling outage.
The expected-duration.of the outage is 47 days, and includes the following major activities:
Refuel the reactor
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' Overhaul actuator on 21 Main Steam Isolation Valve
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Replace 21A and 21B Reactor Coolant Pump Seals Eddy current examination of 21 and 22 steam generators
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Replace channel heads on saltwater heat exchangers
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Alignment and vibration checks of Reactor Coolant Pumps
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Containment Integrated Leak Rate Test
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Refueling machine modifications
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Replace 21B Reactor Coolant Pump motor
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Reactor vessel water level system pressure-boundary modification
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Inspect and overhaul 21 emergency diesel generator.
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On day 17 of the Unit 2 outage the critical path progressed to approxi-mately 3 days ahead of schedule. To date, this refueling outage has been
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characterized by strict adherence to planned activities and good
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communication between licensee and contractor work groups and plant staff.
Unit 2 is now expected to return to service on December 1, 1985.
3.
Licensee Action on Previous Inspection Findings (Closed) Unresolved Item (317/83-16-02) Loss of Pressurizer Level Indica-tion During Cable Meggering Check. Because a procedure for insulation resistance testing did not clearly identify cables to be tested a contract electrician disconnected an operational cable for meggering. He did not first check to see if the cable was energized.
For corrective action the licensee added a note to insulation resistance test procedures to remind construction personnel to verify that conductors are de-energized before disturbing them and changed the Control Work Package Procedure (CCI-700A dated May 1,1984, paragraph 7e) to require cables to be tested to be clearly identified in the test procedure and require that these tests be controlled by the Nuclear Power Department.
This item is closed.
(Closed) Violation (318/81-23-03) Technical Specification Instantaneous Radioactive Release Limit Exceeded. The item was closed in Section 3 of Inspection Report 317/85-15;318/85-13 but incorrectly labeled as item No.
318/81-23-04. See below for closure of item 318/81-23-04.
(Closed) Unresolved Item (318/81-23-04) Adequacy of Installed Instrumenta-tion to Monitor High Level Releases. The licensee has installed, in re-spense to TMI Action Plan Item II.F.1 a Wide Range Noble Gas Monitoring system for each unit.
That system is currently operable on Unit 2.
The Unit I system has been installed and is undergoing final checkout before being declared operable. This item is closed.
(Closed) Unresolved Item (318/83-02-06) Pressurizer Spray Valves Drifting Open Following Loss of Instrument Air Due to Containment Isolation Signal (CIS)). These valves should be held closed upon loss of instrument air by spring pressure assisted by local air accumulator pressure.
During the current Unit 2 refueling outage the licensee will verify that the valves will remain closed upon isolation of instrument air. Additionally, Facil-ity Change Request FCR 83-60 will be implemented during the outage which will allow Instrument Air Isolation valve 2CV-2085 to be reopened from outside Containment to restore air to the spray valves.
Previously, once closed 2CV-2085 could only be opened from inside Containment. This item is closed.
4.
Review of Plant Operations a.
Daily Inspection During routine facility tours, the following were checked: manning, access control, adherence to procedures and LCO's instrumentation, recorder traces, protective systems, control rod positions, Contain-ment temperature and pressure, control room annunciators, radiation monitors, radiation monitoring, emergency power source operability, control room logs, shift supervisor logs, tagout logs, and operating
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orders. At various times during the period, inspectors' attended
' Plant Operations Safety Review Committee meetings to ascertain TS minimum requirements and make an independent assessment of the ef-fectiveness of the committee's activity.
Routine' trends in stimulat-ing questioning are generally apparent.
- No violations were identified.
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System Alignment Inspection Operating confirmation was made of selected piping. system trains.
Accessible valve ~ positions and status were examined.
Power-supply and breaker alignment was checked. Visual inspection of major compo-nents were performed. Operability of instruments essential to system performance was assessed. The following systems were checked:
Unit 2 Shutdown Cooling checked on October.24, 1985.
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Unit 2 Hydrogen Recombiners Inside Containment checked on Octo-
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ber 28, 1985.
~ Unit 2 Containment Air Coolers checked on October 28, 1985.-
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Unit 2 HPSI/LPSI/ SIT Inside Containment checked on October 28, 1985.
No violations were identified.
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Biweekly and Other Inspections During plant-tours, the inspector observed shift turnovers; boric acid tank samples and tank levels were compared to the Technical Specifications; and.the use of radiation work permits and Health Physics _ procedures were reviewed. Area radiation and air monitor use and operational status was reviewed. Plant housekeeping and cleanli-
. ness were evaluated. Verification of the following tagout indicated the action was properly conducted.
..Tagout #15040, #21 Diesel Generator checked on October 29,.1985.
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No violations were identified.
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Events Requiring Notification To The NRC The circumstances surrounding the following events requiring prompt NRC notification pursuant to 10CFR50.72 were reviewed.
For those events re-sulting in a plant trip, the inspectors reviewed plant parameters, chart recorders,-logs, computer printouts and discussed the event with cognizant-licensee personnel to ascertain that the cause of the event had been thor-oughly investigated; identified, reviewed, corrected and reported as required.
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On October 2, 1985 at.12:10 p.m. Unit 1 experienced a reactor / turbine
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trip due to an erroneous feedwater heater high level signal. This was identicalcto the trip experienced two days earlier which.the root cause could not be identified.
Portable instrumentation installed after the initial trip enabled.the licensee to positively identify the cause of~this trip as grounds on.the equipment powered by the 11 DC Bus which resulted in energization of the feedwater heater trip relay. The grounds on both all DC Buses were corrected and on the
'feedwater heater level circuit, and power operation resumed on Octo-ber 3.'
On October 13, 1985 the repair of the Reactor Coolant Pump (RCP) Con-
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trol Bleed Off Lines weld crack was completed. Conditions for the
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repair required the reactor water level be drained below the weld
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repair area. During the fill of the Reactor Coolant System (RCS) in
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accordance with 0I-10 Reactor Coolant System Fill and Vent, Centrol Room Operators (CR0s) noted an increase in frequency of the draining of the reactor cavity sump. A CR0 stationed inside the Containment to vent.the system during the fill of the RCS investigated and found no apparent cause for the increased leakage. A change in shift per-sonnel occurred and as required the plant was pressurized to 200 psi.
Simultaneously another operator was sent to continue the investiga-tion of the sump frequency increase. This operator noted water drip-ping from about one-third of one of the Containment Spray rings. The-Control Room was notified and a reverification of the valve line up was initiated which resulted in closing valve SI-329 (12 shutdown
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1 cooling Heat Exchanger outlet to Containment Spray) an additional two turns, using additional mechanical leverage to fully shut the valve.
Clean up and electrical checks of wetted components followed during the subsequent four hours.
An investigationlof this incident revealed that valve SI-329 was op-erated once during OI-3 placing the plant on shutdown cooling when the normally open valve was shut, then again during the performance of STP-0-66-1-Quarterly Valve Operability Verification which checks valve SI-329 shut.
