IR 05000317/1986007

Partially Withheld Insp Repts 50-317/86-07 & 50-318/86-07 on 860304-0430 (Ref 10CFR2.790 & 73.21).Violation Noted:Lack of Calibr Due Dates on Instruments & Controls for post-maint Test Procedures

ML20211L317
Person / Time
Site:	Calvert Cliffs
Issue date:	06/05/1986
From:	Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20211L262	List: IR 05000317/1986007 ML20211L257 ML20211L281 ML20211L296
References
RTR-NUREG-0660, RTR-NUREG-660, TASK-1.C.1, TASK-2.B.1, TASK-TM 50-317-86-07, 50-317-86-7, 50-318-86-07, 50-318-86-7, NUDOCS 8607020053
Download: ML20211L317 (16)

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U. 5. NJCLEAR RESULATCRY l0Vv:55:CN Region I DC:ket/Recor;: 50-317/86-07 License: DPR-53 50-3'.3/56-07 DPR-69 L':ersee: Ea't'more Gas and Electri: C:::any Facility: Calver: C1fs N; lear Power Diant. Uni:s I anc 2 Inspection at: Lusby, Maryland Dates: March 4 - April 30, 1986 ,

Inspectors: T. Foley, Senior Resident Inspector D. C. Trimble, Resident Inspector Approved: O,e k C+14 , Soy Glsit4 L. E. Tripp, ief,' Reactor Projects Section 3A Date Summary: March 4-April 30, 1986: Inspection Recort 50-317/86-07,50-318/86-0 Areas Inspected: Extended inspection due to the routine nature of operation. In-spection consisted of routine observations defined by the I.E. Manual Chapter 2515 program and included inspection of the Control Room, acces:ible parts of plant stru:tures, olant ccerations. radiation protection, physical security, Emergency Preparecness Drill. ciant coeratirg -ecords, maintenance surveillance, TMI Action Pian Items, reocr:s ;c tre NRC, anc allegat'ons regarcing Healtn Physics controi Inspection hours totalled 24 Results: The most significant concern icentified during this period centers about the increasinc trend of steam leaks in the seconcary portion of Unit 1. The lic-ensee's program may not be being implemented with sufficient urgency as the problem-warrants. This presents significant personnel safety concerns and requires in-creased licensee em;nasi Four violations were identified, two of which appear to be of minor significanc Placing of calibration due dates on instruments has been a long-standing issue with the residend inspectors (Detail 7 and UNR 317/82-12-02). Problems with losing shutdown cooling require additional emphasis and may become more significant if not rectified (Detail 4.a). Controls for development.of post-maintenance test procedures to ensure that appropriate prerequisites and precautions are incorpor-ated and better reviews performed prior to imolementation of the procedures are 2

res e:. te:nri:'ans nee: er3.re : a :nly a:: a:e and reifab'e instrumtnts are usec f:r ce cnstration o# cperacility (Detail E). Security snoulc place lefs reliance on contractor sel' regulation (Detail 13). Allegations of inadecuate Health Physics controls appear to be substantiate PDR ADOCK 05000317 G PDR

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DETAILS

Persons Contacted Within this report perioc, interviews and discussions were conducted with various licensee personnel, including reactor operators, maintenance and surveillance technicians and the licensee's management staf . Summary of Facility Activities At the beginning of the period, both units were operating at full powe On March 13, an Emergency Response Drill for licensee personnel was conducte Unit 1 On March 17, Unit I was shut down to commence a five-day planned outage in order to repair a suspect reactor coolant pump seal, a leaky pressurizer re-lief valve and power operatea relief valves, and main steam line drain an salt water system leaks. The unit was returned to power on March 24, limited to 90% power until repairs to one circulating water pump were completed. The

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unit was returned tp full power on March 2 ;

On April 1, portionb of No. 11 moisture separator reheater (MSR) first stage level control line were encapsulated due to their being.below minimum wall thickness. On April 18, a rupture of No. 12 MSR drain tank normal level con-trol line occurred. On April 22, No. 11 MSR was taken out of service to en-hance the safety of those personnel repairing the No. 12 MSR control line rupture. On April 23, No. 11 MSR high level dump line to the condenser de-

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veloped a circumferential rupture and consecuent steam lea Unit 2

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On March 17, the unit experienced main turbine vibration problems and was brought to hot standby in order to balance the turbine. .The unit was returned te; power operations the same ca '

, Or, March 25, No. 23 MSR vent line developed a steam leak; repairs were com-

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pleted two days late . Licensee Action on Previously Identified Items (Closed) Inspector Follow Item (317/84-31-04). The licensee has identified the root cause of the Failures of the Main Steam Isolation Valves, and has performed repetitive satisfactory testing of.the MSIVs. This item is close (Closed) Violation (317/85-01-01). Accesses to High Radiation Areas in the overhead within the controlled areas have been routinely inspected. The lic-

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ensee has been maintaining adequate control over barricades and postings.

