IR 05000237/1990009

Insp Repts 50-237/90-09 & 50-249/90-08 on 900221-0402.One Noncited Violation Noted Re Failure to Follow Outage Checklist.Major Areas Inspected:Maint/Surveillance,Lers & Previous Emergency Operating Procedure Insp Items

ML17202L206
Person / Time
Site:	Dresden
Issue date:	04/13/1990
From:	Hinds J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML17202L205	List: IR 05000237/1990009 ML17202L204
References
50-237-90-09, 50-237-90-9, 50-249-90-08, 50-249-90-8, NUDOCS 9004240207
Download: ML17202L206 (34)

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U. S. NUCLEAR REGULATORY COMMISSION REGION I I I Report Nos. 50-237/90009(DRP); 50-249/90008(0RP)

Docket Nos. 50-237; 50-249 License Nos. OPR-19; DPR-25 Licensee:

Commonwealth Edison Company P. 0. Box 767 Chicago, IL 60590 Facility Name:

Dresden Nuclear Power Station,. Units 2 and 3 I~spection At:

Dresden Site, Morris, IL Inspection Conducted:

February 21 through April 2, 1990 Inspectors:

S. G. Ou Pont 0. E. Hills B. L. Siegel Approved s~"tci*s*,cc'h~*

~a~to~* Projects Section 18 04-1'3 -9-o Date Inspection Summary Inspection during the period of February 21 through April 2, 1990 (Report Nos. 50-237/90009(DRP); 50-249/90008(DRP)).

Areas Inspected:

Routine unannounced resident and headquarters inspection of previously identified inspection items, licensee event reports (LER),

plant operations, maintenance and surveillances, safety assessment/quality verification, previous emergency operating procedure (EOP) inspection items and report revie Resul'ts:

0 The non-cited violation described below and various_other occurrences indicated that operator performance was mixed. - Other occurrences indicating negative performance included control rod mismanipulations described in paragraph 4.b and inadequate knowledge of the operation of a specific throttle valve described in paragraph 5, The positive side included the excellent response of a li~ensed operator described in paragraph 4.d which prevented an unplanned scram during a feedwater transient and the identification of a High Pressure Coolant Injection (HPCI) system waterhammer event described in par.agraph A non-cited violation was identified in accordance with 10 CFR 2 Appendix C.Section V.A in paragraph 4.a of this repor This involved a*failure to correctly*follow a~ outage checklist which resulted in inadvertent recirculation pump seal cavity pressurizatio No other violations or deviations were identifie *

0

A Unit 2 High Pressure Coolant Injection (HPCI) waterhammer event described in paragraph 4.c occurred on March 19, 1990, which was

. similar to. the event reviewed by a November 1-4, 1989 Augmented Inspection Team (AIT).

The licensee identifie-d a potential analyzed pipe stress condition

. as described in paragraph A follow-up inspection to the previous EOP inspection report 50-237/88012; 50-249/88014 closed all open items from that report except for four items as described in paragraph The inspectors concluded that major improvements had been made in the licensee's EOP program with the development and implementation of revised EOPs based on Revision 4 of the BWR Owners Group emergency procedure

• guidelines.

DETAILS Persons Contacted Commonwealth fdison Company

• E. Eenigenburg, Station Manager

• L. Gerner, Technical Superintendent

~. Mantei, Services Director

• J. Kotowski, Production Superintendent

• D. Van Pelt, Assistant Superintendent - Maintenance J. Achterberg, Assistant Superintendent - Work Planning

• G. Smith, Assi~tant Superintendent-Operations

• K. Peterman, Regulatory Assurance Supervisor W. Pietryga, Operating Engineer

M. Korchynsky, Operating Engineer B. Zank, Operating Engineer R. Stobert, Operating Engirieer J. Williams, Operating-Engineer M.* Strait, Technical Staff Supervisor L. Johnson, Quality Control Supervisor J. Mayer, Station Security Administrator D. Morey, Chemistry Services Supervisor D. Saccomando, Health Physics Services Supervisor

• K. Kociuba, Quality Assurance Superintendent S. Stiles, Training Supervisor T. Lewis, Regulatory Assurance Staff

• G. Bergan, Onsite Nuclear Safety

• R. Falbo, Regulatory Assurance.Assistant The inspectors also talked with and interviewed several other licensee employees, including members of the technical and engineering staffs, reactor and auxiliary operators, shift engineers and foremen, electrical, mechanical and instrument personnel, and contract security personne *Denotes those attending one or more exit interviews conducted informally at various times throughout the inspection perio ~ Previously Identified Inspection Items (92701 and 92702)

(Closed) Violation (237/89019,..02):

Removal of a primary containment isolation fuse was not accomplished in accordance with instructions in that an independent verification.did not tonstitute an adequate component identificatio The inspector.performed visual observation or reviewed appropriate documentation to verify the following:

Caution labels were added to the control room panels to indicate that there were two series of fuse labels with similar numbers that were not in sequential orde They further stipulated that all seven digits of the number were to be verified prior to removing a fuse from its holde The color scheme was also explaine.

Dresden Administrative Procedure -(OAP) 7-27, Independent Verification was revised o.n January 26, 1990, as revision 1 to require fuses that may initiate an Engineering Safety Feature (ESF) actuation to be independently verified and agreed upon prior* to remova This event was covered in the operator continuing training program which was completed on March 23, 199 This event was included in tailgate sessions held on December 12;'

198 This item is considered close (Closed) Open Item (237/g8012-04):

Verify resolutions to 28 technical deficiencies identified in paragraph 4.B of inspection report 50-237/88012; 50-249/8801 These items were reviewed and closed as described in parag~aph 8 of this repor (Closed) Open Item (237/88012-05):

Verify resolutions of walkdown deficiencies identified in paragraph 5 and in attachment B of inspection report 50-237/88012;50-249/8801 These items were reviewed and closed as described in paragraph 8 of this report..

No viO'lations or deviations*were identified in this are.

Licensee Event Reports Followup (90712 and 92700)

=-*

Through direct observations, discussions with licensee personnel, and review of records, the following event reports were reviewed to determine that reportability requirements were fulfilled, immediate corrective actions were accomplished, and corrective actions to prevent recurrence had been accomplished in accordance with Technical Specification (Closed) LER 249/90001:

Inadvertent Automatic Start of Unit 3 Diesel Generator Due to Procedure Deficienc This event and corresponding licensee actions were described in inspection report 50-237/90003; 50-249/9000 No violations or deviations*were identified in this are.

Plant Operations (71707 and 93702)

The inspectors observed control room operations, reviewed applicable logs and conducted discussions with control room operators during this perio The inspectors verified the operability of selected emergency systems, reviewed tagout records and verified proper return to service ~f affected components~ Tours of Units 2 and 3 reactor buildings and turbine buildings were conducted to observe plant equipment conditions, including potential fire hazards, fluid leaks, and excessive vibrations and to verify that maintenance requests had been initiated for equipment in need of maintenanc The inspectors, by observation and direct interview, verified that the physical security plan was being implemented in accordance with the

• station security pla This included verification that the appropriate number of security personnel were on site; access control barriers were operational; protected areas were well maintained; and vital area barriers were well maintaine The inspectors verified that the licensee's radiological protection program was implemented in accordance with facility policies and programs and was in compliance with regulatory requirement The inspectors revie~ed new procedures and ch~nges to procedures that were i~plemented during the inspection perio The review consisted of a verifitation for accuracy, correctness and compliance with regulatory requirement These reviews and observations were conducted to verify that facility operations were in conformance with the requirements established under Technical Specifications, 10 CFR and administrative ~rocedure Various operational occurrences were also reviewed as follows: While valving in the seal purge to recirculation pump 3A on February 17, 1990, the equipment attendant found the seal purge valve on recirculation pump 38 ope Unit 3 was shutdown at the tim This resulted in a high pressure in the #1 and #2 seal cavities of 1400 psig and 700 psig, respectivel Although the differential pressures across the seals were within design limits and were therefore of minor safety significance, they were greater than that normally experience The seal purge valve to recirculation pump_38 was immediately close F*urther, review indicated that the event occurred as the result of a valving error, A non-licensed operator was clearing several outages in the drywell including outage number III-SS~, which involved an out-of-service on recirculation pump 38 to repair a sea The outage checklist specifically indicated that recirculation pump 38 seal purge isolation valve 3-0399-S09 was to be left in the clo6ed position when it was cleare This was to prevent pressurization of the seals since the suction and discharge valves were in the closed position at the tim The *seal purge isolation. valve was located outside the drywel Since the copy of the outage checklist became contaminated, the operator left it in the drywell and performed the portion of the clearance involving this valve from memor As the normal position of this valve when operating was open, the operator placed it in that position r~sulting in the over-pressurizatio This error was dis~overed prior tp the subsequent independent verificatio The valving error represented a failure to accomplish activities affecting quality in accordance with instructions, in this case the outage checklist, contrary to the requirements of 10 CFR SO Appendix 8 Criterion V (S0-249/90008-0l(DRP)).