Interviews of those operating / checking the valve indicated that both had operated the valve fro.T a reach rod, designed
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to minimize the radiation dose to operators.in the event of an acci-dent. The valve, a ten inch velan disk valve with a Tulsa Rote Han-mer Operator attached to a reach rod, is difficult to operate even when performed locally. Both operators used the position indication on the reach rod, without placing additional torque on the valve in
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order to check the valve shut.
Discussions with the shift personnel indicated that no plant policy exists regarding use of reach rods for normal plant operations involv-
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ing valve manipulation. Calvert Cliffs Instruction CCI-300, Secticn VII requires that when checking a valve, that an attempt to move the valve in the shut direction shall be performed in conjunction with L
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7 local valve position indication.
Both operators apparently performed this on the reach rod.
During a discussion with the General Supervisor-0perations the licensee stated that the above CCI-300 would be re-emphasized and a policy.would be promulgated to operators requiring the use of the-local valve operator vice reach rod for all valve manipulations except those requiring use of reach rods due to inaccessibility due to loca-tion or high radiation levels.
Issuance of such a_ policy should prevent future occurrences of this nature. The issuance of this policy will be followed by the NRC (317/85-28-01).
At 11:26 a.m. on November 1, shutdown cooling flow was lost on Unit 2
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when one of the Reactor Coolant System (RCS) hot leg suction valves (MOV 651) closed. The Control Room Operator noted the annunciation
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of the decay heat pump (Low Pressure Safety Injection Pump) low suc-tion pressure alarm and secured the running pump. Unit 2 was in Mode 6.at the time.
The refueling cavity was flooded, and refueling was in progress.. Refueling operations were immediately suspended. The M0V closure was caused by technician error while replacing a relay associated with controller 2-PIC-103.
By design MOV 651 shuts if RCS pressure, as sensed by pressure transmitter 2PT-103 (associated with 2PIC-103), exceeds approximately 300 psig.
This protects the shutdown cooling system from over pressurization.
Shutdown cooling was'quickly restored at 11:34 a.m.
The inspector discussed the event with the lead technician involved,
-the technician'.s supervisors, and a QC supervisor.
The relay was being replaced with an improved device as part of a facility change.
The actual work was being done under a maintenance order. The tech-nician was being assisted by a second technician who normally works at another licensee facility but had been temporarily assigned to this plant for the outage, and a QC inspector was monitoring the job.
The relay replacement was essentially a six step process. The first step was to install a terminal board jumper which would maintain the control circuit to MOV 651 energized. The last step should have been to remove-that jumper. The licensee's Modification and Support Group had previously decided that the relay replacement was within the knowledge and skills of the technician and, therefore, the mainte-
nance order did not include specific procedural steps. The facility change package had been reviewed by the POSRC and included a precau-tion about this relay replacement. However, that precaution was not carried over into the maintenance order.
The same technician had performed this. relay change without a problem on Unit I during its last refueling outage. At an intermediate. point during the relay-change out process, the lead technician told the~ temporarily assigned technician to complete the job while he began preparations to replace another relay.
The second technician removed the jumper in'the wrong step sequence, which resulted in M0V closure.
The lead technician apparently had not provided sufficient guidance to his assistant, a
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Although the' technician's immediate supervisors felt this evolution
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was within the knowledge and skills of the employee, the group's Gen-eral Supervisor, who has had more experience with this circuit, told i
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Lthe inspector that-this circuit is complicated enough that he feels it warrants a step by step procedure. However, he was not involved in the decision _to work without a procedure. Calvert Cliffs Instruc-
. tion CCI-200I, dated April 1, 1985, Step III.H, permits the supervi-sor to make a. determination regarding whether or not a detailed procedure is required based upon whether the work is within the skills normally possessed by maintenance personnel.
The' inspector noted that the jumper was not installed in accordance
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with Calvert Cliffs _ Instruction CCI-117E, " Temporary Mechanical De-vice, Electrical Jumper and Lifted Wire Control".
The licensee pointed out _that that procedure does not apply if installation of the Ejumper. is performed under a maintenance order and the individual per-forming the work removes the jumper during the same work period. The maintenance order must document installation and removal of the de-vice. Therefore, CCI-117 did not apply.
LThe inspector discussed this. event with the Plant Superintendent and pointed out the following:
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When detailed procedures are not included in maintenance orders (MO),
QC effectiveness is reduced in that (by procedure) M0's are not rout-ed to QC for review.for problems / hold points prior to the work'
and during.the work they have no standard or criteria to check the work against. This potentially valuable review is lost. Without
' detailed procedures, supervisor review of maintenance orders is less
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-effective in spotting problems.
Similarly POSRC review is not re-quired when detailed procedures are not included.
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10ne of the purposes for CCI-117 is to adequately review the_ effects
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of. Jumpers, etc. before they are added to a system.
The exclusion of work that-can be accomplished-in one shift does not appear to meet the overall intent of the procedure unless the details of that work
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receive.a sufficient review.through another mechanism (e.'g. detailed M0).
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In combination, the option of omitting detailed procedures in mainte-nance orders and the exclusion of certain jumper installations from CCI-117-requirements, could potentially lead to abuse and allow work to be accompitshed on safety related systems without adequate reviews for possible effects-and procedural problems.
The Plant Superintendent stated.he would further evaluate these problems.
' Licensee action to improvtc controls in this area will. be followed by the NRC (IFI 318/85-28-03).
No violations were identified.
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Observations of Physical Security Checks were made to determine whether security conditions met regulatory _
requirements, the physical security plan, and approved procedures.
Those checks included security _ staffing, protected and vital area barriers, ve-
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=hicle searches and personnel. identification, access control, badging, and compensatory. measures-when' required.
No violations were identified.
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Review lof Licensee Event Reports (LERs)
LERs submitted to.NRC:RI for review to verify that the details were clear-
.ly reported, including accuracy of the description of cause and adequacy of corrective action.
The inspector determined whether further informa-tion was required from the licensee,- whether generic implications were indicated, and whether the event warranted onsite followup. The following LER's were reviewed.
LER No.
Event Date Report Date Subject Unit 1
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'1 85-11 09/30/85 10/29/85 Main Turbine Trip Due To an Undetermined Cause 85-12 10/02/85 10/31/85 Main Turbine Trip Due to.
a Grounded Feedwater Heater Level Control Switch 85-13 10/09/85 11/05/85 RCP Shaft Seal Bleedoff Line Weld Failure 8.
Plant Maintenance-The inspector observed and reviewed maintenance and problem investigation activities to verify compliance with regulations, administrative and main-tenance procedure, codes and standards, proper QA/QC involvement, safety
' tag use, equipment alignment, jumper use, personnel qualifications, radio-logical _ controls for worker protection, fire protection, retest require-ments,_and reportability per Technical Specifications.