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(Closed) Inspector Follow Item (317/85-01-02). The licensee now posts areas within the Auxiliary Building to provide information on abnormally high radi-ation areas or radiation areas subject to change. This item is c1cse (Closed) Inspector Follow Item (317/85-02-03). A review of the licensee's controls for minimizing energized annunciators on the control board has been conducted. Energized annunciators are generally kept to a minimum. This item is close . _R_eview of Plant Operations Daily Inspection During routine facility tours, the following were checked: manning, ac-cess control, adherence to procedures and LCO's, instrumentation, recor-der traces, protective systems, control rod positions, containment tem-perature and pressure, control room annunciators, radiation monitors, radiation monitoring, emergency power source operability, control room logs, shift supervisor logs, tagout logs, and operating order Loss of Shutdown Cooling and Corrective Action On March 22, 1986, at 7:45 p.m., Unit I was in Mode 5 on shutdown cooling with Reactor Coolant System pressure at 210 psia and 149 degrees Fahren-heit temperature. Maintenance instrumentation technicians were perform-ing a post-maintenance test under maintenance order (MO) #206-084-679A to lift a recently installed electromatic relief valve (ERV 404). The MO reauired performance of Section V of STP-M-5728-1, Revision 7, " Pres-surizer Relief Valve Channel Calibration". As required by the test pro-cedure, technicians behind the control boards inserted a greater than 300 psia signal to pressure indicator / controller PIC 103-1 (EIIS PIC).

PIC-103-1, besides providing a signal to ERV 404 (EIIS RV 20) is also interlocked with motor operated valve (MOV) 652 (EIIS ISV 20) to protect the shutdown cooling system from overpressurization. The normal operat-ing pressures for shutdown cooling is 300 psig and the maximum operation pressure is 335 psig. The test procedure provided no direction to block the signal to MOV 652. MOV 652 functioned as designed with this input signal and closed causing termination of shutdown cooling flow. The reactor operator noted the annunciator indicating the loss of flow and secured the No. 12 LPSI pump. I&E technicians immediately reduced the input signal to less than 300 psi to allow re-opening of MOV 652 which operators immediately did after the valve had completely shu No. 12 LPSI pump was restarted approximately one minute after termination of flow. Investigation of this event revealed that the procedure used to test ERV 404 was extracted from a section of a surveillance test. pro-cedure (STP-M-5728-1), Pressurizer Relief Valve Channel Calibratio STP-M-5728-1 is usually performed during shutdowns, before shutdown cooling is established, to ensure that the reactor coolant system is

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protected from over pressurization at low temperature and, therefore, does not address shutdown cooling flow protectio .

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Preparation of the post maintenance test and associated reviews were apparently inadequate. Each section of STP-M-5728-1, except Section 5,

requires that, as a precaution, a jumper be installed prior to inserting a signal greater than 300 psia equivalent in order to prevent MOV 652 from shutting. Section 5 of the STP did not contain prerequisites, pre-cautions or other controls for ensuring that MOV 652 would not be closed by the test input signa The inspector noted that several losses of shutdown cooling have occurred periodically during tne past several year Losses due to inadequate procedures occurred on November 1, 1985, identified in Inspection Report 318/85-28 and most recently on March 22, 1986 identified in the above

- paragraph of this repor Tne inspector also recalled a recent Analysis and Evaluation of Ope' rating

Data (AEOD) case study " Decay Heat Removal Problems at U.S. PWRs", C-503, dated December 1985, which cited Calvert Cliffs as losing shutdown cool-j ing more frequently than most other plants in the stud The inspector reviewed the losses of shutdown cooling with plant opera-tions personnel. Most losses occur while the reactor vessel is drained

to the center line of the hot leg. nozzle. During the procedure for.