Review of administrative proced4res indicated that no guidance was provided as to whether operators were re qui red to obtain a new. copy of the outage check.list and to have it in-hand for completion if it became lost or contaminate The 1-icensee i~sued Operations Department Policy

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I

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No. 19, Using Outage Checklists, to provide guidance in this area.:

In addition, the licensee initiated.actions to include the event and the subsequent guidance

~.n ~he operator continuing t~aining p~egra As the consequence of th1s.1solated event had only. minor safety significance and the licensee had initiated appropriate corrective actions, no Notic~ of Viriiation is bei~~ ~ii~~d in actordancc with 10 CFR 2 A~pendix C Section V.A.. The inspectors have no other concerns in this area and this item is considered close During performance of Dresden Technical Surveillance (DTS} 300-2, Control Rod Drive (CRD) Scram Testing and Scram Valve Timing Test,

• on February 24, 1990, two rod manipulation errors were performed on Unit 3 by Hcensed -operator.CRD L-9 was pulled from position 40 to position 48 and then scrammed into position 00 in accordance with procedur However, the CRD was then incorrectly pulled back to

.po~itton *43 instead of the proper position 4 The Qualified Nuclear Engineer was in attendance to assess the situation and gave guidance to return the CRD to its proper positio The CRD was subsequently placed back to position 40 and testing was continue Another error occurred approximately 12.minutes later when the wrong CRD was scramme The Nuclear Station Operator (NSO) instructed the extra NSO who was stationed behind the main control panel at the scram test panel to scram CRD M-The extra NSO misunderstood the NSO and scrammed CRD H-3 instea CRD H-3 was to have been scram*

tested later in the testing sequenc The Qualifi~d Nuclear Engineer was again present and CRD H-3 was repositioned to its proper position 4 Scram testing continued and licensee management subsequently suspended further testlng about half an hour after the second event to review the policy.concerning control rod manipulation error Safety significance in regard to core parameters did not exist.. A review of procedures controlling testing manipulations of the CRDs reve~ed that testing of the.CRDs was not required to be done in any specific sequenc Additi~nal precautionary measures were taken to increase communication and attention prior to resumption of testing on the next shif These measures included a discussioh between the shift engineer and those involved in the testing to emphasize attention to detail and communication and to ensure that the Qualified Nuclear Engineer indicate to the NSO each time a rod was to be placed back to its proper positio The licensee was still formulating long term corrective actions at the end of the inspection period but items being discussed included emphasis of alpha-designations during communication through tailg~tes and continuing training program On March 19, 1990, a waterhammer event was noted on the Unit 2 HPCI discharge line while performing the valve. operability surveillanc Operators reported hearing waterhammer noises as far away as the thir.d floor of the reactor buildin (The HPCI discharge piping was beneath the ground floor running through the torus catwalk area, west Low Pressure Coolant Injection (LPCI) corner room and HPCI pump room.)

Operators also reported seeing what appeared to be as much as a one inch ~ovement of the piping in the LPCI corner* room and vibration being felt on the ground floo The pump operability portion of the surveillance was susp~nding pending further licensee

in~estigation of the ~ven Some lesser noises were still heard as much as an hour and a half fol~owing manipulation of the valve A previous event involving the discovery of HPCI support damage on both units was potentially attributed to waterha~mer event~ ~~*

an AIT during a November 1-4, 1989 inspection as described in inspection report ~0~237/89023; 50-249/8902 Unit 2 HPCI was being kept in an alternate lin~up due to steam cuts on a valve seat allowing leakage of feedwater back through outboard discharge valve 2-2301- (The bent stem on this valve was replaced during the dual unit outage in December 1989 such that current traces were no longer required each time the valve was cycled.)

Unit 3 HPCI valves were repaired during the December 1989/January 1990 refueling outage and therefore Unit 3 HPCI was no longer utilizing the alternate lineu The alternate lineup consisted of leaving the valve 2301-8 open and instead closing inboard discharge valve 2301-This caused the discharge line to be subjected to feedwater pressure back. to valve 2301-9 and Condensate ~torage Tank (CST) retu~n valve 2301-1 This higher pressure in this portion of the line prevented saturated condition In addition, the stagnated water in the line eventually equalized to the ambient temperature of its surrounding The licensee's root cause involved the formation of voids during the HPCI surveillanc The HPCI valve operability surveillance procedure tested the interlock between torus suction valves 2301-35 and 36 and CST return valves 2301-10 and 1 When the torus suction valves opened, the CST return valves automatically closed to prevent pumping the torus water to the CS The surveillance closed valve 2301-8 and then opened valves 2301-10 and 1 Valves 2301-35 and 36 were then opened and valves 2301-10 and 15 were verified to automatically clos Opening of valves 2301-10 and 15 provided*a flowpath, even though valve 2301-8 was closed, since valve 2301-8 still leake This allowed feedwater to flow through the system and heat up the water within the.pipin Later during inservice testing (!ST) timing of valve 2301-9, the waterhammer noise was first hear Opening of valve 2301-9 had depressurized the volume wnich by this time was hot enough to result in saturated condition When the water reached saturated conditions it flashed to steam to form voids in the piping that could have resulted in waterhamme Temperature monitoring did seem to support this root caus The event occurred at 3:10 a.m. while the temperature taken at the elbow into the X-area (steam tunnel) was 203 degrees Fat 9:00 a.m. and 160 degrees F at 2:00 Thi~ indicated that the piping was cooling off from some higher temperature which could represent saturated condition Void formation from the higher temperature could have caused the waterhamme The original evaluation of the alternate lineup for Unit 2, assigned onsite review number 89-44, add~essed needed changes to various procedures including Dresden Operating Surveillance (DOS) 2300-1, HPCI Motor Operated Valve (MDV) Operability Verification, to reflect this lineu However, the evaluation did not specifically address

• the*effects of simultaneously opening both CST return valves during the surveillance in light of the known leaking outboard discharge valv Detailed walkdowns following this recent occurrence indicated minor damage to two supports which were both located in the torus catwalk area.. Support M-1151D-86 was unloaded with a loose clamp nut while support M-1151D-5 was partia1ly unloaded with a bushing pushed out of the* clevi During the previous event, the M-115iD-86 pipe clamp was found slightly skewed and was repaired while no problems were found on support M-1151D-5, Overall, *damage was much less extensive than that found during the previous even No problems were found wi.th the baseplates or anchor bolt Since the valve operability surveillance was done on a monthly basis, this damage could have also occurred sometime between the previous event and this occurrenc The licensee repaired the damaged support Based upon evaluations done during the previous event for operability of the HPCI system and the lesser damage found during this occurrence~ the licensee did not believe the HPCI system to be inoperable due to the two damaged support The licensee revised the valve operability surveillance to close and test only one of the CST return valves at a time such that a potential flowpath would not occu The licensee then again performed the valve operability procedure on March 22, 1990, while stationing observation personnel in the plant when it was conducte No waterhammer event was note However, about an hour after~the valve operability surveillance was complete, iicensee personnel found the pipe temperature at the elbow entering the X-area had risen*to 322 degrees F while in the alternate lineu (The temperature at the completion of the surveillance was 91 degrees F.)

This increase in temperature indicated that valve 2301-10 was leaking through, providing a flowpath through the syste Saturated conditions were not reached since pressure upstream ~f valve 2301-10 was at feedwater pressur Temperatures taken downstream of valve 2301-10 indicated the highest achieved temperature at this point was 140 degrees F which also precl.uded saturated conditions in this are After closing valve 2301-15 (located downstream of valve 2301-10) temperature in the line again decreased to equalize with surroundings since this deleted the flowpat As a result of further testing, the licensee decided to maintain the standby lineup with valve 2301-15 closed to preclude a leakage pat The licensee also intended to change the lineup on Unit 3 the same way, although valve 2301-10 was. not currently leaking on that unit, as a precautionary measur The licensee planned to submit a supplemental LER to the original October 1989 event which would describe additional corrective actions which the licensee was still developing at the end of the inspection perio These a~tions will be further reviewed when the LER supplement is issue On March 28, 1990, with Unit 3 at 99 percent *rated thermal power, a feedwater transient occurred do to a failure in the feedwater control syste The first indications of the failure were observed

• as a ~emineralizer trouble alarm and an operator selected alar The operator selected alarm was set for a reactor water level of 27 inche The normal low level alarm was 20 inche Following the alarm, the NSO noticed that feedwater regulating valve A, which was in automatic control, was going close Feedwater regulating valve B was in manual control at 40 percent ope The NSO immediately opened feedwater ~egulating valve B such that the level decrease was turned and then placed valve A in manual and returned water level to a normal 30 inche Reactor water level had reached a low of 18 inches during the transient as compared to the scram setpoint of eight inche The NSO then placed the controllers back to their original configuratio Shortly thereafter the red '

indicating lights on all the feedwater controllers went blank and a feedwater system trouble alarm was receive This time the system automatically switched to the backup control modul The failed control module was subsequently replace The licensee with the assistance of the controller vender was investigating the cause of the failure and the late automatic switch to the backup control mogul The alert and quick response exhibited by the NSO clearly prevented a scra No violations or deviations were identified in this are.

