IR 05000331/1993023

Insp Rept 50-331/93-23 on 931126-940106.No Violations Noted. Major Areas Inspected:Ler Followup,Followup of Events, Operational Safety,Maint,Surveillance & Rept Review

ML20059H285
Person / Time
Site:	Duane Arnold
Issue date:	01/11/1994
From:	Lanksbury R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20059H283	List: IR 05000331/1993023 ML20059H280
References
50-331-93-23, NUDOCS 9401270071
Download: ML20059H285 (14)

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l U. S. NUCLEAR REGULATORY COMMISSION REGION 111 - Report No. 50-331/93023(DRP)

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Docket No. 50-331 License No. DPR-49-Licensee: IES Utilities Incorporated j IE Towers, P. O. Box 351 Cedar Rapids, IA 52406 ,

facility Name: Duane Arnold Energy Center Inspection At: Palo, Iowa ,

Inspection Conducted: November 24, 1993, through January 6, 1994'

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Inspectors: J. Ilopkins C. Miller b

Approved: ([ t /11 T1

R. D. Lankhbury,(Thief _

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Date Reactor Projects Section 3B

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Inspection Summary

,7 Jnsoection on November 24. 1993. throuch January 4. 1994 (Report No. 50-331/93023(DRP))

Areas Inspected: Routine, unannounced inspection by the resident inspectors of followup, licensee event report followup, followup of events, operational safety, maintenance, surveillance, and report revie ,

Results: An executive summary follows:  ;

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EXECUTIVE SUMMARY i

Plant Operations The plant operated up to full power during the period with minor down power !

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operations due to surveillance testing. Management involvement was evident in the systematic approach to identify the source of the leak into the reactor building closed cooling water system. An unresolved ' item for inadequate security of a requalification examination under development was identified (Section 8). .;

i Maintenance 1 Strong management and engineering involvement was evident in all phases of the troubleshooting, planning, and replacement of relay C71A-K48. The "C" residual heat removal pump failed to meet' technical specification required discharge pressur Parts and procedures needed to rebuild the pump were not '

in place. ' An inspection followup item was identified concerning the availability of data to determine operability of technical specification required instrumentation (Section 7.b)

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A non-cited violation was issued for inadequate acceptance criteria for a l motor operated valve maintenance procedure' (Section 6).

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Plant Support '!

Iowa Electric Light and Power Company announced their merger with lowa 3 Southern Utilities Company of Centerville,' Iowa, and the formation of a new utility, IES Utilities Incorporated. The merger was effective on January 1, 1994. The current management and organization of the Duane Arnold Energy ,

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Center were not affected by the merger. -Housekeeping, cleanliness, and radiological control practices continued to improve during the operating  ;

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DETAILS -)

1. Persons Contacted J. Franz, Vice President Nuclear i

• D. Wilson, Plant Superintendent, Nuclear

• R. Anderson, Operations Supervisor ,

• P. Bessette, Supervisor, Regulatory Communications ,

J. Bjorseth, Maintenance Superintendent

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• J. Kinsey, Licensing Supervisor ,

• J. Kozman, Supervisor, Configuration Control Engineering i

• M. McDermott, Manager, Engineering

• B. Murrell, Specialist, Regulatory Communications  ;

• C. Nelson, Group Leader, E/I&C Programs  !

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• K. Peveler, Manager, Corporate Quality Assurance

• D. Robinson, Licensing Specialist, Regulatory Communications !

J. Thorsteinson, Assistant Plant Superintendent, Operations Support G. Van Middlesworth, Assistant Plant Superintendent, Operations and i

Maintenance

• Whittier, Systems Engineer

• K. Young,_ Manager, Nuclear Licensing In addition, the inspectors interviewed other licensee personnel including operations shift supervisors, control room operators, engineering personnel, and contractor personnel (representing the licensee).

• Denotes those present at the exit interview on January 4,~199 . Followup (92701) ,

(Closed) Open Item 331/91013-01(DRS): Two dewcells used during the ,

refueling outage (RFO) 10 integrated leak rate test exceeded the dewcell element temperature conversion formula values (129 to 169 degrees l Fahrenheit ( F)) used by the leak rate test data acquisition compute :

Dewcell number 20's temperature was 172.8 F and dewcell number 25's was .

