IR 05000317/1982016
| ML20062D020 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 07/15/1982 |
| From: | Architzel R, Mccabe E, Trimble D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20062C980 | List: |
| References | |
| 50-317-82-16, 50-318-82-14, NUDOCS 8208050429 | |
| Download: ML20062D020 (12) | |
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DbNos: 50317820624 50318820624 50320790238 820702 820509 820604 820514 820602 820604 U. S. NUCLEAR REGULATORY COMMISSION Region I 50-317/82-16 Report No.
50-318/82-14 50-317 Docket No.
50-318 DPR-53 C
License No. DPR-69 Priority Category C
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Licensee:
Baltimore Gas and Electric Company P. O. Box 1475 Baltimore, Maryland 21203 Facility Name: Calvert Cliffs Nuclear Power Plant, Units 1 and 2 Inspection At: Lusby, Maryland Inspection Conducted: June 15 - July 13, 1982 Inspectors:
- I 7/d/fL R. E. ArchitzeT, Senior Resident Reactor Inspector date signed ffh-fir 7,I) /9 2.-
I D. C. Trimble, Resident Reactor Inspector date signed b
?ht/FL Approved By:
E. C. McCabe, Jr., Chief, Reactor Projects date signed Section 2B Inspection Sumary:
l Inspection on 6/15-7/13/82 (Combined Report Nos. 50-317/82-16 and 50-318/82-14).
I Areas Inspected:
Routine, onsite regular and backshift inspection by the resident inspector ( 91 hours0.00105 days <br />0.0253 hours <br />1.50463e-4 weeks <br />3.46255e-5 months <br />). Areas inspected included the control room and the accessible portions of the auxiliary, turbine, service, and intake buildings; radiation protec-l tion; physical security; fire protection; plant operating records; maintenance; surveillance; plant operations; radioactive waste releases; open items; IE Bulletins; I
TMI Action Plan Items; and reports to the NRC.
l Violations: One:
Inoperability of the Auxiliary Feedwater System in Mode 3 (detail l
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DETAILS
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1.
Persons Contacted
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The following technical and supervisory level personnel were contacted:
J. T. Carroll, General Supervisor, Operations J. A. Crunkleton, Supervisor, Electrical Maintenance
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C. L. Dunkerly, Shift Supervisor W. S. Gibson, General Supervisor, Electrical & Controls J. E. Gilbert, Shift Supervisor S. Hager, Site Representative, Combustion Engineering J. R. Hill, Shift Supervisor W. J. Lippold, Supervisor Nuclear Fuel Management J. F. Lohr, Shift Supervisor
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G. S. Pavis, Engineer, Operations J. E. Rivera, Shift Supervisor P. G. Rizzo, Engineering Analyst L. B. Russell, Plant Superintendent
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R. P. Sheranko, General Foreman, Production Maintenance R. L. Wenderlich, Engineer, Operations J. M. Yoe, Instructor, Training
D. Zyriek, Shift Supervisor
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Other licensee employees were also contacted.
2.
Licensee Action on Previous Inspection Findings (Closed) Unresolved Item (317/81-14-01) Metrascope Control Element Assembly (CEA) Position Indication.
During a review of startup physics testing the
NRC had raised a question concerning why CEA position was occasionally recorded in odd numbers when the input reed switches were physically located at even two
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inch increments. The inspector reviewed the system characteristics with licensee employees and determined a problem did not exist.
Although the input to the metrascope is digital at even two inch steps the signal is changed in a voltage divider network (depending on the number of reed switches)
to a 0 to 5 volt signal.
Due to varying line losses (300 feet of cable into and out of containment), variance in the resistors and contact resistance, exact voltage steps are not obtained for all 70 steps and some variance is observed. The voltage divider for each CEA in turn feeds an analog amplifier for further signal conditioning prior to being displayed on the cathode ray tube and compared to other CEAs in a summing circuit (for deviation).
The inspector also observed bench testing of the Unit 1 metrascope which had
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been removed for repairs and noted that even with identical voltage inputs CEA deviations of 0.5 inches were obtained at '132 inches. Technical Speci-fication 3.1.3.3 requires that the CEA reed switch position indicator be 2.25 inches of absolute position, confirming that no accurate to only +h odd heights of CEAs in inches.