Maintenance and Surveillances (62703, 61726, and 93702) Maintenance Activities Station maintenance activities of systems and components listed below were observed or reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides and industry codes or standards and in conformance with Technical*

Specification The following items were considered during this review:

The Limiting Conditions for Operation (LCOs) were met while components or systems were remov~d from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were inspected as applicable; functional testing and/or calibrations were performed prior to returning components or systems to service; quality control reco~ds were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and, fire prevention controls were implemente Work requests were reviewed to determine status of outstanding jobs and to assure that prio'.ity is assigned to safety-related equipment maintenance which may affect system performanc (i) Upon rolling the main turbine during the Unit 3 startup on February 20, 1990, condenser vacuum was noted to be decreasin The licensee found various related problems during the subsequent investigation as described *in inspection report 50-237/90003; 50-249/9000 In addition, the licensee

theorized excessive in-leakage into the condense Following extensive walkdowns and usage of helium leak detection methods, the licensee placed the main turbine on shell warmin A loud noise was heard under ~he high pressure turbine cover and upon removal of an inspection hatch, steam was noticed blowing from the top of the turbin A one inch cap was found missing from a tap that had been used to pour in lubricati~g oil to enable easier removal of the turbine casing during the recent refueling outage:

Work request D83614 had a step to remove the casing but did not specifically address these caps or the process of using lubricating oil to ensure the casing did not stick to the diaphrag It appear~d as if the caps h~d been reinstalled but were not tightened such that this one vibrated of There was no safety sig~ificance involved in this event and the work package was not safety-related. Therefore, the inspectors have. no concerns in this are (2)

On February 23, 1990, Unit 2 commenced a Technical Specification required shutdown from 90 percent power and declared a~ Unusual Even The shutdown was required because of an outboard containment isolation valve failed the valve stroke timing surveillance on the recirculation sample system with the inboard isolation valve leaked past its closed sea The licensee de-inerted and entered the drywell to repair the inboard valve while the outb6ard valve's timing was adjuste On February 24, 1990, all repairs were completed and the

. Unusual Event was terminate The inboard valve was left with a very small amount of leakage.* The license..e inerted the drywell and returned the reactor to 90 percent powe During the Unusu~l Event, power-was reduced to about 20 percent in preparation for shutdown to Hot Standb The shutdown was also stopped when. the Unusual Event was terminate (3)

On March 10, 1990, Unit 3 experienced a reactor scram from 100%

powe The pilot air line to outboard Main Steam Isolation Valve (MSIV) 2A failed resulting in the closure of the affected MSI The pressure spike in turn caused a high flux condition resulting in a reactor scra High steam flow in the other three majn steam lines resulted in closure of all MSIVs (Group I primary containment isolation).

The closure of MSIVs (less than 10 percent full open)"resulted in.another subsequent reactor scram signa All control rods were verified to be fully inserte Groups II and III primary containment isolations occurred after the reactor scram due to low vessel water level as expecte Other expected system responses included the reactor building ventilation isolation and standby gas treatment system automatic initiatio *

. During the event, the operators manually initiated the isolation condenser for vessel.pressure control, restored vessel level with the feedwater/condensate_system and placed the unit into a safe hot standby conditio The primary containment isolations were reset, with the exception of the affected main steam lin..

Several minor component failures did occur during the even Orywell sample valve 3-8501-588 failed to indicate closed during the Group II.isolation buf was verified to have close A limit switch was adjusted to correct the position indica~ion proble Isolation condenser condensate return isolation valve 3-1301-3 also failed to manually fully clos This was evident by steam continuing to be released out of the isolation condenser vent after the operator had received a closed *

indicatio Further attempts to close the valve failed and fl ow was stopped by ci osure of condensate return* valve 3-1301-4, located downstream of t~is valv A current trace performed with the valve opening from the as found condition indicated that it had,not attained a full closed condition since the representative spike from coming off its seat was not presen Subsequent review indicted that the valve operated as des;gne Due to the arrangement of the closed limit switch, the closed indication for this throttle valve may be received before the valve is completely close Operating Order 5-90, Operational Guidelines for Motor Operated Valves, issued January 1, 1990, recommended holdi.ng the control switch in the closed condition for 20 seconds after the full closed indication is displayed for these type of throttle valve The operator, in this case, had released the switch as soon as the closed indication was received, preventing i.t from further closin Further attempts to close the.valve did n6t work because the valve logic required the valve to be reopened before the closing contactor could be picked up agai This logic was employed as a limitorque anti-hammering modification to address stem bending problems, The licensee was reviewing this operating order to determine if it should be revised to list specifically affe~ted valve The licensee also planned

,to provide additional guidance to the operators regarding this logic desig The pilot air line to MSIV 2A was repaired and the other Unit 3 outboard MSIV pilot air lines were inspected by the license This inspection also resulted in work on the MSIV 2C pilot airlin The licensee attributed failure of the pilot air line to mechanical weakening of the copper tubing at the point where it was coupled to the pilot assembl It appeared that the tubing had been bent and then straightened which weakened it such that normal vibration caused a failur Bending of the tubing may have occurred during the recently completed Unit 3 refueling.outage when work request 065489, involving rebuilding of the air operator and work.request 089891, involving repair of an accumulator air supply check valve were complete The licensee was evalua~ing possible corrective actions in regard to a design of the MSlV pilot air lines that would b~ less

susceptible to kinkin The final corrective actions will, therefore, be reviewed in the next inspection perio *

Recirculation pump 3A was at first thought to have failed to automatically run back and was manually reduced to minimum speed by the unit operato It was later determined that the

recirculation pump 3A run back had, in fact, not faile Recirculation pump 38 had run back without waiting for t~:

designed ten* second time dela Seeing this pump run back, the operator manually ran back the other pump prior to initiation of the automatic run bac The operator was not aware of the designed time dela A failed time delay relay on pump 38 was sub~equently replace Failure of this relay has not been a problem in the past.. The licensee also planned to provide additional gui~ance to the operators as to the existence of this rela (4)

On M~rch 15, 1990, the control room:operators observed that recirculation pump 38 seal #2 cavity pressure had trended up to approximately 600 psig as compared to an expected 500 psi~.

This indicated the existence of some* inner seal degredat ion and leakag Drywell identifiecj leakage determined from integrator readings when periodically.pumping the drywell equipment drain sump indicated about 1.85 gpm which had. been relatively constan Dresden Technical Specifications allow 5 gpm unidentified leakage and 25 gpm total (identified and*

unidentified) leakag Thus, leakage was small in comparison to established limit The licensee increased observation of this area by instituting hourly logging of the seal #2 cavity pressur As described in inspection report 50-237/90003; 50-249/90003, the licensee had recently shut down Unit 3 to repair leakage from the same seal.* Upon overhaul of the seal, the licensee could not find any conclusive evidence of what the problem wa (This seal had been just previously overhauled during the last Unit 3 refueling outage in December 1989).*

Upon subsequent restart after'overhauling the seal, ~twas noted that the recirculation pump control seal leakoff flow alarm came up when reactor pressure reached 700 psi However, seal pressures were as expected at that time and thus startup continue This alarm had been up continually since startu By March 20, 1990, seal pre~sure had.trended to 660 psi Following power changes on March 20, 1990, seal pr~ssure was*

noted to have decreased to about 540 psi At the end of the inspe~tion period.the pressure was 490 psi The licensee did not conclude that the inadvertent pressurization of the seal cavities in February, as described in paragraph 4.a.,

contributed to these seal pressure problem The licensee however, was making*contingency plans for possible unit shutdown and repair of the sea Surveillance Activities The inspectors observed survejllance.testing, including required Technical Specification surveillance testing, and verified for actual activities observed that testing was performed in accordance with adequate procedure The *inspectors al so verified that test instrumentation was calibrated, that Limiting Conditions for Operation were met, that removal and resioration of* the affected components were accomplished and that t~st results conformed with Technical Specification and procedure requirement Additionally, the inspectors ensured that the test results were reviewed by personnel other than the individual directing the test,*and that any

..

deficiencies identified during the testing were properly reviewed and re.solved by appropriate management personne The inspectors ~itnessed or reviewed portion~ of the following test activities:

Torus *.to Orywe 11 Vacuum Breaker Testing Core Spray Pump Operability Test LPCI Pump Operability Test HPCI V~lve Operability Test The inspectors also reviewed the on-site calculational results of corrosion/erosion inspections conducted during the previous Unit 3 refueling outag These were accomplished in accordance with the program to maintain the integrity of single phase and two phase high energy carbon steel and low alloy steel piping systems agains degredation by erosion/corrosion as delineated in Generic Letter 89-08 11 Erosion/Corrosion-Induced Pipe Wall Thinning.

The program utilized ultrasonic testing techniques to determine component thickness ~nd wear rate and included specific component selection (high probability of excessive wear) and expansion criteri Sixty-six components were originally chosen for inspection of which four were either repaired or replaced due to inspection results indicating excessive wea An additional nine components were chosen in accordance with the expansion criteria of which one subsequently needed repair, in accordance with the inspection result The inspectors believed this to be a useful technique in detecting and preventing possible future failures of piping a related component No violations or deviations were identified in this are.

Engineering/Technical Support (93702)

The licensee informed the resident inspectors on February 21, 1990 of a potential unanalyzed pipe stress condition which could result with the recirculation system operating in a single loop configuratio The effects of aifferential expansion with an idle recirculation loop were not explicitly addressed in the original or current design specifications or design/stress reports, Therefore, a temperature differential of more than.SO degrees F between an idle and operating loop would have an unknown effect on pipe stress, support loads, spring can and snubber, *

settings and pipe whip restraint gap The licensee believed the effects

• from a 50 degrees or. less temperature differential would be insignificant and acceptabl As the or.iginal analysis was completed by General Electric, there existed the potential for generic appl~cabil~ty to other boiling water reactor Until resolution of this issue, the licensee was implementing temporary administrative controls to ensure that the temperature differential was not allowed to reach 50 degrees F when in single loop operatio The licensee was also reviewing past operating history to identify instances when this potentially unanalyzed condition

~ad been entered and was performing an analysis to determine

reportability of this issue based on safety significanc Analyses being performed by the licensee were to address short term operating

considerations of thermal and gravitational stresses for single loop operation for all loop The licensee had not yet decided whether to do an analysi~ supporting long term single loop operation ior all loops by including seismic concern An analysis for long term considerations for loop 38 only was, however, being conducte These efforts were expected to be completed by mid-April 199 *

No. violations or devi~tions were identified in this are.