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170.4 F. The licensee developed a new dewcell conversion formula (128 F-to 180 F) and analyzed the data received from the two dewcell The calculated differences were small and in a direction showing less leakag The differences did not affect the RF010 leak rate test results. The RF012 leak rate test conducted in 1993 was completed satisfactorily and no problems were identified with the dewcells used ;

during the test. This item is considered close i

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No violations or deviations were identified in this are . Licensee Event Report Followuo (92700) (90712) ,

Through direct observations, discussions with licensee personnel, and review of records, the following event report was reviewed to determine i that reportability requirements were fulfilled, immediate corrective

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actions were accomplished, and corrective actions to prevent recurrence :

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had been accomplished in accordance with technical specification (Closed) Licensee Event Report (LER)93-010 (331/93010-LL): Reactor Scram Due to Grounded Turbine Solenoid Valv This LER documented a reactor scram due to the combination of turbine control valve fast closure and average power range monitor (APRM) high flux signals. A ,

connector which supplied power to the fast acting solenoid valve (FASV)

for the number three turbine control valve (TCV-3) had an unknown, pre-existing ground. Technicians inadvertently grounded a cooling fan in -

the electro-hydraulic control (EHC) cabinet in the control room during -

maintenanc Since the EHC system employed a floating neutral power distribution system, the two grounds together completed the electrical circuit and momentarily energized the FAS This caused TCV-3 to partially close and a half scram signal was developed. The partial closure of TCV-3 caused a reactor pressure spike which in turn caused an APRM high flux signal and another half scram signal. The two half scram signals completed the full scram logic. All engineered safety features functioned as designe The licensee repaired the grounded connector on TCV-3 and verified that there were no other grounds on the other FASVs and test solenoid circuits for the remaining TCVs, stop valves, and combined intermediate i valves. The root cause for the pre-existing ground on TCV-3 was indeterminate. An engineering evaluation determined that the installation of a ground fault detection system within these turbine valve control circuits would not have been appropriate. Additionally, a review of plant history had not revealed any previous examples of plant transients due to " hidden" ground faults. This LER is close No violations or deviations were identified in this are . Lollowuo of Events (93702)

During the inspection period, the licensee experienced several events, some of which required prompt notification of the NRC pursuant to 10 CFR 50.72. The inspectors pursued the events onsite with licensee and/or other NRC officials. In each case, the inspectors verified that the notification was correct and timely, if appropriate, that the licensee was taking prompt and appropriate actions, that activities were conducted within regulatory requirements, and that corrective actions would prevent future recurrence. The specific events are as follows:

November 29, 1993 - Group III Primary Containment Isolation System (PCIS) Isolation During Surveillanc (See Section 8.a for details.)

December 15, 1993 - "C" Residual Heat Removal Pump Failed Surveillanc (See Section 8.c for details.) ,

No violations or deviations were identified in this area.

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. - Doerational Safety Verification (71707) (71710)

The inspectors observed control room operations, reviewed applicable logs, and conducted discussions with control room operators during the inspection. The inspectors verified the operability of selected emergency systems, reviewed tagout records, and verified proper return to service of affected components. Tours of the reactor. building and turbine building 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 maintenance. It was observed that the Plant Superintendent, Assistant Plant Superintendent of Operations, and the Operations Supervisor were well-informed of the overall status of the plant and that they made frequent visits to the control room. The inspectors, by observation and direct interview, verified that the physical security plan was being implemented in accordance with the station security pla The inspectors observed plant housekeeping and cleanliness conditions and verified implementation of radiation protection control Housekeeping, cleanliness, and radiological control practices, which were identified as minor concerns during the refueling outage (August -

October 1993), continued to improve during the current operating cycl Licensee management continued to stress the expected level of performance in these area These reviews and observations were conducted to verify that facility operations were in conformance with the requirements established under technical specifications, Title 10 of the Code'of federal Regulations, and administrative procedure Leak into Reactor Buildina Closed Coolina Water (RBCfW) System On December 18, 1993, with the reactor at approximately 100~ percent power, plant operators determined that the level in the RBCCW surge tank was slowly increasing. Initially, the leak rate into the RBCCW surge tank was approximately 10 gallons-per-day. The RBCCW system provided cooling water for reactor building equipment which had the potential to contain radioactive fluids. Chemistry samples from the RBCCW system identified slightly increased levels of activity from Cobalt-60, Iodine-

'131, Iodine-133, and Sodium (Na) 24 . (It should be noted that the RBCCW system was already contaminated due to a leak several years ago.)

