IR 05000382/1990022
| ML20058B320 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 10/23/1990 |
| From: | Westerman T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20058B313 | List: |
| References | |
| 50-382-90-22, NUDOCS 9010300101 | |
| Download: ML20058B320 (13) | |
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APPENDIX B U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
NRC Inspection Report:
50-382/90-22 Operating License:
NPF-38 Docket:
50-382 Licensee:
Entergy Operations, Inc.
(E01)
P.O. Box B K111ona, Louisiana 70066 Facility Name: Waterford Steam Electric Station, Unit 3 (Waterford 3)
Inspection At: Taft, Louisiana Inspection Conducted:
September 5 through October 1, 1990 Inspectors:
W. F. Smith, Senior Resident Inspector Project Section A, Division of Reactor Projects S. D. Butler, Resident Inspector Pro et Section A, Division of Reactor Projects
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NTO Approved:
T. FW# Raeman, Chief, ProjectA ection A Date Hision of Reactor Projects Inspection Summary Inspection Conducted September 5 through October 1.1990 (Report 50-382/90-22)
Areas Inspected; Routine, unannounced inspection of onsite followup of events, monthly maintenance observation, monthly surveillance observation, operational
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safety verification, followup of previously identified items, licensee event report followup, and engineered safety feature (ESF) system walkdown.
Results:
During this inspection period, the following violations were identified:
The licensee failed to provide complete and accurate information to the NRC, resulting in the NRC granting relief from the testing requirements of ASME Code Section XI (paragraph 4 b), and The licensee installed a scaffold over an emergency diesel generator (EDG)
prior to completing an engineering evaluation to verify that the failure of the scaffold would not affect the operability.of the EDG (paragraph 6).
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Weaknesses were identified, as discussed below:
The corcern with the licensee's control of postwork testing was noted during ',he observation of maintenance on the atmospheric dump valves
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(paragrash4.b).
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The nomer.:lature used in the breaker alignment procedure for the shield
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building ventilation system did not match the description provided on the
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nameplate installed on the breaker (paragraph 9).
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The action taken by the licensee with respect to the Part 21 report
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issued by the Anchor / Darling Valve Company appeared to be nonconservative in determining the status of seal material installed in the feedwater isolation valves (paragraph 7.b).
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The following strengths were observed during this inspection period:
The operators response to the plant perturbation caused by the loss of a feedwater heater was timely and adequate,
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It appeared that the licensee was implementing an adequate surveillance test program.
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1.
Persons Con' acted principal licensee Employees
- J. R. McGana, General Manager, Plant Operations
- P. V. Prasankumar, Technical Services Manager D. F. Packer, Operations and Maintenance Manager A. S. Lockhart, Quality Assurance Manager
- D. E. Baker, Director, Operations Support and Assessments
- R. G. Azzarello, Director, Engineering and Construction W. T. Labonte, Radiation Protection Superintendent
- G. M. Davis, Events Analysis Reporting and Response Manager
- R. F. Burski, Director, Nuclear Safety
- L. W. Laughlin, Licensing Manager J. G. Hoffpauir, Maintenance Superintendent
- R. S. Starkey, Operations Superintendent A. G. Larsen, Assistant Maintenance Superintendent, Electrical D. T. Dormady, Assistant Maintenance Superintendent, Mechanical D. C. Matheny, Assistant Maintenance Superintendent, Instrumentation and Controls
- Present at exit interview.
In addition to the above personnel, the inspectors held discussions with various operations, engineering, technical support, maintenance, and administrative members of the licensee's staff.
2.
Plant Status On September 5, 1990, the plant was restored to full power operation from 18 percent power. As described in the previous inspection report (NRC s
Inspection Report 50-382/90-19), the licensee had recovered from a turbine trip followed by a reactor cutback.
From September 5-24, 1990, the plant was operated at full power. On September 24, 1990, power was reduced to 75 percent for approximately I day to accommodate reduced grid demand. As pressurizer relief valve leakage increased, requiring more frequent venting and draining of the quench tank, the licensee decreased reactor coolant system pressure from 2150 to 2100 psia on September 25, 1990, to reduce leakage.
Plant power was returned to 99 percent to maintain the desired departure from nucleate boiling ratio margin of 0.3 above the minimum of 1.26 required by the Technical Specifications (TS).