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-2-(Closed) Unresolved Item (318/80-22-03) Guidelines for Plant Shutdowns Required by Technical Specification.
General Supervisor-0perations Standing Instruction 82-04 was issued and reviewed by the inspector.
This instruction requires that the operator immediately commence a shutdown at a perceptable rate in those cases where the problem lends itself to correction, but increase the rate as necessary to effect a mode change in a controlled manner within the prescribed time.
For problems which do not lend themselves to correction within required time, the operator is directed to commence a power reduction so as to effect the mode change in a controlled manner as soon as possible.
(Closed) Unresolved Item (317/78-24-02) Evaluation of Planned Upgrading of Emergency Air Monitoring Equipment.
The Emergency Preparedness Appraisal (317/
81-19,318/81-18) and Health Physics Appraisal (317/80-09, 318/80-07) took an in-depth look at this issue.
Examination by appraisal team members revealed considerable improvements have been made in the Emergency Air Monitoring Equip-ment. This item is no longer applicable.
(Closed) Unresolved Item (317/82-12-03) Procedural Change Needed for 0I-41A Concerning Startup of Hydrogen Recombiners.
The inspector reviewed Change Report #82-96 dated May 20, 1982.
This action documented a change to 01-41A, Step II.B.3 requiring the operator to obtain a reference power from the data sheet attached to STP-0-58 instead of STP-0-32 which no longer existed.
(Closed) Unresolved Item (317/81-16-01, 318/81-15-01) Upgrade Training of Fire Brigade Members - Rewrite Training Procedure CCI-133B.
The inspector verified that all personnel presently on fire brigade have received training, fire brigade leader training was accomplished in March and April, 1982, and CCI-133C, issued February 1,1982 has been revised to include NRC guidance.
(Closed) Unresolved Item (317/81-16-04) Perform Surveillance Test for T.S.
Item 4.7.11.1.le4.
STP-M-696-0 was revised on October 1,1981 to include Technical Specification requirements for sequential starting of fire pumps.
Pump start test was also conducted in October, 1981.
3.
Plant Maintenance The inspector observed and reviewed maintenance and problem investigation activities to verify compliance with regulations, administrative and maintenance procedures, and codes and standards, proper QA/QC involvement, safety tags use, equipment alignment, jumpers use, personnel qualifications, radiological controls for worker protection, fire protection, retest requirements, and reportability per Technical Specifications.
The following activities were included.
-- PMS2-24-M-SA-3(MRM-82-2404), Remove and Test all Injectors (DG 21),
observed on 6/30/82.
PM 2-36-M-M-Z, Oil Change for Auxiliary Feedwater Pump 22, observed on
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7/9/82.
No unacceptable conditions were identified.
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Review of Plant Operations, A.
Daily Inspection The inspector toured the facility to verify proper manning and access control, and observed adherence to approved procedures and LCOs.
Instrumentation and recorder traces were observed. Status of control room annunciators was reviewed. Nuclear instrument panels and other reactor protective systems were examined.
Control rod insertion limits were verified.
Containment temperature and pressure indications were checked against Technical Specifications.
Stack monitor recorder traces were reviewed for indications of releases.
Panel indications for onsite/
offsite emergency power sources were examined for automatic operability.
Control room, shift supervisor, tagout log books, and operating orders were reviewed for operating trends and activities.
During egress from the protected area, the inspector verified operability of radiological monitoring equipment and that radioactivity monitoring was done before release of equipment and materials to unrestricted use. These checks were performed on the following dates.
June 17,18, 21, 22, 23, 28, 29, July 2, 6, 8, and 9,1982.
About 11:30 a.m. on 6/28 the inspector noted that both Unit 1
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Auxiliary Feedwater Actuation System (AFAS) handswitches were in pull to lock, thus disabling automatic pump starting. The unit was in Mode 3 (entered at 9:05 a.m. returning from refueling outage)
at 150 psig Steam Generator Pressure and 385 F Reactor Coolant System Temperature.