The licensee increased the frequency of monitoring of the surge tank level from once to twice each shift and the frequency of chemistry sampling of RBCCW and general service water (GSW) (which cools the RBCCW system) from weekly to daily, There was no indication of_a leak from the RBCCW system into the GSW system. Additionally, the components cooled by RBCCW were systematically isolated to determine the source of the leak. " Shift orders," which detailed the required actions if the RBCCW leak rate increased, were given to the control room operating crew ;

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Based on the chemistry samples and isolation of individual components j cooled by RBCCW, the licensee determined that the most probable sources of the leak were either the reactor water cleanup (RWCU) non-regenerative heat exchangers or one of the reactor recirculation pumps' !

seal heat exchangers. A review of the chernistry sample history for !

RBCCW determined that there was a small Na .'4 " spike" after the reactor scram on October 15, 1993, which slowly trended down to less than '

detectable levels. No increase in RBCCW surge tank level was observed at that time. An increase in Na-24 was identified on December 14 when RWCU was isolated to support maintenance activities. As stated above, the increase in RBCCW surge tank level was identified on December 1 Trends of the RBCCW surge tank level and chemistry samples indicated that the leak had apparently stopped at the end of the report perio The licensee planned to continue the increased sample frequency of the RBCCW system and to record surge tank level once each shift. The licensee planned to continue normal plant operations and develop long term plans to isolate and repair the lea Management involvement was evident in the systematic approach to ;

attempting to identify the source of the leak. The inspectors will continue to monitor the RBCCW leak and the licensee's efforts to identify and repair the lea ,

No violations or deviations were identified in this are Monthly Maintenance Observation (62703)

Station maintenance activities of safety-related systems and components '

listed below were observed and/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 specifications (TS).

The following items were considered during this review: the limiting conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating 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 records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and fire prevention controls i were implemente Work requests were reviewed to determine status of outstanding jobs and to assure that priority was assigned to safety-related equipment maintenance which might affect system performanc l

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l Portions of the following maintenance activities were observed and/or reviewed: -l l

- Fire pump 1P-48 auto-start pressure switch calibratio ;

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"C" residual heat removal pump troubleshooting and repai (See Section 7.c for details). 1

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"B" residual heat removal service water pump replacemen Reactor core isolation cooling (RCIC) system minimum flow isolation ,

valve testin {

c RCIC System Minimum Flow Isolation Valve Testin ;

On December 16, 1993, the RCIC system was declared inoperable due to ,

concerns raised during the reevaluation of the valve operation test and ;

evaluation system (V0TES) test data for the RCIC minimum flow isolation valve, M0-2510. The concern was that the "as found" torque switch -

setting could have prevented the motor operator from developing the ,

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minimum required closing thrust. A detailed engineering evaluation, which removed some of the conservative assumptions in the minimum thrust '

requirements, determined that the "as found" torque switch setting would have allowed the motor operator to develop the minimum required closing thrust, and that the RCIC system had always been operable. The inspectors and Region III motor operated valve (MOV) specialists reviewed the licensee's calculations and had no additional question On December 16 the torque switch setting was raised from 1.00 to 1.25 in order to put the closing thrust value in the middle of the acceptable range; and valve M0-2510 was satisfactorily reteste During the MOV team inspection in December 1993 (see inspection report 50-331/93019), the inspectors identified a concern that MOVs with marginally acceptable thrust values were being returned to service without a detailed engineering evaluation to determine operability of the valves. A non-cited violation was identified for inadequate acceptance criteria. Based on the MOV inspectors' concerns, the licensee developed a list of marginally acceptable valves, and was in the process of performing engineering evaluations on the valves. One of the valves being evaluated was MO-2510. During the evaluation, the licensee determined that incorrect V0TES system inaccuracy was used to develop the acceptance criteria when valve M0-2510 was VOTES tested on September 14, 1993. . As stated above, the December 16, 1993, evaluation determined that the "as found" torque switch setting would have allowed the motor operator to develop the minimum rcquired closing thrus Failure to provide adequate acceptance criteria for the VOTES test of valve M0-2510 on September 14, 1993, was a violation of 10 CFR Part 50, Appendix B, Criteria XI. This violation was not cited because'the licensee's efforts in identifying and correcting the violation met the criteria specified in Section VII.B of the " General Statement of Policy and Procedure for NRC Enforcement Actions" (Enforcement Policy, 10 CFR Part 2, Appendix C).