draining, instranent accuracies and the piping _ configuration and reactor design are such that time delays are experienced in obtaining accurate level readings. At times when an appropriate inventory of water has been removed and the lowering of level has terminated, the level may suddenly change a few inches. These types of level changes have caused pump cavitation or flow instabilities which the licensee conservatively clas-sifies as a loss of shutcown cooling. Other times, an operator may secure one cooling pump before starting the adjacent. pump in order to alternate pumps tnereby terminating flow momentarily which the licensee

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conservatively interprets and report's. It is recognized that Technical Specifications permit, during certain modes of operation, termination

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of shutdown cooling for extended periods of time. However, several in-cidents in the past have resulted from inadequate procedures or have l progressed in an uncontrolled manner, which if they had gone uncorrected, could have resulted in more serious consequence '

In the past, licensee corrective actions to prevent the-recurrence of the incidents have consisted of minor procedural changes and counseling 1 technicians. This action appears to be ineffectiv CFR 50 Appendix B Criterion V, " Instructions, Procedures and Drawings,"

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requires that activities affecting quality be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the cir-cumstances and be accomplished in accordance with these instructions, procedures or drawing '

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Contrary to the above, on March 22, 1986, a post-maintenance test of 1-ERV-404 was accomplished by procedures not appropriate to the circum-stances resulting in the inadvertent isolation of the Unit I shutdown cooling syste Additionally,10 CFR Appendix B, Criterion XVI, " Corrective Actions,"

requires that measures shall be established to correct failures, mal-functions and deficiencies, and in the case of significant conditions adverse to quality, the measures shall assure that the cause of the con-dition is determined and corrective action taken to preclude repetitio Contrary to the above, the loss of shutdown cooling event, a significant adverse condition which occurred on November 1, 1985, and which was caused by instructions inappropriate to the circumstances, recurred on March 22, 1986, due to procedures inappropriate to the circumstance Additional events leading to the loss of shutdown cooling have occurred on June 2,1985, January 4 and 7,1983, and October 12, 1983. This is a combined violation of one event failing to comply with two separate

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requirements (317/86-07-01; 318/86-07-01).

b. System Alignment Inspection Operating confirmation was made of selected piping system trains. Ac-l cessible valve positions and status were examine Power supply and breaker alignment was checked. Visual inspection of major components was performed. Operability of instruments essential to system perform-ante was assessed. The following systems were checked:

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Unit 2 Auxiliary Feedwater System checked on March 11 and April 8, 1986.

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Unit 1 High Pressure Safety Injection System checked on March 18 and April 22, 193 Unit 2 High Pressure Safety Injection System checked on March 18 and April 22, 198 Unit 1 Auxiliary Feedwater System checked on March 11 and April 8, 198 No violations were identifie c. Biweekly Inspections

During plant tours, the inspectors observed shift turnovers; boric acid tank samples and tank levels were compared to the Technical Specifica-tions. The use of radiation work permits and Health Physics procedures were reviewed. Area radiation and air monitor use and operational status was reviewed. Plant housekeeping and cleanliness were evaluated.

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! No violations were identified.

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l l Other Insoections Emeroency Planninc Drill On March 13, 1986 the licensee conducted an Emergency Plan drill simu-

, lating a security event and a loss of coolant accident. Participation of outside agencies was limited to telephone notification only. One participant received a minor injury during the drill resulting in an actual medical emergency event response. All levels of plant management (through the Vice President level) participated in the drill and all emergency and media centers were manne The inspector observed portions of the drill and attended a pre-drill controller meeting and the post-drill critique No significant weaknesses were identified by the in-specto No violations were identifie . Low Pressure Steam Line Leaks / Ruptures and Failures Low pressure steam line problems have been manifested in pin-hole leaks and ruptures including one circumferential break. Those occurring during this

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March 25: Steam leak No. 23 Moisture Separator Reheater (MSR) vent line (Unit 2);

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March 27: Pin-hole leak in weld on No.11 MSR Drain Tank level control j line (Unit 1);

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April 17: Rupture of No. 12 MSR Drain Tank normal level control line (Unit 1); and

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April 25: Circumferential failure of No.11 MSR high level dump line to condenser (Unit 1).