Discussions with the Senior Control Room Operator and the Shift Supervisor and review of the Technical Specifications revealed that the actuation system was required operable in Mode 3 and the handswitches were immediately restored to normal from pull to lock. With no power history on the new core a very low decay head load existed. The AFAS at Calvert Cliffs actuates on a low steam generator level (-39.6 to -49.5 inches), however, a 3 to 5 minute time delay is incorporated in the design. Automatic initiation of flow was not required until 30 days following entry into Mode 1 following completion of the reload for cycle 6 (Amendment 67). The inspector concluded that the physical inoperability of the AFAS was not a major safety concern due to the rapid ability to restore the system down from pull to lock from the control room (compared with the automatic 3 to 5 minute time delay), because at least one operator action (versus two when discovered) had already been required to initiate flow, and because of the low decay heat load. The inoperability should have been prevented by administrative controls prior to changing modes. The licensee comitted to perform an independent (of OP-6) check of Technical Specification requirements to ensure a similar problem did not exist prior to entering Mode 2.
Such a check was perfonned on 6/30/82.
Additional licensee corrective actions will be reviewed pending receipt of the followup report.
(LER 82-29/lT was issued on 6/29/82 addressing this event.)
Inoperability of the AFWS in Mode 3 when required by Technical Specifications is a violation (317/82-16-01).
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On 6/29, excess flow through Unit 1 Pressurizer Spray Valve 100F
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was preventing the attainment of full primary system pressure with all heaters on-(later corrected). Spray Valves 100E and 100F feed into a common spray and have individual bypass valves. The inspec-tor noted that the differential temperature between the pressurizer and spray input from spray valve 100E exceeded 400F, but that the spray to pressurizer differential was below the 400F limit because of the flow through spray valve 100F.
Both spray valve had been worked on to reduce leakage, and their bypass valves were locked in the throttle position as specified. There was no procedural provision for assuring that the throttling was proper, and reduced leakage through spray valve 100E had resulted in its bypass flow being too low. The bypass valve was fully opened, and'the licen-see stated the intention to operate with both spray bypass valves fully open in the future.. Inclusion of corrective action in pro-cedural controls will be followed (317/82-16-02).
B.
Weekly System Alignment Inspection Operating confirmation was made of selected piping system trains. Acces-sible valve positions in the flow path were verified correct.
Proper power supply and breaker alignment was verified. Visual inspections of major components were performed. Operability of instruments essential to system perfonnance was verified. The following systems were checked:
Unit 1 Component Coolin Water (CCW) Instrumentation lineup per OI l
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incontainment(partial on 6/25.
Unit 2 High Pressure Safety Injection lineups in the ECCS Pump Room
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on 6/17.
Various locked valves and piping including Containment Spray, Con-
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tainment Pressure Sensing, Filter Units, Containment Purge in the Unit 1 Containment prior to restart on 6/30.
Unit 2 Auxiliary Feedwater System in the Auxiliary Feed Pump Room
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and at the Condensate Storage tanks on 7/9/82.
The inspector observed part of the CCW lineup checks by an operator prior to the Unit 1 restart. The instrumentation lineup checks were added to system lineups (OI 16, attachment 1) per a licensee commitment to the NRC (TMI TAP Item I.C.6, addressed in Inspection Report 317/81-11).
No unacceptable conditions were identified.
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Biweekly Inspection Verification of the following tagouts indicated the action was properly conducted.
19290 Isolation of Diesel Generator 21 for preventive and corrective
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maintenance on 6/21.
34934 Removal of Auxiliary Feedwater Pump from service for maintenance
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on 7/9/82.
Boric acid tank samples were compared to the Technical Specifications.
Tank levels were also confirmed.
No unacceptable conditions were identified.
D.
Other Checks During plant tours, the inspector observed shift turnovers, security practices at vital area barriers, completion and use of radiation work permits, protective clothing and respirators.
The use and operational status of personnel monitoring practices, and area radiation and air
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monitors were reviewed.
Equipment tagouts were sampled for conformance with TS LCOs.
Plant housekeeping and cleanliness was evaluated.
Other TS LCOs, including RCS Chemistry and' Activity, Secondary Chemistry and Activity, watertight doors, and remote instrumentation were checked.
No unacceptable conditions were identified.
5.
Radioactive Waste Releases Records and sample results of the following liquid and/or gaseous radioactive waste releases were reviewed to verify conformance with regulatory requirements prior to release.
Gaseous Release Pennit G-064-82, Vent Unit 2 Contai ent via ECCS Pump
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Room, released 6/21/82.
Group I release rate 402 m /sec., Group II release rate 0.523 m3/sec.