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In addition to performing a detailed engineering evaluation of marginally acceptable valves, the MOV program was revised to require an engineering evaluation of the VOTES data prior to declaring a valve t operable. The inspectors and Region III MOV specialists will continue to review and evaluate the licensee's corrective actions for weaknesse in the MOV progra One non-cited violation was identified in this area. No deviations were identifie h 7. Monthly Surveillance Observation (61726)

The inspectors observed technical specification (TS) required surveil-lance testing and verified that testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, that limiting conditions for operation were met, that removal and restoration of the affected components were accomplished, that test results conformed with TS and procedure requirements and were reviewed by personnel other than the individual directing the test, and that any deficiencies identified during the testing were properly reviewed and '

resolved by appropriate management personne The inspectors witnessed portions of the following test activities:

STP-41A002-Q - Quarterly Calibration and Functional Check of Drywell Pressure Switche STP-42A003-Q - Main Steam Line Low Pressure Instrument Channel l Functional Test and Calibratio STP-45A002-Q - Low Pressure Coolant Injection (LPCI) System Quarterly Operability Tests, Calibration of Drywell Pressure Switches - STP-41A002-0 ,

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On November 29, 1993, with the reactor at approximately 100 percent power, an unexpected half Group III PCIS isolation and ,

startup of the "A" standby gas treatment (SBGT) system occurred during the performance of surveillance test procedure (STP)

41A002-Q, " Quarterly Calibration and Functional Check of Drywell Pressure Switches." All components operated as designed, and the STP was stopped to begin troubleshooting. Initial troubleshooting ,

determined that one set of closed contacts on relay C71A-K4B, that

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were electrically in parallel with other closed contacts on the :

relay being tested (C71A-K4A), had high resistance. The half Group Ill isolation signal was reset, and the affected PCIS components and SBGT system were restored to their original lineu On December 14, with the reactor at approximately 85 percent power, relay C71A-K4B was replaced and STP 41A002-Q was completed satisfactorily. The licensee planned to have a detailed examination of the contacts on relay C71A-K4B performed to l determine the root cause of the high resistanc !

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During the initial troubleshooting on November 29, high resistance across the closed contacts on relay C71A-K4B was identifie Relay C71A-K4B was not cycled or de-energized during the ,

troubleshooting efforts in order to preserve the "as found" condition of the closed contacts. The initial evaluation -

concluded that oxidation on the closed contacts was responsible :

for the high resistanc !

Strong management and engineering involvement was evident in all i phases of the troubleshooting, planning, and replacement of relay C71A-K4B. The inspectors will continue to follow the licensee's efforts to determine the root cause of the high resistanc Main Steam Line Pressure Skitches On December 15, 1993, the licensee performed STP-42A003-Q, " Main Steam Line Low Pressure Instrument Channel Functional Test and Calibration," in conjunction with replacing main steam line low pressure switches PS-1014, PS-1015, PS-1016, and PS-101 Each pressure switch was checked for its as-found setpoint and then replaced with the new pressure switch, prior to moving on to the next switch. The Barksdale pressure switches were being replaced '

with temperature compensated models in order to reduce instrument '

drift caused by ambient temperature variations. The STP served to check the function and calibration of the pressure switches to shut all of the main steam isolation valves 'at the TS trip setpoint of 850 psig. That was the same value as the limiting safety system setting (LSSS) described in the T By 2:00 a.m. (CST) on December 16, subsequent to the replacement-of all four pressure switches, the licensee determined that all of

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the "as found" trip setpoints were below the acceptable minimum-

"as-found" STP values by approximately 12 psig. On December 16 at 2:30 p.m., the inspector questioned if the failure of the' four ,

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pressure switches was reportable under 10 CFR 50.72. On December 17, the licensee determined that all four-pressure switches would have been capable of performing their design function, although two were within 3 psig of not being able to do l so had they drifted lower. This evaluation was performed far in excess of the 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> allowed by 10'CFR 50.72 had the two switches been incapable of performing their design functio The inspectors also questioned the reportability of this issue under 10 CFR 50.73 and whether the pressure switches could be considered operable if: (1) they tripped at a value below the TS LSSS setpoint; and (2) they tripped at a value below the minimum STP "as-found" value, since the STP was used to determine instrument operability. The licensee subsequently determined that all four switches were operable in accordance with TS and were not reportable under 10- CFR 50.73. The bases for that determination were: (1) each pressure switch had been replaced by a new switch that was calibrated to the required TS value within the allowable

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outage _ time; and (2) none of the "as-found" values were below the

" allowable value" which would have rendered the switcFas i inoperable. The LSSS trip set point in TS was the minimum "as-left" value, and the acceptable "as-found" range in the STP was based on the instrument tolerance and-trending program. The

" allowable value" was developed with adequate margin to ensure the TS safety limit was never exceeded. As long as the "as-found" value was above the " allowable'value" and the "as-left" value was above the TS trip setpoint, the instrument was considered operable. Management from Region III and the Office of Nuclear Reactor Regulation initially determined that the licensee's use of

" allowable values" to determine the operability of an instrument l was acceptable even though not described in the licensee's TS or

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surveillance procedures. The licensee had been in the process of developing and documenting the " allowable values" for the instruments in TS in order to support a TS amendment change. The licensee planned to submit the TS amendment change in late 1995 or early 1996.