Safety Assessment/Quality Verification (40500)

Recognizing a negative trend regarding various problemi encountered since completion of the Unit 3 outage (as documented in inspection report 50-237/90003: 50-249/90003 and paragraphs 4 and 5 of this report),*

licensee management conducted a special 50 percent power plateau revie The review, conducted on February 25, 1990, was in accordance with Dresden Poli~y Statement #24, Achieving and Maintaining.Error Free Operatio The various problems discussed included the following:

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0

. 0

Condenser vacuum problems including the partial cause invol~ing the high pressure turbin Recirculation pump seal performance including the con5equences of fa~lure of a seal that had just been rebuilt and the current high 5eal flow alar Drywell floor and equipment drain leakag Recirculation pump seal cooler failure and temporary modified leakoff piping to the drywell equipment sum Control rod mii-positioning events during scram testing.

Inadvertent recirculation pump hydro by the CRD syste As the licensee felt that some of the problems were unnecessary, these problems were subsequently discussed with station personnel during tailgate meeting The inspectors noted that the licensee review was representative of an ability to recognize and quickly address negative trend The inspectors observed the monthly performance review meeting conducted on March 1, 199 Plant management reviewed items of interest since the last meeting including specifi~ operating events, problems and root caus The status of various action items was discussed, as well as the 1990 goals presentation and workplace improvement commit.tee item Recent-results of quality assurance audit and surveillances were reviewed and the status of the maintena~ce improvement program was discusse The inspectors noted that plant management was well informed and knowledgeable of plant activitie No violations or deviations were identified in this are * Previous Emergency Operating Procedure (EQP) In$oection Items An inspection to review th~ licensee's corrective actions in response to specific deficiencies in the Dresden Emergency Operating Procedures (DEOP) identified in inspection report 50-237/88012; 50-249/88014 was performe The specific open items reviewed during this inspection were discussed in paragraphs 4.a(l), 4.a(2), 4.a(3), 4.b, 5 and Attachment B to the original inspection repor The inspection was performed in accordance with s~lected portions of Temporary Instruction (TI) 2515/9 Although the inspection focused on the licensee's corrective actions to open items, considerable effort was devoted to the licensee's recent implementation of revised EOPs based on Revision 4 of the Boiling Water Reactor (BWR) Owners Group Emergency Procedure Guidelines (EPG) and EDP related documentatio '

Results The inspectors concluded that major improvements had been made in the licensee's EDP program with the development and implementation of revised EOPs based on Revision 4 of the BWR Owners Group EPG All the open items identified in Sections 4.a(l), 4.a(2), 4.a(3), 4.b, 5 and Attachment B of the original inspection report 50-237/88012; 50-249/88014 have been closed with the exception of four items in Attachment The remaining open items are:

(1) Item 3, DEOP 200 Series Flow Charts, legibility of scale markings; (2) Item 3, DEOP 500-1, identification of location of proper source of.service water; (3) Item 6, DEOP 500-2, proper use of words "to" or "and" in procedures and control room label; and (4)

DEOP Equipment Cabinets, development of a procedure t~ account for equipment stored in cabinet Specific tracking numbers are assigned in paragraph 8.d of this repor In addition, the inspectors during the course of review of the open items were able to address some of the

• observations of the original* inspection team related to simulator scenarios, human factors analyses and validation and verificatio The inspectors recommend that for the programmatic changes made to the DEOP flow charts and the 500 Series procedures since the original inspection (including deviations from the Plant Specific Technical Guidelines (PSTG)), the licensee should develop and maintain documen~ed justification in auditable for Objective The objective of this EDP follow-up inspection was to audit-and a~sess licensee corrective actions in response to items identified in inspection report 50-237/88012; 50-249/8801 In thi~ report, the following areas and number of open items.were identified:

(1) Technical Adequacy Rev1ew of the DEOPs (31); (2) Control Room and Plant Walkdowns and (3) general comments and 60 detailed walkdown comments contained in Attachment Three of the open items related to the technical adequacy review of the DEOPs were closed in Inspection Report 50-237/89017; 50-249/8901 Background The Three Mile Island (TMI) Action Plan (NUREG's 0660, 0737, and 0737, Supplement 1), required licensees of operating reactors to

reanalyie transients and accidents and to upgrade EOP Special NRC team inspections of BWR Mark I EOP programs were conducted in 1988; these inspections identified significant weaknesses in some programs, as summarized in NUREG-135 This follow-up EOP inspection was conducted to confirm that acceptable corrective actions had been implemented at' the Dresden Nuclear Power Station, Units 2 and 3, in response to the findings of inspection report 50-237/88012; 50-249/88014, dated August l~, 198 Since the initial inspection, two revisions to the DEOP utilizing flow charts (DEOP 100 thru 400) had been mad The first revision issued in October 1988 primarily corrected deficiencies resulting from the inspectio The second revision which was implemented in December 1989 was based on Revision 4 to the BWR Owners Group EPG This revision also made significant format changes to the procedure The inspectors reviewed the first revision to flow charts to determine which findings of the i~spection report were addressed and the latest revision to assure lhese findings were included and if any of the findings not addressed in the first reYision where corrected in the most cufrent revisio Many of the more general findings, and in particular those related to human factor observations, were improved in the current revision to the DEOP T.he 500 Seri es DEOPs which were in written format, were extensively revised once since the initial inspection in December

• 198 Findings The findings identified in ~nspection report 50-237/88012; 50-249/88014 are addressed in this Sectio Numbers in parenthesis indicate section and item in the original inspection repor Validation of the drywell spray initiation pressure limit (4.a.l),

justification for use of 200 degrees as an entry condition for primary containment high temperature (4.a.2), and validation of the nomograph showing allowable pump net positive suction head (4.a.3)

were closed in inspection report 50-237/89017; 50-249/8901 Since this i'nspection, two EOP revisions (October 1988 and December 1989)

had occurred:

The inspection open items identified were addressed in the October 1988 DEOP revision as indicated in the licensee's September 30, 1988 reiponse which identified corrective actions being take The inspectors also verified that all the applicable open item revisions in the October 1988 DEOP revision were retained in the December 1989 DEOP revision which utilized Revision 4 to the BWR Owners Group EPG *

Independent Technical Adequacy Review of the EOPs (1)

(Closed) Open Item (237/88012-4.b.1 and 249/88014-4.b.l):

Difference between the PSTG caution and DEOP caution related to conditions under which Reactor Pressure Vessel (RPV) may be depressurize The revised DEOP 100 eliminated ambiguity by not requiring a determination if adequate flow was available to cool the cor The flow chart identified. the systems and number of systems required to be operable to maintain core coolin This item is close *

(2)

(Closed) Open Item 237/88012-4.b.2 and 249/88014-4.b.2):

PSTG step SP/T-4 had missing informatio The licensee's September 30, 1988 letter stated the information was inadvertently omitted and that the PSTG would be revised as part of the Revision 4 upgrade to the EPG The inspectors reviewed the current PSTG and determined the missing information was include This* item is close (3)

(Closed) Open Item (237/88012-4.b.3 and 249/88014-4.b.3):

PSTG Caution 21 does not apply to the HPC This c~ution was deleted in the revised DEO This item is tlose (4)

(Closed) Open Item 237/88012-4.b.4 and 24/88014-4.b.4):

DEOP Flow Chart 200-4 procedure executes Reactor Vessel Control (RVC) at Step C4Al whereas the PSTG executes this step after emergency depressurizatio The PSTG had been revised to match the flow logic in the DEO This item is close (5)

(Closed) Open Item (237/88012-4.b.5 and 249/88014-4.b.5):

An inconsistency was identified between DEOP Flow Chart 200-4, Caution 9 and control room label relative to number of gallons of water in the condensate storage tank when it reaches low level of 1.5 f The reference to gallons in the flow chart had been eliminate The flow chart was currently consistent with the control room label and only indicates a low level of 1.5 f This item is closed.

(6)

(Closed) Open Item (237/88012-4.b.6 and 249/88014-*4.b.6):

DEOP 200-1, Step C2B calls for operation of drywell coolers which is not in the PSTG.. Drywell coolers had been eliminated in DEOP 200- This item is close (7)

(Closed) Open Item (237/88012-4.b.7 and.249/88014-4.b.7):

DEOP 200-2, Step C2 for bypassing interlocks prior to starting drywell coolers is not in the PSTG, nor is the drywell pressure requirement of le~s than 5 psig for operation of these cooler The licensee in its September 30, 1988 letter stat~d the authorization to bypass interlocks, 'if necessary, to operate the drywell coolers had been incorporated into Revision 4 of the EP Since th~s revision to the EPGs was currently in use at Dresden, this is acceptable and this item is close The licensee also justified the 5 psig drywell limit in the September*3o, 1988 lette The licensee stated that this limit was consistent with the operating limit imposed in the drywell cooler system operating procedure and that operation at higher pressures may cause the fan motors to overhea The inspectors determined this justificition is acceptable and therefore this item is close (8)

(Closed) Open Item (237/88012-4~b.8 and 249/88014-4.b.8):

In DEOP 200-1 the first override differs from the associated override in the PSTGs, torus "cooling" is not contained in the PSTGs, and drywell spray is not contained in the PSTG The

...