Liquid Waste Release Permit M-089-82, Miscellaneous Waste Monitor Tank,
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released on 6/22/82, total curies released 1.92 E-4 excluding tritium and noble gases.
Gaseous Waste Permit G-074-82, Vent of Unit 2 Contaigment via ECCS Pump
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Room, released 7/8/82.
Group I release rate 258-1 m*/sec.
Liquid Waste Release Pennit M-099-82, Miscellaneous Waste Monitor Tank,
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Released on 7/8/82, total curies released 1.07 E-3 excluding tritium and noble gases.
No unacceptable conditions were identified.
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-6-6.
Observation of Physical Security The inspector checked, during regular and off-shift hours, on whether selected aspects of security met regulatory requirements, physical security plans and approved procedures.
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A.
Security Staffing Observations and personnel interviews indicated that a full time
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member of the security organization with authority to direct physical security actions was present as required.
Manning of all three shifts on various days was observed to be
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as required.
B.
Physical Barriers Selected barriers in the protected area and the vital areas were observed.
Random monitoring of isolation zones was performed.
Observations of truck and car searches were made.
C.
Access Control Observations of the following were made:
Identification, authorization and badging;
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Access control searches;
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Escorting;
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Canmunications; and
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Compensatory measures when required.
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No unacceptable conditions were identified.
7.
Review of Licensee Event Reports (LERs)
l A.
LERs submitted to NRC:RI were reviewed to verify that the details were clearly reported, including accuracy of the description of cause and
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adequacy of corrective action.
The inspector determined whether further information was required from the licensee, whether generic implications were indicated, and whether the event warranted onsite followup. The following LERs were reviewed.
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-7-LER No.
Date of Event Date of Report Subject Unit 1 82-25/3L 05/17/82 06/16/82 DEFICIENT PIPE PENETRATION WELDS IN 11 REFUELING WATER TANK.
82-26/3L 05/17/82 06/16/82 LOSS OF SHUTDOWN COOLING FLOW DURING MODE 6 OPERATION.
82-28/3L 06/04/82 07/02/82 LOSS OF REDUNDANT SHUTDOWN COOLING LOOP AND B0 RATION FLOW PATH.
Unit 2 82-22/3L 05/09/82 06/08/82 CEA 43 REED SWITCH POSITION INDICATOR CHANNEL INOPERABLE.
82-24/3L 05/14/82 06/11/82 CHANNEL C PRESSURIZER PRESSURE FAILED LOW.
CHANNEL ZF PZR PRESSURE, 22 SUB-COOL MARGIN MONITOR REMOVED FROM SERVICE; RPS CHANNEL C Tu BYPASSED.
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82-26/3L 06/02/82 07/02/82 CEA 64 DROPPED INTO CORE.
82-28/3L 06/04/82 07/02/82 STEAM GENERATOR CHANNEL A LEVEL TRANSMITTER IN0PERABLE.
82-29/3L 06/04/82 07/02/82 CONTAINMENT PARTICULATE RADIATION MONITORING SYSTEM INOPERABLE.
B.
For the LERs selected for onsite review (denoted by asterisks above), the inspector verified that appropriate corrective action was taken or responsibility assigned and that continued operation of the facility was conducted in accord-ance with Technical Specifications and did not constitute an unreviewed safety question as defined in 10CFR50.59.
Report accuracy, compliance with current reporting requirements and applicability to other site systems and components were also reviewed.
82-25/1T (Unit 2) and 82-27/1T (Unit 2) Simultaneous Inoperability of
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Diesel Generators (DG). This event had been inspected (Report 317/82-12,318/82-10) prior to receipt of the written report by the NRC.
During review of the written reports the inspector stated that some inaccurate information was included in the report and that the corrective action was not sufficiently comprehensive and should be readdressed in an updated LER.
The licensee agreed to submit a revised LER within 30 days. The following were among the items identified by the inspector.
(1) The cause of the trips was stated to be loss of field / reverse power.
In fact the reverse power relay did not actuate in either case, however, the loss of field relay did (separate relays).
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l-8-(2) The actual setpoint of the loss of field (140) relay was left blank in the setpoint book.
Initial discussions with the licensee had indicated that this relay would actuate any time the DG was taken in the lead direction and that this caution would be placed in the OIs.
The inspector determined by review of the relay setting sheets that the DG must be at least 13* 1ead plus a measure of field characteristics called
" distance" f6r the relay to actuate.