Pin-hole leaks have been attributed to localized accelerated erosion caused by steam flow eddies resulting from weld backing rings and penetrations such

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Pipe ruptures occurring in Urit 1 include the third stage extraction steam line in November 1981, No. 15 extraction steam line in November 1984, and the most recent MSR drain tank level control line in April 1986. In October 1981, the Unit 1 25 to 26 feedwater heater 14-inch to 6-inch reducer drain line rupture Low pressure steam drain line elbows carrying high moisture content steam such as those from MSRs and extraction steam lines are most subject 'to this erosion

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failure. Reasons for Unit I experiencing more failures would seem to in-clude an apparently more corvoluted steam drain system in Unit I than Unit 2, the older age of Unit 1, anc the use of schedule 40 pipe in Unit I where

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schedule 80 pipe is used in Unit The design of each unit's drain system with respect to pressure reducers, flows and velocities may be a contributor to the different failure rat The licensee recognized the problem and initiated an ultrasonic testing (UT)

program in 1984. This program defined approximately 6000 locations to be inspected and divided them into high, medium, and low priority, based on most probable locations as determined by EPRI, Gilbert Commonwealth, and Bechtel ,

studies, and licensee experience. The program continues only when a unit is ;

shut down for outage or upon special request, and then the system must be '

isolated and cooled down in order to UT the pipe. Currently, 90% of the high !

priority locations on both units have been inspected. On Unit 1, this is 290 locations of.which 57 locations were below the licensee's administrative ac- '

ceptance criteria which rejects any point below 150 mils. ASME code minimum wall thickness for this application is .090 inches and pipe ruptures generally begin to occur at or below .030 inches. Unit 2's inspection program has thus far resulted in 367 locations of which 52 were rejected. The program has caused the replacement of about 900 feet of piping to date. Several complete pipe runs of low pressure drain line pipe are scheduled for replacement during the upcoming outage with chrome-moly alloy schedule 40 pip Schedule 80 pipe is not used to replace the schedule 40 pipe in Unit I due to the complications which would arise in re-analyzing the pipe support system. The licensee man-agement is aware of and concerned about the potential personnel hazards asso-ciated with the erosion proble The third problem is associated with vibration of the high pressure main steam lines, low pressure extraction steam and drain lines, and high temperature feed water lines. Through observations, the licensee has noted apparent ex-cessive vibration in several areas-of the plant. Efforts to reduce the

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vibration in the past have been to design and install additional support Significant reduction was not evident and the licensee remained concerne As a result, the licentee contracted Bechtel Power. Corporation to perform an engineering evaluation of piping vibration and support systems for the main steam and heater drain system. This included a walk down inspection of the piping systems to inspect the piping from a vibration and support integrity viewpoin Specific tasks included:

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Vibration measurements at selected locations on main and auxiliary piping in the Unit 1 and Unit 2 turbine building for' comparison with prior measurements made in October 198 Inspection of main steam piping supports and ancillary piping in the turbine building of both unit ;

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Inspection of MSR drain piping systems in'both unit Results of the evaluation required installation of supports in 24 areas, 9 of which were required immediately, 12 are to be implemented pending comple-tion of design studies underway, and 3 for long term consideratio . .-. -- --- _-- .. . - . - --_

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The study concluded that, in general, the main steam piping supports are in

, good condition except as noted, and appropriately located to resist dynamic i

forces resulting from the main steam flow. Localized areas of high vibration i in bypass headers and small branch lines, resulting in some loosening and wear

, of support components, have been identified and are presently under investi-

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gation for design of additional restraints as require Localized areas of excessive motion of MSR drain piping have also been identified and are under

investigation. Upon completion of this work, confirming vibration measure-ments and a program of periodic inspection of support conditions should assure that there are not problems with the piping support syste On April 23, 1986, Unit 1 No. 11 MSR high level dump line to the condenser i was found leaking steam. Subsequently, it was determined that a circumferen-tial break had occurred but the pipe was apparently " cold sprung" in the direction of the condenser, minimizing steam leakage or air in-leakage to the condenser. This line had been identified as one of twelve requiring a support to be designed befcre installation. A program to study hangers and other supports for high capacity steam lines and high temperature f.ed lines is being developed and will be implemented during the next refueling outag . Review of Licensee Event Reports (LERs)

i LERs submitted to NRC:RI were reviewed to verify that the details were clearly reported, including accuracy of the description of cause and adequacy of cor-rective actio The inspector determined whether further information was re-quired from the licensee, whether generic implications were indicated, and whether the event warranted onsite follow up. The following LER's were re-i viewed:

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! 86-01 01/20/86 2/20/86 Violation of Technical Specifications

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for Pressurizer Overpressure Protec-tica during Cold Shut-Down Conditions

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86-02 2/4/86 2/28/86 Inadvertent Trip of Main Turbine from

Engineering Safety Features Actuation System

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86-03 3/15/86 4/11/86 Inadvertent Engineered Safety Features Actuation Due to Failed Logic Module