As of the end of this inspection period, the plant was operating at 99 percent
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power. The licensee has indicated plans to shut down at 12 midnight on October 5, 1990, to replace the leaking pressurizer relief valve.
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Onsite Followup of Events (93702)
a.
Loss of Feedwater Heater Transient On September 19, 1990, the licensee experienced a feedwater system transient while operating at 100 percent power. The transient occurred while implementing a clearance for calibration of the level controller for the alternate level control valve for Feedwater Heater IC. While hanging the tags, the auxiliary operator inadvertently closed the wrong valve (later determined to be caused by an incorrect label on the valve) which caused the level switch for hi-hi level in the heater to actuate.
This signal caused automatic isolation of extraction steam to all three (IA, 18, and IC) feedwater
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heaters by closing Valve ES-109.
The sudden drop in feedwater temperature caused cooling of the reactor coolant system which i
resulted in an increase in reactor power.
In addition, the increased steam flow through the turbine caused turbine load to increase.
The inspector observed the operating crew's response to the transient.
The operator quickly reduced turbine load which, in turn, reduced
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reactor power.
Reactor power remained slightly above 102 percent for several minutes during the early part of the transient and was above 100 percent for approximately 30 minutes.
It was later determined that reactor power averaged over the 8-hour shift did not exceed the license limit of 100 percent.
Efforts to restore extraction steam to the three feedwater heaters by reopening Valve ES-109 was hampered because the valve would not open using the handswitch in the control room.
Operators were first dispatched to the valve itself but, when it was determined that the differential pressure across the valve made it too difficult to be opened by hand, they proceeded to the electrical controller for the valve.
By manually overriding the contactor for the valve motor operator, Valve ES-109 was reopened to restore extraction steam to the feedwater heaters. Once the feedwater system was restored to normal, reactor power decreased to below 100 percent and, subsequently, both turbine load and reactor power were restored to their normal full power values.
Subsequent review by the licensee determined that a discrepancy existed between plant drawings and the installed labels on the valves
'being used to isolate the level controller.
The clearance had been correctly prepared using the drawings, but the discrepancy caused the operator to shut a valve which isolated both the level controller and the level switch that closed Valve ES-109, instead of just the level controller.
Immediate corrective action by the licensee consisted of voiding the clearance, removing the tags which had been hung, and I
returning the valves to normal.
The licensee initiated a 100 percent inspection to verify that valves associated with level control and indication on all the feedwater heaters were correctly labeled.
Additional discrepancies were found and correcte i
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s 5-Equipment problems that appeared during the recovery from the transient included the inability to operate Valve ES-109 from the control room and the automatic tripping of the B heater drain pump.
The problem with Valve ES-109 was identified during a startup on September 5,1990, and a condition identification report (CI 271025)
was generated with an appropriate priority, but no work had been done because of plant conditions. The loss of the B heater drain pump due to low suction pressure did not cause a delay in the recovery from the transient but, again, an operator had to be dispatched to manually actuate a limit switch on the discharge valve in order to
restart the pump. The inspector was informed that a CI was generated to adjust the limit switch.
During the recovery from the transient, the inspector noted that an off-normal procedure was not available for use by the operators.
The inspector also reviewed the annunciator response procedure for the initial alarm, hi-hi level in Feedwater Heater IC, and found that it did not address the effect of the loss of extraction steam on the primary plant.
This was discussed with the licensee who committed to evaluate whether there should be a more prescriptive response to this alarm.
The inspector concluded that the operator's response to the transient was timely and adequate considering equipment malfunctions and the lack of detailed procedural guidance.
The inspector made an observation to the licensee that a greater reduction in turbine load during the initial operator response could have better expedited the return of reactor power below the license limit.
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A significant occurrence report (SOR 90-023) was initiated by the licensee which required further investigation of the event, including a root cause analysis and long-term corrective action to be taken.
The inspectors will monitor the corrective actions taken by the
licensee as a result of lessons learned.
This shall be tracked as an inspectorfollowupitem(382/9022-01).
b.
Inadvertent ESF Actuation On September 22, 1990, at 1:55 a.m., and on September 29, 1990, at 1:11 a.m., the licensee experienced inadvertent control room isolations and actuation of the control room emergency filtration units.