(3) The physical significance of the loss of field relay should be provided to and understood by the operators to avoid this trip and prevent possible damage.
(4) The licensee should re-examine the instrumentation for the DGs, or the methods for running the machines in parallel with another power source.
Remote (control rdom) instrumentation does not include either power factor nor leading reactive load indication which is available locally.
The inspector noted that these indications would not be necessary during design conditions
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(parameters determined exclusively by lagging reactive load of components) which would be the DGs running by themselves. The licensee, however, now routinely runs the DGs for long periods of time paralled with other generators (to burn off lube oil carried into exhaust header) and should consider proper instru-mentation in the control room or local monitoring of the generator. These LERs remain open.
8.
Review of Events Requiring One Hour Notification to the NRC The circumstances surrounding the following events requiring prompt NRC (one hour) notification via the dedicated telephone (ENS-line) were reviewed.
An inadvertent actuation of Safety Injection, Containment Isolation and
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Spray Systems occurred at 10:26 a.m. on 6/24. The plant was in cold shut-down and injection and spray did not occur due to equipment configurations.
The actuations occurred when two independent maintenance actions caused containment pressure actuation signals. MRI-82-65, containment pressure transmitters, had been approved for work on 6/16.
This maintenance
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electrically disconnected the containment pressure transmitter prior to the containment integrated leak rate test and reconnected and calibration checked transmitters following the test. The technicians had checked with the control room operators prior to performing work on 6/24.
The Shift Supervisor, Senior Control Room Operator, and Control Room Operators were all aware of the maintenance activity calibrating the containment pressure channels.
MRI-82-183 was approved on 6/24 to replace a logic module for a channel of the Recirculation Actuation System. This maintenance activity de-energized sensor cabinet ZB resulting in a second actuation signal to be
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The operators stated that they were aware, in hindsight, that the simultaneous perfomance of these activities would result in an actuation of the engineer safeguard features.
The instrument technician involved in the recirculation actuation maintenance was similarily aware. The inspector concluded that this event was an isolated example of personnel error and/or oversight.
The event was reported to the NRC Operations Center at 10:43 a.m.
No violations were identified.
Pressurizer level oscillations greater than the + 5% allowed by Technical
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Specifications occurred during Unit 1 Startup Physics Testing, specifically during the measurement of Isothemal Temperature Coefficient between 6:55 p.m. and 9:05 p.m. on July 2, 1982.
The level oscillations are nomal. A Technical Specification change is being pursued by the licensee and followed by the NRC.
9.
Surveillance Testi13, The inspector observed parts of tests to verify perfomance in accordance with approved procedures, LCOs were satisfied, test results (if completed) were satisfactory, removal and restoration of equipment were properly accomplished, and that deficiencies were properly reviewed and resolved.
The following tests were reviewed.
STP M-11-1, MR-82-3474 observed surveillance test of a Unit 1 Main Steam
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Line hydraulic snubber on 6/18.
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PMS 1-24-E-R-2, Emergency Diesel Generator 12 Relay preventive maintenance
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and ietpoint checks per Procedure FT-E-54, observed on 6/23.
STP 0-4-1 Integrated Engineered Safety Features Test, observed on 6/25.
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Portion of PSTP-3, Revision 3 dated 6/25/82, Unit 1 - Cycle 6 Escalation
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to Power Test, observed on 7/8/82.
On 6/18 the licensee was checking the operability of eight Unit 1 Main Steam.Line hydraulic snubbers under survie11ance test procedure STP M-11-1.
The inspector watched the test of one snubber.
The ' snubber failed because it did not meet-the required perfomance specifications for lock up velocity and bleed rate. The licensee is presently upgrading and reclassifying these snubbers to the " safety related" category.
The inspector observed portions of the conduct of the Unit 1 Containment Integrated Leak Rate Test completed on 6/21.
This testing was observed by a NRC:RI inspector and resident inspector observations were incorporated in the specialist inspector's report (317/82-15).
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-10-10. Unit 1 Startup Testing The inspector reviewed and observed portions of the startup test program for Unit 1 from the refueling outage for cycle 6.
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Shift Engineer Log for the Unit 1 startup program was reviewed.