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Plant Maintenance

! The inspector observed and reviewed maintenance and problem investigation ac-t tivities to verify compliance with regulations, administrative and maintenance procedures, codes and standards, proper QA/QC involvement, safety tag use,

equipment alignment, jumper use, personnel qualifications,. radiological. con-

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trols for worter protection, fire protection, retest requirements, and re-portability per Technical Specifications. The following activities were in-cluded:

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MO 206-059-133A, MSIV-2 Accumulator Bladder Removal, Inspection and Reassembly of No. 8 Accumulator 21 MSI M0 206-11-382A, No.11 Control Element Drive Mechanism Motor-Generator Set Bearing Replacement / Repai MO 206-111-300A, No. 23 Auxiliary Feedwater Pump Bearing Temperature i Rise Investigatio Calibration Stickers During the performance of STP-073-01, as subsequently discussed in paragraph 8, operators utilized an out of calibration gauge to determine operability of No. 11 HPSI pum Review of this resulted in a violation due to use of an uncalibrated gauge that was inappropriate to the circumstance Further review of the gauges indicated that perscnnel performing the test are unable to readily determine whether gauges are calibrated or not in that calibration stickers are not used on installed instrument This topic had been previously discussed with the General Supervisor, Elec-trical and Control Department. The supervisor referenced ANSI 45.2.4 to which the licensee is committed through the Baltimore Gas and Electric Quality As-surance Manual. He highlighted that the standard which requires that installed instrumentation be provided with tags or stickers indicating the date due of next required calibration, is a construction standard applicable to plants in a construction phase and is not applicable to Calvert Cliffs in its current phase of operatio Further research and examination of other utilities for use of calibration stickers on installed instrumentation revealed that other facilities examined utilize calibration stickers both in the control room and in the plant and comply with ANSI 45.2.4 and IEEE 336. Further, the licensee's QA Manual re-quires compliance with Regulatory Guide 1.30 which specifies that ANSI 45. be applicable to operating power plants as well. The licensee's failure to implement the requirements of ANSI 45.2.4 and IEEE 336 is a violation (317/86-07-02; 318/86-07-02).

8. Surveillance The inspector observed parts of tests to assess performance in accordance with approved procedures and LCO's, test results (if completed), removal and res-toration of equipment, and deficiency review and resolutio The following tests were reviewed:

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STP-073-01, Engineering Safety Features Equipment Performance Test.

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STP-M-572-1, Pressurizer Relief Valve Channel Calibration.

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STP-05-1, Auxiliary Feedwater Pump.

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STP-0-65-1, Quarterly Valve Operability Check.

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STP-M-77-0, Diesel Fire Pump Surveillanc .

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STP-0-90-2, Emergency Diesel Generator No. 21 Operability Tes ,

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On March 10, Unit I was at 100% power. The licensee was in progress of per-forming STP-073-01 " Engineering Safety Features Equipment Performance Test",

j Revision 23. During performance of Section (E) 11 High Pressure Safety In-jection (HPSI), the procedure requires determination of " Pump Head" by re-I cording and subtracting the suction pressure from the discharge pressure

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i utilizing PI-301Z as the discharge pressure instrument (located in the Control Room). PI-301Z, "13 HPSI Discharge Pressure Gauge" had attached to it an "MR" i

sticker No. 3994 cated February 23, 1986, stating "13 HPSI in Action Range i

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due to 1-PT-301 out of cal". The needle of the gauge also appeared to be in-i appropriately centered below the lowest indicating increment, i.e., zer ) Performance of the STP continued utilizing this gauge. Consequently, the i acceptance criteria for Pump Head (TDH) 2900 Ft. was not met, i.e., as found ,

data, suction pressure 42 psi plus .89 factor (correction factor in psi due

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to gauge location) subtracted from 1180 discharge pressure plus .65 factor i

provide a differential pressure D/P of 1137.8 psig or 2633.9 Ft. Pump Head.

Based upon the failure-to meet the Pump Head acceptance criteria, the Shift l 1 Supervisor appropriately declared the HPSI Pump No. 11 inoperable. Subse-

quently, operators noteo that the discharge' pressure gauges for HPSI pumps

! 12 and 13 (subject to the same pressure) were consistent and indicated several

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pounds pressure higher than PI-301Z. Noting this, the-pressure from HPSI pumps l 12 and 13 was used to justify acceptance of operability in lieu of HPSI pump i 11 pressure gauge and the pump was declared operable.