The plant was operating at full power.
The ESF actuation on September 22 was caused by an electrical spike in control room outside air intake (CROAI) Radiation Monitor ARM-IRE-0200.15.
The ESF actuation on September 29 was caused by a power failure on Monitor ARM-IRE-0200.25. Each time, the operators implemented off-normal Procedure OP-901-017, Revision 4, "High Airborne Activity in Control Room," until HP technicians sampled and determined that no l
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Prompt NRC
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notification of the ESF actuation was made in accordance with 10 CFR Part 50.72, and the resident inspector was notifie,
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-6-The licensee has recently experienced several inadvertent actuations of the control room emergency filtration units and was in the process of implementing a design change on the detector light filters to reduce spurious actuations of the CROAI radiation monitors. However, both ARM-IRE-0200.15 and -0200.25 were monitors that had already been modified.
The licensee had not determined the cause of the latest failures. This problem was discussed in more detail in NRC Inspection Report 50-382/90-19. Corrective actions will be reviewed by the inspectors upon closure of the applicable licensee event reports.
4.
Monthly Maintenance Observation (62703}
The station maintenance activities affecting safety-related systems and components listed below were observed and documentation reviewed to ascertain that the activities were conducted in accordance with approved work authorizations (WA), procedures, TS, and appropriate industry codes and standards, a.
WA 01057462. On September 20, 1990, the inspector observed preventive maintenance on Train 8 of the shield building ventilation system (SBVS).
The overcurrent alarm relay for the B SBVS fan motor was cleaned and inspected, and the setpoint was checked in accordance with Procedure ME-007-036, Revision 4, "G.E. Auxiliary Relays, HFA51A and HFA518." The inspector verified that the work was authorized by the shift supervisor and was being performed in accordance with a properly approved work package. The workers performing the work were knowledgeable and were using the appropriate calibrated test equipment. The lifting of leads was documented and verified in accordance with the procedure, b.
WA 01061778. On September 26, 1990, the inspector observed replacement of the air operator bypass tubing and valve on the atmospheric dump valve (MS-116A) for the No I steam generator.
While attempting to replace a leaking bypass valve on MS-116B the licensee discovered that the particular valve specified in the vendor's technical manual did not match what was previously installed. A nonconformance report was initiated and, as a result, the bypass valve had to be replaced on both of the atmospheric dump valve air operators.
The following problems were identified during this work:
(1) When the WA was presented to the shift supervisor for approval to implement, the shift supervisor rejected the WA because the postmaintenance testing instructions were inappropriate.
The WA specified Surveillance Procedure OP-903-033. " Cold shutdown IST Valve Tests." Implementation of this test would have caused a significant steam transient, if followed while the plant was at full power, because the procedure was written to stroke the valve when the steam generators are in cold shutdown.
The inspector expressed concern to the licensee that this was another example
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where inappropriate testing was specified in a WA, apparently due to programmatic weaknesses in the licensee's testing program. A Notice of Violation was issued on August 1, 1990 (NRC Inspection Report 50-382/90-15), citing similar circumstances in the postmodification testing of some control room ventilation damper circuits.
The licensee's response of August 31,1990(W3P90-1191), addressed corrective actions for the postmodification testing, with additional actions to review
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and correct weaknesses in the postmaintenance area.
This was discussed with the licensee on September 28, 1990, and the licensee committed to ensure that corrective actions would F
address all testing area weaknesses, taking into account the problems identified in this report.
The inspectors will review corrective actions taken by the licensee during the followup inspection on Violations 382/9015-02 and -03.
(2) The safety-related automatic steam dump, MS-116A was out of service for a longer period than necessary, considering the minor scope of the task to be performed.
The valve was out of service for over 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
Three preventable delays occurred.
At least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> were lost to revise the retest requirements.
Quality assurance coverage was delayed by a mandatory luncheon meeting.
Incorrect size replacement fittings were specified and, thus, were supplied.
Time was lost recovering from that problem. These delays were discussed with the licensee.