(10)

( 11)

differences between the first override in the DEOP and PSTGs had been corrected and torus 11cooling 11 had been eliminated from the DEO The licensee in its September 30, 1988 letter stated that the current placement of the instruction to close the drywell spray valves was consistent with the basic intent of the *PSTGs and therefore no chan.ge to DEOP 200-1 was require The inspectors reviewed the DEOP flow chart and agreed with the licerisee's d~termination. This item is close (Closed) Open Item (237/88012-4.b.9 and 249/88014-4.b.9):

In DEOP 200-:1 the drywell pressure value of 14 psig in the flow chart was different from the step in the PSTG which called for 13.4 psig in the toru This value was rounded off to 13 psig in the October 1988 revision to DEOP 200-1 for instrumentation readability which was in the conservative directio The new PSTG (based on Revision 4 to the BWR Owners Group EOPs)

utilized a new calculational.method and resulted in*the use of a 9 psig drywell pressure in DEOP 200- This item is close (Closed) Open Item (i37/88012-4.b.10 and 249/88014-4.b.10):

In DEOP 200-1 the PSTG Step PC/P-7 "or if the suppression chamber cannot be vented" has not been incorporated in the DEOP flow char A step had been added to the flow chart that states the drywell should be vented if the suppression chamber cannot be vente This item is close *

(Closed) Open Item (237/88012-4.b.ll and 249/88014-4.b.ll):

In DEOP 300 the integrated radiation release control actions and secondary containment control actions are different than the PST These actions had been corrected to be consistent with the PST This item is close (12) (C}osed) Ope~ Item (237/88012-(.b.12 and 249/88014-4.b.12):

(13)

In D.EOP 100, Step 4 the 1 ast i tern is not contained in the PST DEOP 100 and the PSTG had been made consisten This item is close (Closed) Open Item (237/88012-4.b.13 and.249/88014-4.b.13):

In DEOP 100 the logic of contrbl and insertion differs from the PSTG step The licensee in its September 30, 1988 letter stated that the various attions to insert control rods was consistent with that incorporated in Revision 4 to the EPG The inspectors verified that the PSTG and DEOP 100 were consistent with EDP Revision This item is close (14) (Closed) Open Item (237/88012-4.b.14 and 249/88014-4.b.14):

In DEOP 100 step RC/L-2 was reversed in sequence relative to PST The.licensee in its September 30, 1988 letter stated'

this was corrected and the inspectors verified that the sequence of these steps was consistent between the DEOP and PST This item is close *

(15)- (Closed) Open Item (237/88012-4.b.15 and 249/88014-4.b.15):

(16)

(17)

(18)

In DEOP 100 the words "AND CONTROL" were omitted from steps RC/L,P,Q. *The licensee in its September 30, 1988 letter stated this was corrected and this was verified during the inspectio This item is close (Closed) Open Item (237/88012-4.b.16 and 249/88014-4.b.16):

In DEOP 100 cautions identified as applicable to step RC/P-5 differ from the PST The inspectors verified that the cautions in the DEOP were consistent with the PST This item is close (Closed) Open Item (237/88012-4.b.17 and 249/88014-4.b.17):

In DEOP 100 step RC/RC2b and 2c are functionally different from the PST Inspectors verified that these steps were currently consistent between the DEOP and PSTG. This item is close (Closed) Open Item (237/88012-4.b.18 and 249/88014-4.b.18):

In DEOP 400-1 the procedural override preceding Step 1 does not appear i~ the PST The inspectors verified that this procedural override had been eliminate This item is close (19) (Closed) Open Item (237/88012-4.b.19 and 249/88014-4.b.19):

In DEOP 400-1 the LPCI subsystem identifiers in the PSTG and DEOPS are differen The inspectors verified that the LPCI subsystem identifiers in the DEOP were consistent with the PST This item is closed..

(20) (Closed) Open Item (237/88012-4.b.20 and 249/88014-4.b.20):

In DEOP 400-1 logic step C12C is not consistent with the intent of the PST The inspectors verified that the flow charts had been revised to be consistent with the intent of the PST When the RPV level drops below minus 143 inches emergency depressurization was required and if no injection system was available the flow charts directed the operators to go into the steam cooling mod This item is close (21) (Closed) Open Item (237/88012-4.b.21 and 249/88014-4.b.21):

In DEOP 400-2 the logic of steam cooling differs from the PST The inspectors verified that the DEOP had been revised to be consistent with the PST This item is close (22) (Cl~sed) Open Item (237/88012-4.b.22 and 249/88014-4.b.22):

In DEOP 400-2, Step C6 and the preceding decision were not contained in the PST The inspectors verified that these items were eliminated from the revised DEOP to be consistent with the PST This item is.close (23) (Closed) Open Item (237/88012-4.b.23 and 249/88014-4.b.23):

In DEOP 400-2 the head vent as a method of RPV depressurization is not id~ntified, however, it is identified in the PST The inspectors verified it had been identified as a method of RPV depressurization in the revised DEO This item is close (24) (Closed) Open Item (237/88012-4.b.24 and 249/88014-4.b.24):

In DEOP 400~3 logic step C4 does not meet the intent of the PST This had been revised to be consistent with the PSTG:

This item is close (25) {Closed) Open Item (237/88012-4.b.25 and 249/88014-4.b.25):

DEOP 400-3 references the primary containment design pressure and the PSTG references the suppression chamber pressur The licensee had installed a torus bottom pressure indication, therefore,. the drywell and suppression chamber pressures were no. longer 'utilized in this flow char This item.is close (26) (Closed) Open Item (237/88012-4.b.26 and 249/88014-4.b.26):

In DEOP 400-3, Step 12 mis-references Step 1 The PSTG *

references Step 17. Steps 17 and 18 were also improperly referenced in the original inspection repor However this comment was no longer valid since these steps had been eliminated in the December 1989 revision to DEOP 400-3 which referenced DEOP 400-5 (failure.to scram procedure).

This item is cl os.e (27) (Closed) Open Item (237/88012-4.b.27 anef 249/88014-4.b.27):

In DEOP 400-4, Step 8 is not contained in the PST The inspectors verified that Step 8 hld been eliminated from DEOP 400- This item is clo'se (28) (Closed) Open Item (237/88012-4.b.28 and 249/88014-4.b.28):

• The original inspection report identified prpcedures that may have to be executed concurrently with the DEOP The fnspection team specifically concluded that Alarm Response and Abnormal Operating Procetjures.contained instructional steps that differed from the DEOPs~ In the licensees September 30, 1988 response, it was stated~that OAP 9-13, Procedural Response to Abnormal Conditions, established hierarchy of procedure categories to follow during abnormal procedure This procedure identifies DEOPs as the highest priority, followed by Dresden General Abnormals, Dresden Operating Abnormals and Annunciator Procedure In addition, the Dresden Stations upgrading of operating procedures was currently ongoin The licensee during this inspection stated that any discrepancies that existed should be eliminated when this upgrade is complete Based on the establishment of a hierarchy and the revision of procedures currently ongoing, the inspectors have determined this concern is.reso~ved and this item is close Closure of these 28 items constitutes total closure of items 237/80012-04 and 249/80014-04 in the original inspection repor Control Room and Plant Walkdowns (Closed) Open Item (237/88012-5a and 249/880i4-5a):

During the original inspection it was noted that the values specified in the

flow chart DEOPs frequently require a level of accuracy which is not obtainable from the instruments used by the operator In this follow-up inspection the values specified in the December 1989 revision to the flow charts, which was based on Revision 4 of the BWR Owners Group EPGs, were checked against the PSTG and the flow charts that were in effect during the original inspectio Based on this review it was determined that this concern had been adequately addresse Numbers had been rounded off to values that match instrument accuracy and were in a conservative directio This inspection also addressed the walkdown comments many of which were related to thi~ concer The results of the walkdown review, which are discussed later, provide further verification this concern had been adequately addresse Based on these findings this item is close (Closed) Open Item (237/88012-Sb and 249/88014-Sb):

In the original inspection, inconsistencies between equipment labelfng and procedures were noted in addition to missing and mis-marked labels:

Attachment B to the original inspection report identified specific eiamples of t~ese problem During this follow-up inspection, the inspe~tors addressed all of the walkd6wn concern Except for a few items, all the inconsistencies and labeling problems had been correcte Almost all the Detailed Control Room Design Review (DCRDR) ~edifications had been completed and new labels had been installed on the panel The DEOP coordinator for Dresden, stated that during DCRDR modifications, valve labeling, and the DEOP flow chart modifications, a considerable effort went into correcting these problem The inspectors did not check beyond those items identified during the walkdown to determine the extent to which

• inconsistencies had been correcte However, based on the findings resulting from the follow-up inspection of the walkdown. items, the extensive DCRDR modifications, valve labeling and the procedure upgrade program, it could be concluded that most of the concerns identified had been correcte This item is close (Closed) Open Item (237/88012-Sc and 249/88014-Sc):

During the original inspection, many specific examples of deficiencies discovered during*the walkdowns were identified in Attachment B to the inspection reports, which raised concerns related to the adequacy of ~he process used at Dresden to develop and implement the DEOP These Attachment B deficiencies.were reviewed during the follow-up inspection and are discussed belo * DEOP 200 Series Flow Charts, Walkdown Comments (1)

The medium range Drywell pressure gage, 8540-001, used to detect any ent_ry condition into Containment Pressure Control,.

had dymo label markings for the proper scale on the cover of a 0 to 100 gage scal A new scale had been put on the recorde This item is close (2)

The "cooli"ng valves" in Procedure Section 200-1, in the bJoc between location Points 2 and 3 are actually labeled "Flow Test" (2-1051-388 and 2-1501-208) on the pane Reference to

"cooling valves" had been eliminated from the flow chart Section 200- This item is close (3)

The medium range drywell pressure strip chart indicator is covered with ink to the point of illegibility and the position indications on the panel drywell spray valve operating switch are also illegibl Problems with the pressure strip chart still existe Although* it was still legible, the markings in some areas of the scale were almost illegible from clearing to remove in No problem with the position indications on the panel spray valve operating switch appeared to exis This item is ope (4)

The nomenclature "Suppression Pool" and "Torus" are used interchangeably in panel labels, sometimes on the same instruments, such as back panel Recorders 2-1640-200A and B for torus water temperatur The flow chart procedure seems to consistently use "Torus."