The following activities were included.
e Unit 2 Main Steam-Isolation Valve Actuator observed on October 25,
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1985.
MO #205-248-233A Replace Turbocharger of #21 Diesel Generator ob-
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served on October 29, 1985.
Rigging of new channel head for #22 SRW Heat Exchanger observed on
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October 29, 1985.
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. Main Steam Safety Valves observed on November 6-7, 1985.
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MO-205-10-010C Replacement of Butterfly Valve 2-SW-5155.
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Inspection of the No. 21 Emergency Diesel Generator, STP-M-11-2.
Inspection, Disassembly and Reassembly of 12" Atwood Morrill Safety
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Inspection _ Tank Check Valves per M0-8402407.
Emergency Diesel Generator Maintenance On October 30, 1985 surveillance testing being performed on the No. 21 diesel engine was observed. This surveillance, performed using STP-M-20-0, Revision 11 is a thorough inspection of all major diesel en-gine components including a lube oil analysis. A quality control inspec-tor.and a Colt Industries diesel inspector were present during the performance of STP. Both inspectors were actively involved with the in-spection and_ knowledgeable of the required surveillance. The diesel en-gine technical manual was used frequently to ensure compliance with the
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manufacturers recommendations. Work area access was properly controlled.
Alignment verification was made of selected piping systems on the No. 11 and No. 12 diesel generators ensuring Technical Specification 3.8.1.1 was
,' satisfied. The following systems' lineups were verified for both diesel generator No. 11 and No. 12:
Air start piping-
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Fuel oil piping
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l Lube oil-oiping
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Service water piping.
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No inadequacies were identified.
However, general cleanliness in diesel generator rooms No. 11 and No. 12 were noted to be below the general stan-dards maintained throughout the rest of the plant.
In particular, loose rags were'found under the No. 12 diesel. engine. Additionally, both en-
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gines have oil on their casings in various locations beyond what would be expected for satisfactory cleanliness. These conditions present an unnec-essary potential fire hazard and were discussed with the licensee. These-will be monitored during the routine inspection program.
No violations were identified.
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Surveillance Te' sting The inspector observed parts of tests to assess performance in accordance
. with approved procedures and LCO's, test results (if completed), removal j
e and restoration of equipment, and deficiency review and resolution. The following tests were reviewed:
.STP M-571-2, Local Leak Rate Testing of Penetration 61 observed on
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October 24, 1985.
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STP 2-SIT-10Y-1, Hydrostatic Testing of Safety Injection Tanks ob-
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STP M-20-0, #21 Diesel Generator observed on October 29, 1985.
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STP-M-571, Local Leak Rate Test of SI-340.
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Steam Generator Snubber Surveillance On October 28, 1985, the licensee informed the NRC that 2 steam generator snubbers on Unit 2 failed to meet their acceptance criteria during a func-tional test. TS 4.7.8.lc requires a functional test of at least 10% of
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snubbers in plant use at least once per 18 months during shutdown.
Snub-ber.No. 2-63-19 failed _its functional test for both lock up velocity and bleed rate.
Snubber No. 2-63-11 failed for lock up velocity. The
- licensee stated that a Combustion Engineering review of the failures de-tsrmined that the acceptance criteria for lock up velocity was conserva-tive.
Combustion Engineering has provided the licensee with revised acceptance criteria which brings both snubbers within acceptable limits for the lock up velocity criteria.
The failure of Snubber No. 2-63-19 to meet the bleed rate criteria re-quires, in accordance with TS 4.7.8.lc, that an additional 5% of the snub-
-bers be functionally teste'd until no more failures are found or until all snubbers have been functionally tested.
Calvert Cliffs' TSs do not speci-fy however whether 5% of all plant snubbers need to be tested or 5% of the same type of snubbers -(mechanical / hydraulic or a large bore or small bore)
that failed the functional-test.
Discussions between the' resident inspector,.the licensing project manager, and regional specialist resulted in the' determination:that the snubber type (large or small bore) distinction was erroneously omitted from the Calvert Cliffs TS, that the-intent of the TS is to provide additional con-fidence in the area of technical concern i.e., large bore snubbers.
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- dard TSs include the type distinction and therefore it was determined that only 5% of the steam generator snubbers (large bore) need be tested to satisfy TS 4.7.8.lc.
The licensee plans to submit an amendment change to clearly. designate snubber type in their TSs and thereby prevent any ambigtity in future interpretations of this TS.
The licensee functionally tested steam generator snubber No. 2-63-20 to meet the~5% test requirement. This snubber passed under the revised Com-
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bustion Engineering lock up velocity criteria and the existing bleed rate criteria.
In addition, although not required by TSs, the licensee tested an additional steam generator snubber to ensure confidence that the in-stalled snubbers are performing their intended safety related function.
This snubber, No. 2-63-20, also met the revised lock up velocity criteria'
and the existing bleed rate criteria.
During the above investigation, the inspector'also reviewed Surveillance
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Procedure STP M-11-2, Revision 14 which provides the guidelines for iden-tifying, removing, testing, calibrating, accepting, and installing a
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representative sample of at least 10% of the safety related snubbers as required by TS 4.7.8.1.
A representative sample.is required to include
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those listed in Table 3.7-4 as "especially difficult to remove" or "in lhigh radiation zones". A review of Attachment A of STP M-11-2,' Revision 14 revealed that the sample chosen for the current Unit 2 refueling met the intent of Technical Specifications.
Further roview of STP M-11-2 re-
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p vealed that an adequate engineering analysis was performed for the failed E
sten eenerator snubber as required by TS 4.7.8.lc.
No violations were identified.
F 10. Unit 2 Refueling Outage On October 19, Unit 2 performed an orderly shutdown to commence its sixth refueling outage.. The planning effort and control of the project has been very well conducted. Outage goals were as follows:
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47. scheduled days duration Less than 250 person-rem exposure
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Maximize use of ALARA concepts
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Complete oli priority A and B maintenance
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Complete all outage modifications
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Eight major work paths were identified consisting of 2,100 activities and 110,000' planned man hours of work.
Each work path identified the major
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activities, prioritized work, set milestones, identified potential prob-
'lems, and. identified shift work schedule for each area.
An independent effort regarding ALARA has, as of the middle of the outage, shown a very significant improvement over previous outages, as follows:
Shielding the Refueling Pool 44' floor.resulted in a 50% decrease of
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exposure compared to last outage.
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Due to review by the ALARA group, changes were made to primary side steam generator work (i.e., Nozzel Dam and Eddy Current equipment installation and removal). This required more mock up training, ad-ditional on the job supervision and stressing group cooperation.
This resulted in a reduction of from 42 man-rem installation of
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equipment last outage to 7 man-rem for installation of equipment this
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Changes were made in the methodology of shielding the Regenerative
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Heat Exchanger.
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More briefings to contractor health physics technicians and group supervisors regarding their role in ALARA.