(3) The inspector noted that MS-116A and MS-116B had an upstream isolation valve, yet the licensee's ASME Code Section XI,
" Inservice Test Program," Revision 5, had an NRC-approved relief request (3.1.27) allowing relief from the code requirement to exercise the valves once every 3 months. The basis of the relief request was that cycling the valves would induce unwanted secondary and primary transients, and that failure of the valves in a nonconservative (open) position would force a plant shutdown. This was not an accurate basis.
Each steam dump has an upstream isolation valve (MS-115A and MS-115B) that could be shut before testing the atmospheric steam dumps, which was the way the valves were tested with the plant at full power, subsequent to the above described maintenance.
Failure to accurately represent the conditions forming the basis for relief from NRC regulations, i.e., compliance with ASME Code Section XI as implemented by TS 4.0.5, is a violation of 10 CFR 50.9.(a).
(382/9022-02).
5.
' Monthly Surveillance Observation (61726)
The inspectors observed the surveillance testing of safety-related systems and components listed below to verify that the activities were being performed in accordance with the TS requirements.
The applicable procedures were reviewed for adequacy, test instrumentation was verified to be in calibration, and test data was reviewed for accuracy and
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-8-completeness. The inspectors ascertained that any deficiencies identified were properly reviewed and resolved.
a.
Procedure MI-03-126, Revision 6, " Core Protectic Calculator Functional Test." On September 12, 1990, the inspector observed the performance of Procedure MI-03-126 for Channel A of the core protection calculator.
The monthly functional test was performed to satisfy, in part, TS Surveillance Requirement 4.3.1.1.
The inspector determined that the surveillance was properly authorized by the shift supervisor and was performed in accordance with an approved procedure.
Test personnel were knowledgeable of the work performed and test equipment was properly calibrated.
b.
Procedure OP-903-046, Revision 8, " Emergency Feedwater Pump (EFW)
Operability Check." On September 17, 1990, the inspector observed the performance of Procedure OP-903-046 for the B EFW pump following preventive maintenance on the pump.
The surveillance test was being performed as a retest following maintenance prior to declaring the pump operable and returning it to service, In conjunction with Procedure OP-903-046, the operator performed Procedure OP-904-012, Revision 2, " Emergency Feedwater Pump Environmental Qualification Maintenance Input," to collect the necessary data for the pump motor.
The inspector verified that performance of the tests was authorized by the shift supervisor and was being conducted in accordance with approved procedures.
6.
Oyerational Safety Verification (71707)
The objectives of this inspection were to ensure that the facility was being operated safely and in conformance with regulatory requirements, to ensure that the licensee's management controls were effectively discharging the licensee's responsibilities for continued safe operation, to ensure that selected activities of the licensee's radiological protection programs were implemented in conformance with plant policie:
and procedures and in compliance with regulatory requirements, and to inspect the licensee's compliance with the approved physical security plan, i
. The inspectors conducted control room observations, plant inspection l
tours, and reviewed logs and licensee documentation of equipment problems.
l Through in plant observations and attendance of the licensee's plan-of-the-day meetings, the inspectors maintained cognizance over plant j
status and TS action statements in effect.
On September 23, 1990, while the inspector was conducting a routine tour
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of the Train A EDG, an audible air leak was found on the air relay supplying control air to the fuel control cylinder, an integral part of the fuel control linkage.
Upon identifying the leak to the shift supervisor, the inspector questioned the impact this leak might have on the operability of the EDG.
The licensee evaluated the condition, with support from the system engineer, and concluded that a total failure of
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the seal at this particular point in the system would not prevent the EDG from performing its inteaded safety function.
The fuel control cylinder is one of two methods available to shut down the EDG if an overspeed or
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voltage differential condition should occur while operating in the
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emergency mode. The only impact on EDG operability was the increased frequency of air compressor cycling. The cycle had increased from about
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twir,e an hour to about eight times an hour. - This could increase wear and tear on the compressor, which is not safety related.
The licensee chose not to take the EDG out of service at this time because an outage was already planned to occur within 3 weeks, at which time the repair could be made, thus minimizing total outage time for the EDG.
The inspectors had no problem with this approach.
On September 24, 1990, while on a routine inspection tour, the inspector found a scaffold erected just above the Train A EDG which rigidly connected the EDG access platform and handrails (which were attached to the EDG cylinder block) to adjacent building structure which, in turn, was supporting adjacent cable trays.