As a result of control room panel modifications, all nomenclature had been changed to 11 torus

which matches procedure This item is close (5)

In the step following Block 4A of the torus temperature (200-3)

.procedure, torus water temperature is to be maintained below 156 degree The temperature indicator is calibrated in 5 degree increments and, therefore, can not be read to this level of precisio Reference to this temperature was eliminated in the December 1989 revision to the DEOP 200 flow chart and replaced by a heat capacity temperature limit curv This item is close (6)

There were instances of inconsistency in the application of magenta DEOP indicator tags on instruments referenced in the DEOP Examples where tags were missing were torus cooling and the acoustic monitors (which are also not labeled as to function).

Tags were remarked during the control room upgrade which was associated with the DCRDR and inconsistencies or missing tags no longer existe Also a black line* border had been placed around tags referenced in the DEOP This item is close (7)

In the cautions and notes, No. 21 caution that elevated torus pressure may trip the HPCI turbine on high turbine exhaust pressur The gage, PI 2340-5, is not marked for this trip point (100 psig).

No. 28 notes that only drywell pressur~ wide range indicators should be utilized for containment pressures above 5 psig, and specifies that indicators PI-2(3)1640-llA/B on Panel 902(3)-3 be use These indicators are marked LT-1641-5A and These cautions and notes had been delete Thi~ item is close DEOP 100, Reactor Control (1)

The inconsistent use of magenta labeling was noted during the wa 1 kdown of. DEOP 10 For ex amp 1 e, two of the four entry

• conditions (RPV pressure and power) had meters that were not identified with magenta labels in the control roo Also, the OEOP equipment cabinets were identified with white label The use of colored labels was described in OAP 9-4, Control of Dresden Emergency Operating Procedure OAP 9-4, which was revised in January 1989, no longer requires the use of colored label This item is close (2)

The meter, 1602-1, Torus Pressure, was observed not to have any engineering units on, the meter scal Engineering units had been placed on the meter scal This item is close (3) *The scram test switches (Step 6C3) do not have the switch positions labelled on Panel 902-1 The scram test switch

~ositions had been labelled on the pane This item is close (4)

Step 100-1.4 states, "Maintain RPV level greater than -143 inches.

The meter that is used to measure -143 inches has a range of +60 t6 -340 inches in increments of 10 inche A value of -143 inches can only be estimate The typographical error had been corrected and a mark had been placed in the meter indicating the -143 inch leve This item is close (5)

Step 3 states, "Verify Aux Power has transferred."* The operators know how to perform this step using common knowledge, but the control room panels and breaker switches are not labelled "Aux Power. 11 This step had been eliminated from the OEO This item is close (6)

Caution 9 refers to a Condensate Storage Tank Level of "1.5 f or 10,000 gals."

The meter is located in Unit 2 only (not in Unit 3, as implied by the wording of the caution) and has increments in feet of watef leve A label next to the meter stated each foot of water level was equal to 8~000 gallon Therefore, 1.5 feet is equal to 12,000 gallons, not 10,000 gallon In the same caution, HPCI wa~ incorrectly called HPIC, and the word "torus" was used when the control room labels call the torus a "suppression pool."

The procedure.had removed the reference to gallon The typographical error had been corrected and control room labeling had been corrected to r~ad "Torus" as previously note This item is close (7)

Caution 19 stated, "Manually trip Standby Liquid Control (SLC)

pumps at 0% level in the SLC tank.

Since the pumps do. not automatically trip on low level in the tank, waiting to stop the pumps at 0% can result in pump damage due to loss of pump suctio OEOP 400-5 had been revised to trip pump when SLC tank level drops to 8%.

This it.em is close DEOP 200 Series Flow Charts, Secondary Containment and Radioactive Release Control (1)

The Reactor Building Exhaust entry condition (greater than 4 mr/hr) is actually called a "Vent" on the mete It has no

~agenta EDP tag, and.no indicatio~ of the alarm point (on either Unit 2 or Unit 3).

The WO:"dS "Exhaust Duct 11 had* been added to mete This tag had been changed and had a black line border indicating it was referenced in the DEOP The alarm point was no longer specified in the DEOP~ This item is close (2) The determination as to whether an area temperature entry condition has been reached (greater than "max normal") is somewhat comple A front panel alarm is* received which

'directs the operator t~ a back panel on which the individual locations which feed the front panel are indicate Those which are DEOP entry conditions are marked with the magenta DEOP label on this back pane In all bu't 4 cases, this would immediately alert the operator that an entry condition had been reache To determine if an entry condition had been reached in the X-Area or Shutdown Cooling Area, the operator must press a button and read a mete The X-Area and Shutdown Cooling Area were alarmed on the front pane It appeared the nomenclature identif~ing these areas may have been misleading to the inspectors during the original inspectio This comment 1~ not valid and therefore thi~ item is close DEOP 400-1, Level Restoration (1)

The Automatic Depressurization System (ADS) system was called

"Automatic Slowdown System 11 (ABS) on the control panel name plat This had been change This item is clo~e (2)

The table located under Step 3 of the flow chart procedure directs actions based on whether the RPV is a 11 Low Pressure,

11 Intermediate Pressure" or "High Pressure."

The Low Pressure and the Intermediate Pressure regimes are separated by a bar labeled 80 psig and the Intermediate Pressure and High Pressure regimes by a bar labeled 330 psi If the RPV pressures were exactly at 80 or 330 psig, the operator would be uncertain as to the correct action to take in accordance with this tabl In the center section (Intermediate Pressure section), the entry. question is "is HPCI available."

In the steps that follow this question, there is no step which directs the use of HPCI.. The December 1989 revision* to this DEOP had eliminated this proble Actions were based on the RPV pressure being greater than 50 psi above the drywell pressure (single pressure value) and a subsequent step'which directed the operator to rapidly depressuriie the RP This item is close.

-

{3) Several steps in this procedure require that RPV level be read at -143 in.. The gage has gradations iri 10 inch increments and cannot be read to this level of accurac~. Similarly; RPV

. '*

pressure is to be read at 1101 psi This gage has increments of 20 psig~ A mark had bee~ placed on the gage indicating the-143 in. RPV level. *The step that required the operator to read a RPV pressure of 1101 psig had been revised to eliminate this pressur The procedure currently stated that if depressurization were required, that the RPV should be blown dow This item is close (4) This flow chart procedure has the same procedures as previously noted regarding values which cannot be read to the accuracy it specifie All values had been changed to readable values or elimi~ated. This item i~ close (5)

In Block l, the word 11 opening 11 should be.changed to 11 cycling.

The use of the word 11opening 11 had been eliminated in the revised flow chart This item is close DEOP 400-2, Emer:~ency Pressurization

.(1)

In Block 1 the word 11expect 11 should be changed to "except.

This had been changed in ~ubsequent revisi~ns. This item is close (2)

This procedure, in several places, calls for "-torus pressure 11 to be read and compared with RPV pressur The toru~ pressure gage can only be read from +5 to -2.45 in. and so cannot be used in all cases to make this compariso It is believed that the operators actually use Drywell Pressure when making these comparison The narrow range of this pressure* gage al so makes it impossibl~. for the torus pressure to be compared with primary containment design pressure as called for in Note 29 of the procedur This problem had been eliminated with the use of the newly installed torus bottom pressure *indication instead of the torus pressure gag This item is close (3)

The torus pressure gage on Unit 3 does not indicate the units of measurement. *It should read PSI The scale also*consists of dymo labels applied over a scale which is gra.duated 0 to 10 This problem had also been eliminated by the use of the newly installed torus bottom pressure indication instead of torus pressur This item is close DEOP 400-3, RPV Flooding (1) This flow chart procedure has the same problems as previously noted regarding values which cannot be read to the accuracy it specifie The procedures-had been revised to correct this proble This item is close (2)

Caution 25 is repeated in the block which directs the operator to the cautio The December 1989 revision had eliminated this redundanc This item is closed.

-'.

DEOP 500-1, Alternate Standby Liquid Control Injection (1)

The inspector checked the access to and availability of boron'

to the plant in the event alternate boron injection is require Security was asked to provide a key to the storeroom where*the chemicals are store The security personnel on duty could not identify the proper key which was ultimately obtained

• from storeroom personne Adequate boric acid (10, 325#

barrels) and borax (8, 320# barrels) were locate However, these were found to be surrounded by heavy pallets of absorbent granules which would need to be moved out of the way before the boron could be taken to the Turbine Buildin There was no equipment in the storeroom which could be used to move either the boron.or the blocking pallets. Storeroom personnel stated that it is planned to bring fork lifts from the main storeroo Qual1fication and availability* of personnel to perform this function on the 'back shifts and weekends should be verified by the license The licensee in its September 30,.1988 response stated that bresden is providing a controlled itorage space for boron chemicals tha_t would be established by December 1, 198 The licensee had since changed its method of storage of boron..