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More cooperation between ALARA Coordinators, dosimetry and unit au-pervisors, resulting in lowering the maximum dose to individuals,
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-These efforts ha've resulted.to date in a total outage exposure of 71 man rem of a scheduled 250 goal. Last outage's total was 276 man-rem.
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Outage communications and supporting activities appear to be a significant contributor to the thus far success of this outage. General planning, information, and status. meetings are conducted each morning followed by technical problems and coordination meetings immediately thereafter.
Dai-ly general maintenance meetings are conducted for the coordination of work for_the operating unit.
Plant Operations Safety Review Committee meetings are held three times a week and prospective managers meetings for the re-
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structured organization occur weekly. Meetings attended by the resident inspectors have been conducted in an orderly, succinct manner.
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The outage control staff has clearly defined responsibilities of the vari-ous work groups, and with the Plant Superintendent's endorsement holds groups accountable for work progress. This has resulted in the critical path'being 80 hours9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br /> ahead of schedule on day 1.9 of the 47 day outage.
To date the inspectors observed various aspects of the following major activities in progress. Most activities are yet to.be completed.
Refueling of the reactor and associated activities
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Overhaul'of 21 MSIV actuator
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Replacement of service water heater exchanger channel heads -
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Reactor vessel water level monitoring system modification 21. Emergency Diesel Generator overhaul
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Ultrasonic testing of secondary and primary system piping
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Inservice inspection hydrostatic pressure tests of safety injection.
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tanks Addition of. human factors up grades and engineering enhancements to
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the contrc.1 boards
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Upgrading.various electrical switches and connections to environmen-
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tally qualified models Reviewed safety analysis for relocating air supply line for CV-2035
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Removal of Incore Instruments (ICI) wires
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Attended briefing for " jumpers" installing Nozzel Dams in steam
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generators Removal and testing of steam generator snubbers
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Inservice inspection of salt water system piping at circulating water-
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system Inservice inspection of salt water system piping at service water
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system Local leak rate testing of various valves inside Containment
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Duri_ng inspection of.the activities associated with disassembly of salt water system and components, the inspector independently examined the con-
~dition of the surfaces of components and piping exposed to the salt water-environment.
The area surrounding.the volute and impeller of the 21 circulating water pump appeared.in very good condition, with little marine growth (due to
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ivelocityofflowLaroundthepumh).-^Marinegrowthdidsignificantlyin-
-4 crease as. th'e insp~ction progressed toward the condenser.:in the circulat -
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ing(wat 5 piping.,. However,L the. growth lwas.not.more than what might be
' _ _
expected, i..e.,E2-3linchesiin length.' Engineers' designated various points
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<to be inspected?and where marine growth should be ; removed for examination -
'
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- and:possible refurbishment.(1.e.,1re-cement /mortarLthellining). The pip-~
-
- ing.in!the ar_ea of the Service' Water Heat Exchanger (SWHX), appeared clean g
lwithilittle marine growth;'no evidence of significant corrosion.
Several P
'castLiron butterfly: Valves are installed-in'this piping. One-valve,
'-
-
l 2 SW-5155' was observeo'during its removal. for replacement.. The. valve was
.
'
-beingLreplaced because,the Surveillance Test Procedure STP-0-65 results-
'
= exceeded the acceptance criteria for closing time. The valve condition'
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,
,appe'ared to;have minor. pitting and only slight corrosion.
J tion of the area is good.
_ General condi-p
'
,
,
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Ihe:inspectorshlantoviewthesalt'waterportionsoftheComponentCool, f
ing' Heat Exchanger (CCHX) when.they become available..This Js a low flow p
-
- area where more significant' corrosion and marine growth is expected.., Cur-t
.
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'rently,-the. licensee 1 continues'to examine salt water systems, salt-water g.
'
R-7 pumps,- and 'arelin thelprogress of completing installation of' the new rub
".
F iber lined' channel heads for the SWHX and CCHX.
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-
As previously fidentified in:Inspec';. ion Report 317/85-13;318/85-15;the.in-
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- spectors maintain.a concern regarding the licensee's safety analysis fail-
-
"
iure to' address:the use of Belzona and coal tar epoxy on/in safety related
.
- 1 systems,:andzfailure to address the seismicity aspects of the degraded
1 salt' water pumps.
-
No violations were' identified.
. ^ '
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- ll.
Review o_f Main Steam Line Safety Valves
-
L _
- During the Unit' 2 shutdown /cooldown for the current refueling outage
.
.(shutdown began on October' 18,.1985), the lift setpoints of the main'
,,
. steam' safety. valves (MSSV) were checked. in accordance with Surveillance
'
'
-Test' Procedure STP M-3-2, Revision 6' dated November 7,-1984.
The data ~
'
-from this surveillance is listed in Attachment-1..The valves are manu-
<;.
-
.factured by Dresser Consolidated, type 3700 valves, and:are checked by.
hydroset with Reactor Coolant temperature between 495 and.515 degrees =
Fahrenheit. Eleven of the-sixteen valves were.found to have lift values:
-
"outside the. range allowed by Technical ~ Specification-(TS). 3.7.1.1 (TS
.'
l lift retting +/- 1%). Those setpoints which exceeded the +/- 1%. limit
"
' had drifts ranging from 22 -to 71 psi.
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St.nilar problems with setpoint drifts were experienced during the Spring-Ws 1985 UnitEl refueling outage and during the previous-Unit 2 refueling out-
,
- age _(e.g. 13(Unit 2 valves-had to be adjusted).
In the Spring of'this'
'
-
'
,
-
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year.the licensee received NRC approval for a TS revision providing a
/
. wider range of' allowable' lift settings for the MSSVs'. The same TS revi-
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sion was requested and is currently under review by the NRC for Unit 2.
,
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. In~ addition to the widened lift setting band for each valve, the new TS
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'also states that settings are acceptable if, for~each steam line, any two.
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M ialVe's.liftbetweenL935.and995.psig,twoother..valvesliftbetween935 andjl035 psig and the: four remaining. valves lift between 935 and 1065
.
ipsig.1
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SeNeralLactualtliftvaluesobtainedth'isUnit2outagefell;outside~the
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~~ A allowable range ~of the new TS.
Specifically, eight valves-were outside
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"their:individualilimits. On'one header no valves lifted in either the low x-
- or mid
- lift' rangeside' scribed above. On the second header, only one valve
': '
' ::1ffted in the low range.
'
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,
,
f Historically, the licensee had some.less severe drift problems with those
'
valves in the 1977/1978 time frame. They worked with the vendor and es-
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- tablished a practice of checking lift 1 settings 'immediately before an out-1 age.at elevated RCS/ steam generator temperatures. The problem disappeared
'
- and.very good.results:were obtained until-the Spring of 1984. After sig-
'
inificant' drift problems began to' occur in 1984, the lice <;ee discussed the x.