PSTP-2, Unit 1 Cycle 6 Initial Approach to Criticality and Low Power Physics testing, Revision 3 approved 6/25/82 was partially reviewed.
The inspector observed portions of Dual CEA Symmetry checks, Essentially All Rods Out Baron Concen-tration, and Isothermal Temperature Coefficient Measurements.
Portions of PSTP-3, Revision 3 dated 6/25/82, Unit 1 Cycle 6 Escalation to Power test procedure was reviewed and test preparations for the power coefficient measurement test were observed. Additionally, a tour of the Unit 1 Containment was made after the final containment closecut inspection.
Various equipment and locked valves were checked, including Containment Spray, Purge, Safety Injection Tanks and cooling water to containment filter units.
The inspector reviewed completed copies of OP-6, Reactor Startup Locked Valve Checklists and STP-0-55, Containment Isolation Valve Checklists.
No unacceptable conditions were identified.
11.
Licensee Action on NUREG 0660, NRC Action Plan Developed as a Result of the TMI-2 Accident The NRC:RI Office has inspection responsibility for selected action plan items.
These items have been broken down into numbered descriptions (enclosure 1 to NUREG 0737, Clarification of TMI Action Plan Items).
Licensee letters contain-ing commitments to the NRC were used as the basis for acceptability, along with NRC clarification letters and inspector judgment.
The following item was reviewed:
I.A.I.3 Shift Manning, (1) Limit Overtime.
This item had been previously
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inspected (317/81-07; 318/81-07) and left open pending revision by the licensee of Calvert Cliffs Instruction 140C, Shift Staffing.
The inspector reviewed the latest procedure revision (change 2, approved 4/19/82) and
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verified that the requirements had been changed to limit overtime to no more than 72 hcurs in any seven day period (other limits are included).
This item is closed.
12.
Licensed Operator Training Instructor The inspector reviewed records of training instructors contracted by the licensee from Combustion Engineering for training licensed operators. Through discussions with the licensee and contractor the inspector determined that the instructors had previously held senior licenses at operating Pressurized Water Reactors (PWR).
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certified by the NRC (none have to date) or have been licensed (senior) operators I
at an operating PWR. The inspector also verified that Combustion Engineering routinely sends new instructors to Calvert Cliffs for the purpose of in-plant familiarization, including walk downs of piping systems and buildings.
The licensee does not administer the training programs which vary in duration between two to four or more weeks.
No unacceptable conditions were identified.
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-11-13.
IE Bulletin Followup The inspector reviewed licensee actions on the following bulletin to detemine that the written response was submitted within the required time period, that the response included the infomation required including adequate corrective action comitments, and that licensee management had forwarded copies of the response to responsible onsite management. The review included discussions with licensee personnel and observations and review of items discussed below.
IE Bulletin 79-25, Failure of Westinghouse BFD Relays in Safety Related
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Systems.
This bulletin had previously been inspected during NRC Inspections 317/80-11, 318/80-10 and 317/81-04, 318/81-04. The inspector reviewed the relay preventive maintenance program and noted that it was in conformance with the bulletin.
The bulletin response, however, was detemined to be inaccurate in that normally de-energized relays (recom-mended to be replaced) were not addressed.
The licensee submitted a supplemental response on 3/18/81 describing the preventive maintenance program and an additional response dated 6/16/82 addressing their planned course of action for the normally de-energized relays (all BFD relays removed from stock, existing BFD relays to be replaced by NFBD relays upon failure). The licensee comitted to replace all NFBD relay coils with replacement coils recommended by IE Infomation Notice 82-02, including both in-plant and stock relays.
IE Bulletin 79-25 is closed.
14.
Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted pursuant to Technical Specification 6.9.1 and 6.9.2 were reviewed.
That review included the fol-lowing:
Inclusion of infcmation required by the NRC, test results and/or supporting information consistency with design predictions and perfomance specifications, planned corrective action adequacy for resolution of problems, detemination whether any information should be classified as an abnormal occurrence, and validity of reported infomation.
The following periodic report was reviewed:
May,1982 Operations Status Reports for Calvert Cliffs No.1 Unit 'and
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Calvert Cliffs No. 2 Unit, dated June 14, 1982.
15.
Exit Interview Meetings were held with senior facility management periodically during the course of this inspection to discuss the inspection scope and findings. A summary of findings was also provided to the licensee at the conclusion of the report period.
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