The boron was currently contained in premeasured 3.5 gallon container~which were stored in a ded~cated locked cage within the Unit 2 turbine buildin The licensee during its verification and validation program verified that adequate personnel were available to perform this function on the back shifts and weekend This item is close (2)

Steps 4.b.(l), (2), and (3) call for the manipulation of valves in the Reactor Water Cleanup (RWCU) Demineralizer Valve Galler This is a high radiation are The valves are located high in the gallery and there is no ladder or other equipment provided to facilitate their operation in an emergenc The DEOP no longer required manipulation of these valves since the condensate demineralizers were used instead of the RWCU demineralizers for alternate SLC injectio This item is close (3)

Several problems were noted in carrying out Steps 5.a.(12)(a)

through (c) which are the staps in which alternative sources of water. are obtained to prepare a boron solution in the CATEX tan Step (a):

Neither of the clean demin. water so~rce valves or supply fittings were marke The supply located on the east end of U2 Turbine Building Closed Cooling Water (TBCCW) Heat Exchanger has two stop valve The upstream valve is missing a valve handle and it is unknown if the valve is open or shu Step (b):

There are several Condensate Demineralizer Post Strainer Drains, so the items should be made plural in the procedur Step (c):

The proper source of Service Wa.ter for this evaluation was not easily determine After some searching, it was determined that a pressure test *

connection which now has a gage attached would be the most

ii

likely candidate sourc All of the problems identified had been corrected with the exception of the location of the proper source of service wate This location was not th2 pressure test connection identified in the original repor The inspectors recommend that the true location be identified in the procedur The original inspection report also recommended that the alternate source~ of water should have magenta tags

• indicating these are identified in the DEOP The licensee stated that no special DEOP designation had been given to any

.systems for ease of finding including those that provide alternate sources of water for the SLC syste Since Dresden had not specifically identified these as DEOP systems to maintain marking con~istency throughout the plant. the inspectors have no objection to the licensee's positio This item is closed except for the concern related to identification of the location of the proper source of service wate (4)

In Step 9.b.(l)(a) and (d) the Cleanup Controller and the Drain Flow Regulator were without numbers in the Control Room (this is one example'of many).

In Step (e), RWCU system temperature is obtained from a six position temperature instrumen The procedure does not specify which position should be used (probably Position 3).

In Step (i), the operator is to observe Regenerative*Heat Exchanger Inlet Pressure and Reactor Pressure and note when the difference is less than 100 psi The procedure does not direct ~he operator to the nearest Reactor Pressure gage to minimize the difficulty of making this calculation (probably the HPCI pressure gage).

In Step (n),

the operator is to "maintain suction pressure on RWCU Recirculation Pumps" however no values are give Since the RWCU system was no longer used as an alternate source of water for standby liquid ~ontrol injection these concerns are no longer vali This item is close DEOP 500-2, Bypassing Interlocks and Isolations (1)

In Procedure DEOP 500-2, some minor inconsistencies were noted between switch labelling in the control room and valve descriptions in the procedur This was corrected with the December 1989 revisio This item is close (2)

In Step A.8, Step C.1 should be eliminated in the revi~ed procedur This step had been This item is close (3)

In Step C.l.c(7), Valve MO 3-3005 was noted not to 'be numbered on the control room label, only the name of the valve was give This hi~ been corrected as part of the control room upgrad This item is close (4) Three main steamline drain valves, MO 3-220-1, 220-3 and 220-4 were observed to.have control switch positions (open-closed)

that could not be read, because the labelling had worn of These valves had been relabele This item is closed.

(5)

(6)

(7)

(8)

. (9)

Step C.1.c(18) instructs operators to "Return the Main Steam Line (i-~::;~)

.:~-:.~:;.o.lves to their normal position. 11 The step should clearly list which valves are to be returned to their

~ormal positio Th's had not been changed ih the revised procedur The valves in question were identified as required to b'e verified "open" four steps earlier in the procedure in the same pag Although it was not necessary to relist these valves, the inspectors suggest relisting for consistenc This item is close In Step C.2.b, the words "to" are indicated as* "and" in the control room label This has not been changed in the control roo Upon further review by the inspectors, it was determined that the 4kv breakers can go either wa Therefore 11 and 11 as indicated in the control room label was more appropriate and the procedure should be change This item is ope In Step C.3.a(l)(f), the operator is supposed to perform an action based on reactor water level being below 2/3 core heigh This level in inches is more appropriate in the procedure and should be consistent with the ability to read the Fue 1 Zone range meter This had been change This item is

• .close Step C.3.a(l)(k) references a dP indicating controller that the operator has to monito The scale on the meter was noted to be incorrec The correct scale was superimposed onto the incorrect scale with a piece of tap This had been correcte This item is closed.

Step C.4.a(2) directs operators to ensure the Fuel Pool radia~ion level is bel~w 100 mr/h The control room meter was labelled with an alarm setpoint of 90 mr/h The difference between the 90 and 100 mr/hr setpoint was not clea Since the control room meter had an alarm setpoint which is lower than specified in the procedure and was therefore mor~ c9nservative, this is acceptabl This item is close (10) Step C.4.a(4) should include the value needed for the operator to determine if Reactor Building differential pressure is being maintaine This step had been deleted for the procedur This item is close (11) Step C.4.b(3)(a) and (b) direct the operator to start fans without clearly identifying which_fans are to be *starte Since there were only tw6 fans (fan types designated as RBX exhaust and supply fans).which were clearly marked, the (12)

.inspectors do not think it is necessary to identify the specific fans by number in the procedur This item is close Step C.6 incorrectly lists 11 RFP 11 as 11 RVP11 *

Also, the two steps, D and E, are incorrectly labelled as G and procedure had been revised to correct these prbblem item is close last H:. The This

DEOP 500-3, Alternate Water Injection Systems (1)

Step D.l.b.(6) requires the operator to pump the alternate unit's torus to the* unit in distress hotwell oer DOP 1600-2 (Torus Water Level Control).

DOP 1600-2 does. not contain a section or other direction to :.accomplish the required actio The procedure had been revised to be a sta~d alone procedure (no longer references DOP 1600-2).

This item is close (2)

Step 2.a.(3)(a) and (b) should be reverse Presently the control room valves are op~ned first and then the remotely operated valve The procedure had been revised to correct this proble This item is close (3)

Step 3.b.{7) the CRO cooling water flow is not numbered in Unit This had been numbered in the control room as part of the upgrad This item is close {4)

Step 3.d.{8) requires the comparison of Pump A and B discharge header pressures at the local conirol st~tion, and throttle the

lower pressure pump until the pumps are at approximately the same pressur These gages are widely separated and cannot be used in the required manne The procedure had been change The CRO pumps were ~urrentiy balanced using the pump amperage indicators in the control roo This item is close (5)

Ste~ 9.b.(12){b) the breaker for MO 205-2-4 is labeled inc6rrectly on the breaker (now r~ads MO 205-24).

This problem had been corrected for both uni ts with.new label However,

. the old blue label on Unit 3 had not* been remove This item is close OEOP 500-4, Containment Venting (1)

In procedure Step A.I, the licensee should change Step 2.a to 2 and change Step C.l to D.1~

In procedure Step A.2, change Step 8 to SA or 88 and*change Step C.2 to In Procedure Step B.2, change Step C.1 to 0.1 and cnange C.2 to In all cases, the wrong step numbers wer~ noted to be used in Procedure 500- Entry and exit conditions had been eliminated in the revised procedure This comment.is no longer applicabl This it~m is close (2). Step 0.1.a.(6) instructs the operator to reset the drywell isolatio The step should instruct the operator to place the switch in both the left and right positions, to agree with instructions given in Step D.2.c(l).

This step had been

eliminated in the latest revision of the procedure.. This item is close~.

(3)

Step D.l.b(3) tells the operator to monitor Standby Gas Treatment (SBGT) area radiation monitors. The SBGT area radiation monitor is d~splayed only on Unit 3, and is not identified with a maroon colored DEOP label. The label fo this radiation monitor currently had a DEOP designatio This item is close *

(4)

Step 0.2.b instructs operators to 'verify SBGT is operatin The step implies SBGT is already in servic Instructions for starting SBGT should be added to the ste Starting of the

• SGTS only required the turning of a switch in the control roo Therefore, specific instructions were not require This item is close (5)

Steps D.2.c(l) and (2) in'struct operators to reset the drywell isolation.. A review of the electrical schematic diagrams indicates the drywell isolation reset is not required to open the 2 11 vent relief valve The procedure had been revised to correct this ~rror. This item is close (6)

Step D.2.e provides directions to instal 1 j~~~e~s utili:i~~

open ended connections that require additional nut The use

• of alligator clips would allow jumpers to be installed quicker and easier, but is not administratively allowed at Dresde Dresden prdcedures still did hot permit the use of alligator clip Therefore this recommendations was not applicabl This item is close *

(7)

Step D.2.g(S) incorrectly underlines the word CLOS The procedure had been revised.to correct this erro This item is closed.