'%
- : problem with the vendor, _ reviewed their work practices, reduced the over-
.
X
. haulffrequency on each valve from five years to three years, revised the.
"
1survet11ance teststofrequire checking all sixteen valves each outage, and forderedLnew hydrosets. ' Currently, they are re-looking at failure. data,
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,.
calling;in afvendor technical representative, and having the hydrosc.t's
! calibration checked.
,
,
^
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~
- The licenseeLalso plans to send off.two of the valves with high drift-
.problemsito Wiley-Laboratories. Tests will be conducted to determine (1)
- if ambient' room temperature can, affect lift setpoints, (2).if testing at-
,
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~ :RCS/ steam-generator. temperatures and pressures.somewhat below normal oper-L ating' conditions can affect setpoint, and-(3) how long it takes for valve-
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componentitemperatures to steady'.out after a plant heatup/cooldown..Both (valves will' have' their setpoints set with a common hydroset:(new) and the.
F Evalv'es will,be " pop" tested to verify setpoint.. The valves will be re-ow
- turned,'. installed and rechecked using the same hydroset as.used at the.
%[py test facility. :All other valves will-then be checked with the same r
- hydroset.
, my
^
'
,
-
- The inspectorsLwill continue to monitor-licensee progress in resolving the-
"
'
LMSSV setpoint drift problem (IFI.318/85-28-02).
'
.'Atithe beginning of the outage the inspector checked five MSSVs and found v
Lthe cap / drop lever assemblies to be loose on four of those valves. The-31ock-screws securing. the assemblies to the valve yoke were missing on two
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. valves and were loose on the' other two valves.
If these assemblies are.
"
loose, sit may be possible during a valve 11ft for these assemblies to vi-
, A brate and cock in such a manner as to contact the release nut (on the -
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c w.-
- spindle)'and prevent valve closure. The inspector pointed this out to the f,
'
licensee.. They informed the inspector that they will examine methods of l
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^
improving 1the. locking device and improve STP M-3-2 to : add a step at the
'
f end of the procedure to tighten-the locking screw (currently only a gener-
-
!alEstep exists stating to " reassemble the valve which was disassembled in
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Step;3", therefore.the lock screw could be overlooked).-
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'The inspector also compared STP M-3-2 with the valve technical manual (Dresser Maxiflow Safety Valve Manual 3700) regarding setpoint testing and adjustment. Only one disparity existed.
The procedure stated to increase hydroset pressure until the valve begins to simmer audibly.
The technical manual ~ states: " increase the hydraulic pressure to the hydroset to obtain-a lifting force that causes the valve to just barely " spit" or simmer.
This pressure can readily be determined because of a slight downward de-flection of the pointer on the hydraulic pressure gauge installed on the pump of the hydroset".
The inspector was concerned that the audible threshold may vary with individuals and background noise, leading to error in setpoint determination. The licensee stated that the audible simmer
.and gauge pointer deflection occur simultaneously. However, they also had noted this disparity and had already planned to change the procedure to agree with the technical manual.
12.
Licensee Action on NUREG 0660, NRC Action Plan Developed as a Result of the TMI-2 Accident.
The NRC's Region I Office has inspection responsibility for selected ac-tion plan items.
These items have been broken down into numbered descrip-tions (enclosure I to NUREG 0737, Clarification of TMI Action Plan Items).
Licensee letters containing commitments to the NRC were used as the basis for acceptability, along with NRC clarification letters and inspector judgment.
The following item was reviewed.
II K.3.25 Reactor Coolant Pump (RCP) Seal Integrity Following Loss of
--
Offsite Power. This item was previously addressed in Inspection Re-port 317/82-16 and report 317/85-24, 318/85-20.
In a Safety Evaluation issued by NRR on October 7, 1985, the staff deter-mined that operator action to reinstate semi cooling is acceptable and therefore Calvert Cliffs Units 1 and 2 complied with the requirements of TMI Action Plan II.K.3.25.
This item is closed. '
s 13.
Review of Radiologicai Effluent On October 22, 1985 the inspector performed a sampling rbview to verify licensee compliance with recently issued (July 1985) Radiological Effluent Technical Specifications (RETS).
The inspector reviewed Techn'ical Speci-fication (TS) requirements for dose and dose rate for gaseous effluents (TS's 3.11.1.1, 3.11.1.1, and 3.11.2.3) and the principle implementing procedure (RCP-1-604, Gaseous Waste Releases). He then reviewed related records and discussed aspects of the program with the engineer responsib?e for implementation of RETS, a Rad-Chem technician, and the Chemistry Su-pervisor.
RCP 1-604 was the last procedure to be modified to include RETS requirements (Revision 9 approved October 4,1985).
Since that r'evision licensee personnel have noted several problems with the procedure and a subsequent change is planned.
Those problems included:
needed steps to calculate maximum allowable Wide Range Noble Gas monitor response in micro CI/CC and missing portion of procedure for calculating final activity re-lease.for Containment purges.
.
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The inspector reviewed Gaseous Waste Release Permit (GWRP) P-94-85, modi-fied Unit 2 Containment Purge conducted on October 20, 1985, and noted that the maximum allowed Main Vent Noble Gas monitor (RI-5415) response was calculated to be 2135 cpm. This value should represent 150*; of the expected detector response based upon the activity in the gaseous release.
During the_ release, the detector only registered a count rate between
,
60-75 cpm.
With no releases in progress, RI-5415 on Unit 2 shows a count rate of about 70 cpm. The Shift Supervisor on watch during the Containment purge described above stated he had noted that the Unit 2 Wide Range Noble Gas monitor was indicating an activity increase but RI-5415 was not respond-ing. He contacted chemistry and had them compute the maximum allowed Wide Range Noble Gas monitor response to assure release limits wero not being exceeded. The Shift Supervisor, however, did not initiate c Maintenance Re' quest (MR)'on the detector at that time. He informed chemistry and as-sumed they would initiate corrective action.
The inspector noted that Unit 2 RI-5415 demonstrated a similar low response on October 11, 1985 (Waste Gas Decay Tank Permit W-90-85, maximum allowed count rate = 1670 cpm, actual count rate = 100 cpm).
Chemistry personnel although knowledgeable of a discrepancy between ex-pected and actual detector response had not initiated a MR.
The inspector expressed concern to the Chemis,try Supervisor and the Shift Supervisor
"
that RI-5415 was not responding properly and recommended an MR be submit-ted. That evening a source check and instrument drawer calibration check were done on the detector. These checks revealed no problems. The in-spector then discussed the problem with the Plant Superintendent (PS) and recommended that RI-5415 readings be considered suspect until further checks could be run to confirm operability.
The PS agreed that a problem did seem apparent and stated he would have it further investigated. The inspector also expressed concern regarding why the licensee personnel had not _ initiated a request for maintenance until he urged this action.