The inspector questioned the licensee.as to whether this installation had been evaluated and approved by engineering prior to erection as required by Nuclear Operations Construction Procedure NOCP-207,-Revision 3, " Erecting Scaffold." The-response was that it had not but was pending a posterection engineering evaluation. As of September 24, 1990, the evaluation had not been done.
The work was expedited and the scaffold was removed on September 25, 1990.
The licensee's representative explained that the people responsible for erecting scaffolds did not take into consioeration that attaching scaffolds to the EDG access platform was the same as' attaching to the EDG because most other handrails and platforms were free-standing structures.
The inspectors.have expressed concerns in the past (NRC Inspection Reports.50-382/89-08 and -23) over the lack of controis-over scaffolds around safety-related equipment because of the possible impact on equipment operability, particularly from a seismic qualification
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standpoint in that the potential exists for EDG operability to be
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affected during an earthquake. While improvement has been noted over the-past year, controls over scaffold erection still appeared to have
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weaknesses.
Failure to'obtain the required engineering evaluation prior to erection of the above described scaffolding in accordance with Procedure NOCP-207 is a violation:(382/9022-03).
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Followup of Previously~ Identified Items (92701)
a.
(Closed) Unresolved Item 382/8926-02i Evaluation of three potential deficiencies identified during ESF walkdown of Trains A and B of the high pressure safety injection (HPSI) system.
The first. item was a bolt missing from the motor casing on motor-operated Valve-SI-121A.-- The licensee determined that, since
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.the bolt did.not see operator thrust and the seal was not leaking, the bolt had no impact on valve or system operability.
The bolt was promptly replaced.
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The second item involved an inappropriate tag found on an HPSI pump suction line support designating it as nonsafety related.
The license 9's evaluation concluded that the support was safety related and was designed and constructed in accordance with the applicable requirements. The presence of the tag could not be explained, and it was removed.
The third issue was the installation of scaffolding which could interfere witt. the movement of a spring hanger installed on safety injection piping. This was promptly corrected by the licensee before an evaluation could be performed to determine the impact on HPSI operability. Whether or not the scaffold would have rendered the HPSI system inoperable has become moot, and the issue of inadequate controls over scaffolds in the proximity of safety-related components has been addressed in paragraph 6 of this inspection report. This item is closed, b.
(0 pen) 10 CFR Part 21 Followup Item 90-008: On January 26, 1990, the Anchor / Darling Valve Company submitted a Part 21 report to the NRC identifying a problem with backup rings furnished in spare parts seal kits and with the same rings supplied with feedwater isolation valve (FWIV) actuators.
The rings should have been Viton, but Waterford 3, among other plants, had equipment that may have been supplied with the wrong material (Buna N), which could impact the operability of the FWIVs. The FWIVs are containment isolation valves
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required-to shut in less than 5 seconds.
The licensee' responded to the 10 CFR Part 21 report by:
(1) sending the 4-way valves currently in stock in the warehouse back to Anchor / Darling to have the material identified as being correct or
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replaced if incorrect, (2) discarding questionable or incorrect rebuild kits, and (3) reordering rebuild kits 1from Anchor / Darling which are-at the correct quality -level.
The licensee contacted Anchor / Darling on February 22, 1990, and questioned how long it would take before exposure of incorrect seal rings to hydraulic fluid would cause operational problems. The'
response, " based on engineering judgment," was 6 months to 1 year.
Since maintenance history indicated that the'four-way valves were
- replaced on FWIV A in January 1987 ~and on FWIV B in April '1988, the
' licensee concluded that if incorrect seal' material had been used, problems would have occurred by 1990.
FWIV surveillance results, including valve stroke timing trends, did not indicate any problems, so the licensee further concluded that there is no reason to question the operability of the FWIVs, and no action was to be taken.on the installed four-way valves.
E The inspector did not consider the above assumptions to be sufficient technical basis for concluding that the FWIVs did not contain improper seal material. The licensee was requested to furnish a more
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8.
Licensee Event Report (LER) Followup (90712}
The following LER was reviewed and closed.
The inspectors verified that reporting requirements had been met, causes had been identified, corrective actions appeared appropriate, generic applicability had been considered, and that the LER forms were complete. The inspectors confirmed that unreviewed safety questions and violations of TS, license conditions, or other regulatory requirements had been adequately
described.