(8)

Valves used the performance of.DEOP 500-4 were inspected in the field. Some valves were not clearly identifie Additionally, most valves are located in high radiation or contaminated area This could hinder operator actions if portable air or nitrogen bcittles were required to be connected to certain valves on loss of nor.mal air supplie All safety related valves had been retagged as a result of a station wide effor *Work was also currently in progress to retag balance of plant (BOP) valve This effort was to be completed in 199 When this retagging is completed, all concerns related to valves not being clearly or properly identified should be eliminate This item is cl~se DEOP Equipment Stor~ge Cabinets (1)

The content~ of the two equipment storag~ cabinets are inspecte The cabinet located in the control room contained:

two sound po~ered headphones; miscellaneous jumpers of different lengths; tools to install jumpers, lift leads or p~ll.fuses; insulated gloves; and fire hose.fittings.to connect fire protection water to the feed pump suctio (alternate wate~ injection).

(2)

The cabinet l~cated in the Turbine Building contained:

several sound powered headphones; hoses for alternate SLC injection (DEOP 500-1) and venting the over piston area of CRD's (DEOP 100, Step 6E); tools for connecting the hoses and venting the over piston ar~a; hose fittings; and copies of Procedure 500~ *

The contents of the cabinets are supposed to be inspected on a quarterly basis, per Procedure DOS-10-15, which is currently in the draft proces The licensee had stated that Procedure DOS-10-15 was still in draft and had therefore not been issue To assure this equipment remains available in the specified equipment cabinets, these two items will remain open until this procedure is complete This item is ope DOP 1600-2, Torus Water Level Control Procedure, A Reference Procedure In DEOP-200 (1)

(2)

(3)

In Step F.2.c.(1) the procedure specified Torus Transfer Isolation Valve~ are labeled Tcr~s/Hotwell Isolation Valve on the Panel (2(3)-1599-61 and -62).

In Step F.2.h. the procedure calls for hotwell water level to be read on LI 1602-3 on Panel 902(3)- The specified indicator is actually ~he torus level indicato The proper indicator is 2-3340-06*on Panel 902(3)- In Step F.3.c., the HPCI Flow Bypass Valve M0-2301-14 is actually labeled Minimum Flow Valve on the panel and is not a throttle valve as the procedure indicate (4)

In Attachment A to this procedure, the vertical axis is not labeled other than at the top with 11 PSIG.

The vertical axis should be labele Torus/Drywell Differential Pressure, PSID.

Reference to this procedure was eliminated in the* December 1989 revision to DEOP 20 Therefore these concerns are no longer applicabl These items are close DOA 250-1, Relief Valve F~ilure (A Referenced Procedure in DEOP 200)

In Step 0.2.d. the Motor Suction Pump is actua1ly labeled Turbine Main Shaft Suction Pump on the pane This.procedure was no longer utilize This item is close Based on the above findings, all but four open items in inspection report 50-237/88012; 50-249/88014 are close Simulator Scenarios (Section 6 of fhe Original Inspection Report)

In the original inspection report, several specific concerns were identified as a result of the simulator scenarios performe One was related to the need to either revise a procedural step in DEOP 400-1* "Fuel Restoration" to state the requirement to depressurize after the level d~creases to -143 inches or to provide additional training on this specific ste The inspectors verified that the procedure has been. revised to more explicitly require depressurization when the lev~l decreased to -143 inche The other item was related to whether the flow chart DEOPs were useable in the control roo The licensee had stated that a flip-up panel was to be installed behind the CRT display console

.:,

(,lo of each unit so the operators would have a place to spread out the DEOPs so they were usable. *since this panel was not yet installed, the inspectors could not determine the useability of the DEOPs in the control room.. The December 1989 DEOP revisions, which utilize Revision 4 to the Owners Group EOPs, were much easier to follow than the previous versions and were more self contained (require less flipping back and forth between flow charts and procedures).

On this basis; it is the inspector's opinion that once this flip panel is installed, the operators should not have difficulty using these flow charts (assuming this panel is large eno~gh).

Human Factors Analysis (Section 7 of the Original Inspection Report)

In the original inspection report human factors concerns were identified in the following areas:

decision steps/logic statements; cautions and.notes, transitions, overall consistency; writer's guide; graphics; control room; and concerns related to the DEOP 500 Series procedure Detailed concerns were identified in Attachment C to the original inspection repor The inspectors did not specifically address human factors concerns during the follow-up inspectio However, based on the limited review of the December 1989 revision to the flow charts, it is the inspectors opinion that significant i~provements had been made in all the areas of concern identified in the human factors revie Some specific examples of improvements observed were:

the elimination of notes in the flow charts and the incorporation of caution statements close to the applicable step; transitions within and between flow charts and procedures had been reduced, use of non-DEOPs had been reduced or eliminated; overall consistency of flow charts had improved; the graphics quality had greatly improved as well as the readability, curves and tables were included on the flow charts and located as close as possible to the applicable step, and typographical errors had been correcte The control room had been completely remodeled since the original inspectio These modifications, many of which were the result of extensive DCRDR human factors concerns, had corrected many of the problems identified in the original EOP revie The revised flow charts should also make them easier to use in the control room and the flip-up panel to be installed by the licensee, if adequate in size, should eliminate the concern regarding the ability to effectively use the. flow charts in the control room; the DEOP 500 series had been completely rewritten since that original inspection and most of the concern5 identified had been correcte Verification and Validation (Section 8 of the Original Inspection Report The inspectors reviewed the verification and validation programs utilized by the licensee during the approval process of the.December 1989 revision to the DEOP The program in place was very comprehensive and the checklists used appeared to be sufficiently detailed to ensure that the procedures were consistent with the writer's guid The inspectors also compared DEOP 200-1, Primary Containment Control and DEOP 100, Reactor Control, with the PSTGs which was based on

• • Revision 4 of the 8WR Owners Group EPG Although for the most part, the DEOPs tracked the PSTG, inconsistencies were identifie Information in the PSTG was sometimes relocated to other DEOPs and information was sometimes added to the DEOPs for clarification that was not specified in the PST~. Although the licensee believed that the flow charts could be reconstructed by. a person experienced in working ~ith EOPs, it is the inspectors opinion that the licensee should develop a bases document that clearly provides the justification for differences between the PSTG and the flow chart Although the DEOP coordinator was very knowledgeable regarding the revisions that have been made to the flow charts since the original inspection, this corporate knowledge will be lost once he either changei positions or leav~s the compan The inspectofs therefore recommend that for all the programmatic changes to the DEOPs, (including deviations from the PTSG) the licensee should develop and maintain documented justification in auditable for EOP Open Items The open it~ms identified in inspection r~port 237/88012; 24~/88014 items 4.a.(1), 4.a.(2), 4.a.(3), 4.b and 5 and Attachment 8 have.all been addressed in this report and all but four items have been close The remaining open items are identified below:

(1) Attachment 8, DEOP 200 Series, Item 3:

Correction of problem related to legibility of the scale on strip chart of medium drywell pressure strip chart indicato (Open Item 50-237/90009-02(DRP)).

{2) Attachment 8, DEOP 500-1, Item 3:

Identification of the location of the proper sources of service wate (Open Item 50-237/90009-03(DRP)).

(3).Attachment 8, DEOP 500-2, Item 6:

Proper use of the words

"to" or "and" related to the 4 kv bus breaker (Open Item 50-237/90009-04(DRP)).

(4) Attachment 8, DEOP Equipment Storage Cabinets:

Verify that procedure 005-10-15, when completed, is implemente (Open Item 50-237/90009-05(DRP)).

.

No violations or deviations were identified in this are.

Report Review During the ins~ection period, the inspectors reviewed the licensee's Monthly Operating Report for Januar The inspectors confirmed that the information provided met the requirements of Technical Specification 6.6.A;3 and Regulatory Guide 1.1 "'

--.....

• l'l

..

While reviewing effluent report which indicated been licensed.

the Dresden July through December 1989 radioactive dated February 28, 1990, the inspectors noted a statement utilization of a release path for which Dresden had not This statement read as follows:

. "In the one case where effluent monitoring equipment is not used, i.e.; the burning of contaminated oil in the heating boilers, administrative controls are imposed to limit concentration in the heating boiler to less than 10 CFR Pa~t 20 Appendix 8, Table II, Column 1 and the contribution to overall dose to less than percent of the total station annual release."

Howeve~, the lice~see*was not licensed to treat or dispose of licensed material by incineration (burning of contaminated oil in the heating boilers) in accordance with 10 CFR 20.30 The inspectors independently verified that the burning of contaminated oil in the heating boilers was not a current practice at Dresden and that the effluent report was in erro The.licensee indicated that future issues of this report would be accordingly correcte *

The inspectors also reviewed the Secondary Containment Leak Rate Test Report dated February 26, 1990. which covered testing performed on November 26, 198 The inspectors verified that this report met the requirements of Technical Specification 6.6.C.3 for that tes No violations or deviations were identified in this are.

Open Items Open items are matters which have been discussed with the licensee *Which will be further reviewed by the inspector and which involved some actions on the part of the NRC or litensee or bot Four open items disclosed during the inspection are discussed in paragraph.

Exit Interview (30703)

The inspectors met with licensee representatives (denoted in Paragraph 1)

on April 2, 1990, and informally throughout the inspection period, and summarized the scope and findings of the inspection activitie The inspectors also met with the licensee's DEOP coordinator on March 14, 1990 and summarized the scope and findings of the EDP portion of the inspectio The inspectors also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspector during the inspectio The licensee did not identify any such documents/processes as proprietar The licensee acknowledged the findings of the inspectio