Licensee action to further evaluate the operability of Unit 2 RI-5415, perform corrective maintenance (if necessary) and sensitize personnel to recognize / initiate corrective action for radiation monitor response anomolies will be followed by the NRC (318/85-28-01).
14. NRC Contractor Review of Post Accident Effluent Monitoring On October 8, 1985, the licensee's post-accident monitoring system, in-stalled pursuant to the requirements of NUREG 0737, Item II.F.1-2, " Sam-
',
pling and Analysis of Plant Effluents", was reviewed by a specialist from Bettelle Laboratories accompanied by an NRC inspector.
Such review was for the purpose of comprehending problems associated with representative sampling of effluent release paths in accident conditions. The review included examination of the system design, the evaluation of operating
'
data and the determination of operational parameters that could effect
,
representative sampling.
it is expected that the data and information L
l
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___ __ _ _ - __________ _ ____ _-_
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..
.
. acquired in this review will assist the NRC in the development of generic guidance in this area.
The licensee representatives assisting in this review were cooperative and helpful in understanding system design and performance capabilities.
No unsatisfactory. conditions were noted.
15. Organizational Changes On September 20, 1985, the Board of Directors of Baltimore Gas and Elec-tric Company announced plans to restructure the utility to include a sepa-rate Nuclear Energy Division.
Functional responsibilities will become effective January 1,1986. The Nuclear Energy Division will consist of a Vice~ President and four major departments.
The Plant Superintendent's position has been deleted, however, each department will now consist of an onsite Manager and a Vice President located primarily onsite. Major-changes are as follows:
'Mr. Joseph Tiernan, Manager-Nuclear Power was reassigned as of Octo-
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ber 1,<1985 as Vice President, Engineering and Construction until January 1, 1986 when he will become Vice President of the newly cre-ated Nuclear Energy Division.
Mr. Walter Lippold replaced Mr. Tiernan as Manager-Nuclear Power un-
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til January 1, 1986 when he will become Manager, Nuclear Engineering Services.
Mr. Leon B. Russell currently Plant Superintendent will become Manag-
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er, Nuclear Maintenance Department.
,
Mr. James R. Lemons will become Manager, Nuclear Operations
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Department.
Mr. Robert Douglass will be Manager, Quality Assurance and Staff Ser-
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vices Department.
(The name of the department will be changed from Quality Assurance to reflect moving quality control to the operating departments and bringing additional divisional support functions in with the quality assurance function.)
'
Reassignments for General Supervisors and Supervisors for each department were announced on October 24, 1985. A review of qualifications for those individuals whose reassigned positions are addressed in ANSI 18.1 1911
" Selection and Training of Nuclear Power Plant Personnel", to which the
. licensee is committed to'in the Quality' Assurance Manual, was performed.
The position of Operations Manager as addressed in ANSI 18.1 section 4.2.2 requires that'a Senior Reactor Operation's License beheld by the individu-al occupying the position.
Currently, the proposed Manager of Nuclear Operations Department does not maintain a Senior Reactor Operators posi-tion..:This is unresolved (317/85-28-02) pending revision to Licensee's
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Quality' Assurance program which should describe the newly created managers positions such that a comparison can be made to the ANSI requirements.
Another concern regarding the r'.tructuring of the organization involves the Plant Operations end Safety Review Committee': (POSRC) membership.
,
The~ restructuring removes many years of plant experience end several key members who have demonstrated good conservative judgment :ombined with a clear understanding of the significance of potential safety issues.
Re-moving the Plant Superintendent position, replacing the General Supervisor LTraining and. Technical Services, and replacing in the recent past the Gen-eral Supervisor, Operations, appears to have significar.tly reduced the experience level of the POSRC and in fu;c, totally eliminated the key fig-ures who'have in the past been the most dynamic and significant contribu-tors to the safe operation of the facility.
Removing these members in a radical manner will remove much of the plant knowledge currently available-to support a sound approach to resolution of technical issues, devitalize an already over-burdened POSRC, and cause a process to o cur in which old-issues' may be resurrected, both operationally and from a ragulatory view.
LThe inspectors discussed-this with the Plant Superintendent and requested that the licensee consider maintaining as many of the principal contribu-tors 'as possible for as long as 'possible.
The restructuring may provide many. positive effects, bewever, the core of POSRC is being significantly
. reduced.
Tha effectiveness of the POSRC was addressed in the~ previous SALP report and will be carefully monitored by the inspectors in the future.
16. Radiological Controls Radiological. controls were observed on a routine basis during the report-ing period.
Standard industry radiological work practices, conformance to radiological. control procedures and 10CFR'Part 20 requirements were ob-
. served.
Independent surveys of radiological boundaries and random surveys of.non-radiological points throughout the facility were taken by the inspector.
~17.
Review of New Emergency Operating Procedures (EOPS1 During the period the inspector reviewed two new E0P's (E05 '40 Loss of Offsite Power / Natural Circulation and EOP 600 Steam Generator Tube Rup-ture) which will go into effect on January 1, 1986. Operators are cur-rently receiving simulator training on the E0P's.
Following a recent Reactor Coolant System (RCS) Natural Circulation (NC) test at a B&W-de-signed plant, Steam Generator (SG) pressure rapidly increased and a SG safety valve lifted when reactor coolant pumps were restarted. Neither E0P 200 or 600 contain any precautions to warn operators of this type of problem. The' inspector informed the licensee"of the potential for.this SG pressure increase, and the licensee decided to see if their plant would
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react in a_similar fashion by running a test scenario on the simulator.
- _
-The simulator showed that SG pressure would indeed increase.
With RCS temperature in the range of 520 degrees Fahrenheit, during a re-covery from two loop NC, SG pressure could exceed the lowest allowable SG safety valve setpoint (935 psig).
During a recovery.from single loop NC,
.SG pressure almost certainly would exceed the lowest relief valve setting.
The licensee plans to further investigate this possibility, train opera-tors on the problem, and (as appropriate) revise procedures.
The inspector noted that recovery action E of E0P 600, Steam Generator
~
Tube Rupture (SGTR), directs that a subcooling margin of 25-35 degrees Fahrenheit be maintained.
Recovery Action M says to isolate the affected SG when hot leg temperature (T ) is less than 520 degrees Fahrenheit.
If H
SG isolation is attempted at T about 520 degrees Fahrenheit and a.
H subcooling margin of 35 degrees Fahrenheit the inspector determined that RCS pressure would be 1090 psia.
The isolation action could then result -
in a-:SG pressure of 1090 psia, which-is well above the setpoints for the SG safety valves.
Safety valve opening would be counter to the objective of the procedure which is to isolate and contain the leakage. The inspec-tor discussed this with the General Supervisor, Operations,'the individual responsible for generating and correcting the E0P's,'and the Operations Traini_ng - Supervi sor.
Further investigation for possible procedure changes will be conducted.