(Closed) LER 382/88-027, " Environmental Qualification of Electrical Splices not Adequately Documented During Construction."
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This was a voluntary report submitted by the licensee because of its potential interest to the NRC and other utilities. There was considerable discussion over this issue between the licensee and the NRC staff, including an enforcement conference on June 1,1989.
During a followup inspection. conducted by NRC Region IV staff on August 20-24, 1990, the issue was closed.
NRC Inspection Report 50-382/90-16 summarized and closed the enforcement actions and other inspection findings.
This LER is closed.-
9.
Engineered Safety' Feature (ESF) System Walkdown (71710)
The inspectors performed an indepth review and walkdown of accessible portions of the SBVS.
The SBVS mitigates some of the consequences of a postulated accident by filtering air leakage from the containment prior to releasing it through the plant stack. The licensee's operating and surveillance procedures and system drawings were reviewed and compared with.the as-built configuration of the system in the plant.
Equipment-j
- condition; valve, damper, and breaker positions; housekeeping; labeling;
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permanent instrument indication; and apparent operability of support '
R systems essential to operation of the SBVS were all reviewed, as appropriate.
Sections 6'.2.3.2.2 and 6.5.1 of the Final Safety Analysis Report were reviewed to determine the design requirements and description of the SBVS that were applicable.
The following plant procedures were reviewed:
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OP-008-008, Revision 5, " Shield Building Ventilation"
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OP-903-043, Revision 6, " Shield Building Ventilation System i
Operability Check"
OP-903-044, Revision 4, " Shield Building Integrity Verification"
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PE-005-003, Revision 3, " Shield Building Ventilation System Surveillance" OP-903-029, Revision 5, " Safety Injection Actuation Signal Test" (in
part)
The procedures were reviewod for adequacy and to determine if the surveillance requirements of TS 4.6.6.1 were properly incorporated in plant procedures.
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Using plant drawings and Attachments 11.1 and 11.2 of System Operating Procedure OP-008-008 as guides, the inspectors walked down the accessible portions of both trains of the SBVS.
The equipment appeared well maintained and no hardware deficiencies were identified.
Inconsistencies'
were found between the breaker lineup (Attachment 11.2) and the equipment labeling.
In view of the fact that this procedure was reviewed and revised on June 5, 1989, under the licensee's procedures upgrade program, the inspectors expressed concern that the procedure writer's guide, Procedure OP-100-013, Revision 3, " Writer's Guide for Operating Procedures," may not have been followed. The procedure review checklist (Attachment 6.1 to Procedure OP-100-013) had an attribute to check that equipment number and/or nomenclature used in the procedure is consistent with those displayed on.the equipment.
The inspectors identified the following inconsistencies as examples:
The equipment description in Attachment 11.2 read, "SBV FILTER TRAIN
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A HEALER SBV-0001A HTR."
The' equipment label on the breaker. read, "EHC-51(3A-SA)SBYS" (similar problem on Train B).
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The equipment descriptior in Attachment 11.2 read, "SBV EXHAUST FAN A SBV-0002A."
- The equipment. label on the breaker read, ".eHLD BLDG VENT FAN E-17
' I 3A-SA" (similar problem on Train B).
- The equipment description in Attachment *.1.2 read, "SBV EXH FAN A
' INLT ISOL SBV-110A."
The equipment. label-on the breaker read, "SBVS A OUTLET VLV.
SBV-110A" (similar problem on Train'B)..
The licensee responded to the concern by stating that the checklist was-being used on procedures that have been upgraded, but that the equipment
- nomenclature in procedures was being compared with station information management system computer data.rather than actual labels in' the field.
The inspectors questioned the wisdom of such a practice and requested licensee management to resolve the concern.
Followup on the effective l
utilization of the procedure writer's guide and correction of inconsistencies found on SBVS breaker identification shall be tracked as
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.an' inspector followup' item (382/9022-04).
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. 10,- Exit Interview
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The inspection scope and findings were-summarized on October 4,1990, with
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those persons indicated in paragraph I above._ The licensee acknowledged
the inspectors' findings..The licensee did not identify as proprietary,
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any of the material provided to, or reviewed by, the inspectors during
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-this inspection.
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