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evaluate the past operability of the four pressure switches for reportability under 10 CFR 50.72 were slow. The licensee stated that the deviation report (DR) process, which provided engineering support to evaluate operability and reportability, had been started, as required by plant administrative procedures, after the

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first pressure switch had failed the STP. However, since'all four

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l of the pressure switches were being replaced over a 2 day period, I the DR was not forwarded for evaluation until all four were l- completed. The inspectors will continue to evaluate the DR process and the licensee's sensitivity to past operability determinations.

i The inspectors were also concerned that the operations shift supervisors (OSSs) were unaware of the minimum acceptable trip setpoint values for operability purposes. The licensee's present program of using an analytical " allowable value" for. operability determinations, rather than the TS LSSS value or surveillance test acceptable "as-found" value range, leaves the OSS without the benefit of an acceptable value range for instrument operabilit In many cases the analytical value had not yet been calculate Thus there was no clear TS value for operability for OSS guidanc The inspectors were also concerned with the acceptability of the calibration program tor Barksdale pressure switches since all four pressure switches drifted about 35 psig low (non-conservative) at the same time in one quarterly surveillance period. These concerns will be tracked as inspection' followup item (IFI)

331/93023-01(DRP), "C" Residual Heat Removal (RHR) Pumo Failed Surveillance On December 15, 1993, during the performance of STP 45A002-Q,

"LPCI System Quarterly Operability Tests," the "C" RHR pump failed

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to meet the TS required discharge pressure of 165 psig at 4800 gallons-per-minute (gpm) flow rate. The actual discharge pressure ,

was 163 psig. The plant entered a 30 day limiting condition for- !

operation (LCO). The pump had developed 169 psig at 4800 gpm during the previous quarterly test on September 11, 1993. The STP !

was successfully completed on the other three RHR pumps by-December 1 The licensee verified the test equipment instrument accuracy and that the LPCI system valve lineup was correct. Additionally, individual system components, including check valves, were *

evaluated to determine if they were the source of the pump's degraded performance. The licensee proceeded in parallel paths to evaluate current pump performance against surveillance history and STP acceptance criteria, and to prepare to overhaul the pump and motor, if require The pump overhaul procedure had to be ;

updated, and a concern with the acceptability of parts had to be resolved. A pump vendor representative (Byron Jackson) and a contract pump specialist from MPR Associates, Incorporated, were brought onsite to assist the engineering department in the evaluation of the pump performance. On December 21, the licensee decided not to disassemble the pump, if needed, until the all of the parts were availabl Based on the trending data of the pump's discharge pressure and '

vibration, the vendor representative, the MPR specialists, and the licensee concluded that the degradation of. performance was relatively minor and a pump overhaul was not required. A review -

of maintenance history determined that none of t' ' RHR pumps had ever been rebuilt. Pump performance was still aoove the action required range in accordance with American Society of Mechanical Engineers (ASME)Section XI. The historical performance of the other three RHR pumps was-reviewed and was not significantly >

different from the "C" RHR pum On December 18, 1993, a leak from the. mechanical seal of the "C" RHR pump of approximately 1 pint-per minut.e was identified during the troubleshooting for the low discharge pressure. The isolation valves for the pump were shut to minimize draining from the suppression pool. On December 20 the pump was unisolated to support additional troubleshooting, and a reduction in the seal ;

leakage was observed. The vendor representative, MPR specialists,

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and_ licensee agreed that the pump seal leak was not the cause of the degraded pump performanc The licensee reviewed the bases for the STP acceptance criteria and on December 30, 1993, concluded that there was adequate margin to justify an interim value of 160 psig. Specialists from Region III were reviewing the adequacy of the licensee's evaluation to reduce the acceptance criteria setpoin i

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On January 3,1994, the "C" RHR pump was isolated to replace the ;

t seal. During the seal replacement, the licensee detcrmined that the pump impeller was not axially centered in the pump cas !