The inspector also pointed out to the individurl responsible for the E0Ps that Recovery Action 0 of E0P 600, regarding cooldown/depressurization of the RCS with the affected SG isolated, directs the operator to maintain 25-35 degrees Fahrenheit subcooling margin in the unaffected SG but is silent about maintenance of subcooling margin in the affected SG. Neglect of that margin, in NC cooldown, could potentially lead to bubble formation
- inside'the tubes of the affected SG and aggravate cooldown control prob-lems. The individual responsible for the procedures stated he would also-investigate this. item.
Licensee action on the possible procedure problems noted above_will be followed by the NRC (317/85-28-03).
'
The inspector observed portions of an operator simulator training session.
The simulator is an excellent facility.
Ine instructor was capable and very professional.
The participating operators maintained a serious atti-tude.toward their training.
The concept and form of the new E0P appears very good.
The operators ap-pear to be receptive to the new procedures. Operator involvement in the
. development of the E0P's.has been maintained and the idea of testing the procedures out on the simulator and accomplishing training at the same is excellent.
- 18.
Review of Spent Fuel Pool Cooling Although not required for safe shutdown, the Spent fuel Pool Cooling sys-tem (SFPCS) was reviewed because of its importance to safety, in that it
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provides shielding, cooling, and subcritical Boron concentrations for re-feeling and long term storage of spent fuel.
The following areas associ-ated with the SFPCS were examined in order to assess overall system
,
capability:
housekeeping, operating procedures, control room indications, surveillance, and maintenance.
System documentation was reviewed to assure adequacy in terms of training, operational, and regulatory needs. The system description, " Spent Fuel Pool and Spent Fuel Pool Cooling and Purification Systems",. System De-scription No.10, July 1983 provided a clean, concise description of the system design and operation. The FSAR also presents an accurate system description. The FSAR system drawing (M-58), in Figure 907, contains sev-eral errors and omissions:
the refueling pool No. 11 discharge point is not shown as are the No. 21 and No. 12 s,7ent fuel pool discharge spargers, and several alarm locations are not shown. The errors in drawing M-58 also appear in-Operations Drawing (0M)-58. The licensee was informed of the errors and agreed to correct these errors.
Plant housekeeping related to the SFPCS was observed in the following areas: the 69 foot level spent fuel pools, the 27 foot level SFPCS rocm, and the 45 foot level refueling water tank (RWT) rooms. The Spent Fuel Pool Demineralizer and Filter Room was inaccessible due to the normally high radiation levels. The equipment, piping, supports and general sur-rounding areas of the SFPCS appeared to be clean and well kept, with a notable absence of tools and extraneous material, except in those areas where specific activities were in progress.
The inside of electrical cabinets Sm-1411 (motor control center for No,. 11 SFPC pump) and 52-2411 (motor control center for No. 21 SFPC pumps) were relatively free of dust, combustible or other adverse conditions.
-The operating procedures for the SFPCS contained in 01-24 Revision 17, provides a clear description of a considerable number of functions associ-ated with spent fuel and refueling pool cooling, filtration and RWT recir-culation. Each function is clearly described including initial conditions, procedure for obtaining the desired system function, and re-turning to initial conditions. The attachment to 0I-24 contains the sys-tem valve line up. An independent verification of valve position was performed by the inspector.
The following inadequacies were noted:
the location of SF P-237, given in the procedure as "above SFP", was actually found on the 45 foot level-of the Auxiliary Building, west side; the iden-tification on valves SFP-5 through SFP-14 do not agree with that provided i-in 01-24. While the incorrect procedure location of the low point drain valve SFP-237 is minor, the identification problem with SFP-5 through SFP-14 is more significant in that these valves are needed to determine the location of spent fuel pool liner leakage.
The licensee was made aware of these problems and the description in 0I-24. The licensee imme-diately initiated a change to the procedure to correct the inadequacies.
-
With regard to 01-24, it is significant to note that no procedure exists for supplementing the SFPCS with the shutdown cooling heat exchangers should the need arise. This capability is described in Section 3.2.5 of
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the system description. Moreover, the removable " spool pieces" needed to i
~
-achieve the SFPCS/ shutdown cooling interface are in place; thus, this con-
' figuration could be utilized at this time. The inspector discussed with
[
the licensee the possible use of the cooling interface which may be neces-
- sary during full core off load in the future and the need for a procedure.
The valve and pump controls, alarms and alarm manual associated with the SFPCS were reviewed for each SFPCS alarm to determine if adequate guidance was available to operators to cope with off normal (alarm) conditians.
All SFPCS alarms were verified to be properly addressed in the riarm manu-al except as follows: alarm window K-20, "SFP Level Temp HI" does not specify operator, action in the event that high spent fuel pool level is detected. The licensee provided a corrective change to the alarm manual-when notified of this condition.
Plant procedures were reviewed to determine if the licensee is in compliance with the-surveillance requirements of Technical Specifications (TS) as follows:
TS 4.9.1(1) and (2) Fuel pool reactivity requirements, are satisfied
--
by performance of Procedure NEP-1, Revision 8 (Nuclear Engineering Procedure
"Incore Fuel Management").
Calculations were reviewed for boron concentrations to maintain K effective less than.95 for Units 1 and 2 cycles 5 and 6; TS 4 9.11 Spent Fuel Pool Water level requirements are perfc,rmed by
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STP-0-87-1 " Borated Water Source Operabilit/ Verification". A random sampling of data obtained during 1985 indicate ths.t this weekly sur-veillance interval is being observed. Additionally, TS 1 4 2 minimum
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source range neutron detectors is ascertained on shift logs and in STP-0-61 " Source Range Instrument Functional Test" and OP-5 Mode 6 checklist; and TS 3.9.4 regarding Refueling Containment Integrity is verified by
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STP-0-55A " Containment Integrity Verification. A review of the above surveillances was performed for those-associated with the Unit 1 1985 Spring outage..No inadequacies were identified.
Corrective and preventive maintenance programs for the SFPCS were reviewed for electrical / instrumentation and mechanical components.
Preventive maintenance is performed on all temperature instruments (PM No.
,
1-67-I-RQS-100) and pressure instruments (PM Nos.1-67-I-RQS-101 and 1-67-I-SA-102).
Tho inspector could not identify level instrumentation as-part of the preventive maintenance program.
Level instrumentation pro-vides an important indication of off normal (alarm) conditions (i.e., as-identified in IE Bulletin regarding cavity seal failures) and therefore should be,part of the preventive maintenance program.
Electrical preven-tive maintenance includes the SFPC pump breakers 52-1411 and 52-2411 (PM Nos. 1-67-E-2R-1 and 1-67-E-2YR-1). A " search" using the licensee's com-puterized corrective maintenance system indicated a backlog of only two
,
items requiring corrective maintenance for electrical / instrumentation com-
_
ponents. Both items had been recently identified.
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The mechanical. preventive maintenance program only includes the SFPC pumps (PM Nos. 2-67-M-A-2 and 2-65-M-A-3).
No motor operated or control valves
-
are used in the SFPCS.- A print out of outstanding mechanical corrective maintenance fitems (and a list of items not yet entered into the computer system) indicated only a few items, mostly leaky valves.
'
-With the exception of the water level instrumentation addressed previous-ly, the preventative and corrective maintenance programs for the SFPCS appear to include the correct components and appears to be keeping pace with. identified failures.
In' conclusion, the SFPCS appears to be a well documented and well main-tained system.
Procedures for system operation and diagnosis of off nor-
. mal conditions appear adequate for their purposed. The licensee appears
'
to be in compliance with applicable regulatory requirements and is up to date on preventative and corrective.naintenance.
.No inadequacies were identified.
19.
Review o_f Hydrogen Recombiners During the period a review was conducted of the hydrogen recombinqr and the hydrogen purge systems. Accessible valve positions and component con-ditions were examined. Power supplies, breaker alignments and a visual inspection of major components were performed. Operability of instruments essential for system performance was assessed. The inspector reviewed the surveillance test procedures for' the hydrogen recombiner system. The re-view conducted specifically addressed the adequacy of the surveillances in meeting the intent of _. Technical Specifications for the hydrogen recombiner
. system. The following procedures were reviewed:
STP 0-28-1 & 2 Hydrogen Recombiner Semi-annual Functional Test.
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STP 0-58-1 & 2 Hydrogen Recombiner 18-month Functional Test.
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STP M-580-1 & 2 Hydrogen Recombiner Instrument Checks.
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STP M-581-1 & 2 Hydrogen Recombiner Inspection.
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A review of system descriptions and FSAR indicated the system was well
>
defined and reflected actual system status.
Technical Specifications 4.6.5.2 Hydrogen Recombiner Surveillance Requirements were reviewed rela-tive to the above surveillance procedure. All specifications were ade-quately addressed. A tour of Containment during shutdown conditions revealed that the H Recombiners appeared in good condition.
'
'During the review of STP-M-581 it was noted that no acceptance criteria or documentation of results of a visual inspection ~is found in the procedure.
The procedure does required that the applicable inspection be performed and does contain acceptance criteria for resistance readings on the heater coils.
Inclusion of documented results of the required TS 4.6.5.2(b)(2)
visual inspection in the applicable procedure is unresolved
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...
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(317/85-28-04). The' inspector noted as a positive attribute that the-licenseestrends TS related Hydrogen Recombiner parameters and reviews this data quarterly.
'
No other inadequacies were noted.
20. Measuring and Test Equipment (MTE) Program Review On October 10, 1985 the inspector discussed the MTE Program with the MTE Supervisor, the Instrument & Control Supervisor, and MTE technicians. A review of several instruments, both portable and installed was performed for the following:
traceability to the calibration source; as found and
.as calibrated data; identification of standards used; identification of calibration procedures used; limitations on use; date of calibration; date of next required calibration; and name of person performing calibration.
The inspector noted that the MTE shop appeared very well organized, with formal controls for almost all' aspects, and close adherence to Quality
'
Assurance Procedure (QAP-17) " Control and Calibration of Measuring and Test Equipment".
The department maintains records of the calibration standarc's used and
.their traceability to nationally recognized standards (National Bureau of Standards,: NBS).
Instrument errors and accuracies of these calibration standards are controlled to a significantly greater conservative margin than the MTE instrun.ents being calibrated.
The accuracy for the standards is required to be a minimum of four times more accurate than the instrument being calibrated; however, many are often ten times more accurate.
Storage of test equipment is generally good.
Controls are derived from Military Standards and Institute of Nuclear Power Operations guidelines for. Control of Calibration standards and shop calibration equipment.
The only significant weakness noted in the program involved the control of the equipment, in that: no formal controls exist which prevent the use of uncalibrated equipment; no formal policy or statements stating MTE must be in calibration prior to use; no controls exist to prohibit use of MTE by unauthorized or unqualified personnel or for unauthorized usage, i.e.,
wrong meter on wrong equipment.
'The' inspector noted while inspecting stored MTE that personnel in the equipment storage room kicked boxes with MTE enclosed and some rough han-dling occurred. Also noted'were battery operated equipment on " charge" within the shelves of the equipment store room. This should take place in-
' a designated well ventilated area. The control of issuance / usage of MTE is on.the " honor" system, which requires personnel to log equipment in and out on a usage log and fill out several required entries, most were illeg-
-ible. This control does not provide adequate assurance that MTE is being recorded when used or for what use.
The controls associated with the issuance /use of MTE need improvement. The inspectors will follow.the licensee's action.in regards to these controls (317/85-28-05).
.
b
21.
Review of Periodic and Special Reports Periodic and special reports submitted to the NRC pursuant to Technical Specification 6.9.1 and 6.9.2 were reviewed.
The review ascertained:
inclusion of information required by the NRC; test results and/or support-ing information; consistency with design predictions and performance spe:-
ifications; adequacy of planned corrective action for resolution of problems; determination whether any information should be classified as an abnormal occurrence, and validity of reported information.
The following periodic reports were reviewed:
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August and September Operations Status Reports for Calvert Cliffs No.
1 Unit and Calvert Cliffs No. 2 Unit, dated September 11, 1985 and October 7, 1985, respectively.
Revision to June and July Operating Data Reports for Calvert Cliffs
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No. 2 Unit, dated August 23, 1985.
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October Operations Status Reports for Calvert Cliffs No. 1 Unit and Calvert Cliffs No. 2 Unit, dated November 6,1985.
22.. Unresolved Items Unresolved items require more information to determine their acceptability and one such item is discussed in Detai'. 19.
23.
Exit Interview Meetings were periodically held with senior facility management to discuss the inspection scope and findings. A summary of findings was presented to the licensee at the end of the inspection.
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v(:[: -.,
ATTACHMENT 1 i
SAFETY VALUE'
TS MAX ACTUAL LIFT TOTAL NUMBER SETPOINT-ALLOWABLE PRESSURE ERROR DRIFT 4000 985.t 1%
995-1037
52
~
>4001 985 i 1%
-995 1040
65
, 002 995 1%
1005 1059
64
.
'
4003-995 i 1%..
1005 1047-
52 4004 1015 i 1%-
1025 1070
55
_4005 1015 t 1%
'1025 1054
39
-
4006
.1035'i 1%
1045-1104
- 69 4007 1035 i 1%
1045 1106
71
'
3992
.985-t 1%
995 991
--
3993-
~985 t'1%
995 1015
30 3994.,
-995' ~ 1%
1005 1001.
--
.-3995 995 i 1%
1005 1035
- 40 3996-1015 1: 1%
'1025 1024
--
L.-7 73997 1015 i 1%
1025 1020
~
--
3998 1035 1 1%'
1045 1044
--
.3999-1035.1%
1045 1057 12-
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