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After discussions with the pump vendor, the impeller was axially centered. The root causes for the impeller not being centered and t the seal failure were being evaluated at the end of the report i period. The licensee was also evaluating the axial position of i the impeller on the other three RHR pumps and the two core spray pumps. On January 6, the seal replacement and impeller i maintenance were completed, and the post-maintenance STP was l i

performed. The "C" RHR pump failed the STP with a pump discharge pressure of 156 psig at 4800 gpm. Maintenance activities to .

troubleshoot and rebuild the pump were starte j The "C" RHR pump had a history of operating close to the STP limit. As demonstrated by this event, a minor degradation in performance had made the pump inoperable. The inspectors noted that parts and procedures needed to rebuild the pump were not in ,

place when the event occurred. The inspectors were concerned that parts and procedures for other pumps operating close to the acceptance limits may not be available. The licensee was in the i

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process of reviewing the trending data and the availability of repair parts and procedures for other pumps. The inspectors will continue to follow the licensee's repair activities and review of the availability of parts and procedures for other pump t t

No violations or deviations were identified in this area. One inspection followup item was identifie . Reoualification Examination Security

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Operator Licensing Examiner Standards, NUREG 1021, provided guidance for NRC administered requalification examination development, including examination security guidance. Examination Standard (ES) 602, Section ;

C.I.c stated, "If the facility licensee submits a proposed l'

(requalification) examination, those individuals involved in its development become subject to the security restrictions of ES-601 once !

examination development commences. These restrictions remain in effect :

until the NRC examination is given." Section C.4.b of ES-601 '

specifically stated "those individuals with knowledge of the examination content shall not participate in any facility requalification training programs (e.g., instruction, examination, or tutoring) involving the- '

licensees selected for the examination."

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The licensee began examination development on August 10, 199 Licensee training representatives delivered the facility developed  :

requalification examination to the NRC on October 21, 1993. The signed :

security agreement provided at that time was signed by three l individuals, two signed on October 19, 1993, and one on October 21, 199 The developer of the examination and his supervisor were asked if :

they had given any instruction to the proposed examination candidates i between the time development of the examination had begun and the date- l

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the security agreement was signe Both answered "yes". The developer had instructed in the areas of Curves and Limits and Emergency Operating Procedure (E0P) C, "EOP Flowchart Support Procedures."  :

All sections of the examination provided for review to the NRC were modified. Three simulator scenarios were deleted and replaced with one simulator scenario written by the NRC to prevent a potential compromise of the examination. The NRC replaced one additional job performance measur ;

Additional investigation revealed that the licensee did not have an examination security procedure in place that would prevent compromising ;

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the integrity of examinations under development. The lack of a procedure to prevent compromising the security of an examination under ,

development was considered an unresolved item (331/93023-02(DRS)).

i No violations or deviations were identified in this are One unresolved item was identifie . Report Review (90713)

During the inspection period, the inspectors reviewed the licensee's ,

monthly operating reports for November and December 1993. The ,

inspectors confirmed that the information provided met the requirements of TS 6.11.1.C and Regulatory Guide 1.1 No violations or deviations were identified in this are . Inspection Followup Items Inspection followup items are matters which have been discussed with the licensee, which will be reviewed further by the inspectors, and which ,

involve some action on the part of the NRC or licensee, or both. An Inspection followup Item disclosed during the inspection is discussed-in Section ,

11. Unresolved items  :

Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations or deviations. Unresolved items disclosed during the inspection were discussed in Section . Violations For Which A " Notice of Violation" Will Not Be Issued The NRC uses the Notice of Violation to formally document the failure to ;

meet a legally binding requirement. However, because the NRC wants to '

encourage and support license initiatives for self-identification and correction of problems, the NRC will not issue a Notice of Violation if the criteria set forth in Section VII.B of the " General Statement of Policy and Procedure for NRC Enforcement Actions," (Enforcement Policy, 10 CFR Part 2, Appendix C) are met. Violations of regulatory 1

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.1 requirements identified during the inspection for which a Notice of i Violation will not be issued are discussed in Section "

13. Exit Interview (30703)

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The inspectors met with licensee representatives (denoted in Section 1) *

on January 4,1994, and informally throughout the inspection period and :

summarized the scope and findings of the inspection activities. The inspectors also discussed the likely information content of the ,

inspection report with regard to documents or processes reviewed by the !

inspectors. The licensee did not identify any such documents or  :

processes as proprietary. The licensee acknowledged the findings of the :

inspectio ;

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