The inspector noted the above and discussed the same with the Shift Supervi-i sor, and noted that although the pump appeared operable based on the above

. observations, formal determination of operability can only be determined by successful completion of a performance test. Therefore, the test should be

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the alternate gauges.

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Consequently, later during the day, Section E of the test was repeated without inserting a change and the pump re-declared operabl ,

10 CFR 50, Appendix B Criterion requires that instrumentation appropriate to l the circumstances be utilized to demonstrate compliance with requirements.

! Contrary to this, STP-073-01 was initially performed to demonstrate compliance l with Technical Specifications for operability utilizing a gauge inappropriate J

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to the circumstances in that the gauge was known to be deficient by evidence of the Maintenance Request (MR) adherad to it. This is a violation (317/86-07-03).

The inspector noted that guidance should be promulgated to ensure that (1) tests are not performed utilizing instruments that are suspect for any reason, (2) operability can only be determined via completion of a successful test procedure, and (3) procedures for making temporary changes to test pro-

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cedures should be re-emphasize . Safety Review Committee Meetings

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During the period the inspector attended several Plant Operations and Safety

, Review Committee (POSRC) meetings and the quarterly Off Site Safety Review Committee (OSSRC) meeting held on March 27, 198 The inspector observed each meeting for compliance with Technical Specifica-

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tions and ANSI 45.2 and for its apparent effectiveness in utilizing group synergis POSRC meetings appear to be improved since the management change of January 1986, in that:

) (1) The Chairman allows more discussion between POSRC members with little l comment until the end of discutsion, then separately solicits a recom-

mendation, thereby forcing the POSRC to act in an advisory role as re-quire (2) Changes were made to reduce the number of personnel in the conference

room, making the environment less crowde i (3) POSRC Chairman appears to be more critical, and leads the members in asking more probing questions resulting in many items being returned for additional analysis or wor POSRC meetings appear to meet Tectnical Specifications and are effectiv Attendance at the Off Site Safety Review Committee, OSSRC, meeting held at the "The Eagles Den" on site revealed that the meeting appeared to have fewer people in attendance and less formality than OSSRC meetings held in Baltimor , Those present did, however, ask thought provoking questions with good inter-action between member Review of the OSSRC members' expertise indicated that no personnel were pre-sent at the meeting who had expertise in metallurgy or non-destructive examin-ation. During discussions with the the licensee, the inspector indicated that formal controls should be established to establish acceptance criteria for j what topics must be deferred when the person with accredited expertise is not present.

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12 Technical Specifications require that the OSSRC be composed of certain members with specific expertis Review of the licensee's matrix for accrediting ex-perience and the resumes of the members indicated that anyone who had attended Naval Nuclear Power School was accredited with expertise in Operations, Health Physics, Nuclear Engineering and Chemistry. The inspector discussed this with the licensee and took exception with this policy in that many persons were accredited with " Nuclear Engineering" but only a very few had had actual ex-perience in dealing with the subject. Others accredited with " Health Physics"

, had had little or no more experience than the average radiation worker, and

very experienced people with degrees and experiences are available on sit The inspector requested the licensee to re-evaluate the matrix for accrediting experience.

I No violations were identified.

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1 Licensee Action on NUREG 0660. NRC Action Plan Developed as a Result of the

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TMI-2 Accident The NRC's Region I Office has inspection responsibility for selected action plan items. These items have been broken down into numbered descriptions (enclosure 1 to NUREG 0737, Clarification of TMI Action Plan Items). Licensee letters containing commitments to the NRC were used as the basis for accept-ability, along with NRC clarification letters and inspector judgment. The

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following items were reviewe Item I.C.1 Short Term Accident and Procedure Review. This item has been addressed in Inspection Report 317/80-05; 318/80-08 and 317/85-24. The licensee has completed all aspects of this item. The procedures are currently in the Control Room for operator use, and one cycle of training l has been complete A revised due date for this issue was. established

as December 31, 1985, by a Confirmatory Order to the licensee dated July i 16, 1985. Procedure implementation was in effect at this time. This item is close Item II.B.1 Reactor Coolant Vent System. This item was addressed in In-spection Report 317/82-05; 318/84-07. The system-is currently acceptable and considered closed. Additional items associated with the system are l as follows:

(1) Emergency procedures for operation of the Head Vent are not in the

new symptoms format utilizing the Owners Group Emergency Guidelines (tracked under Item I.C.1). Previour.ly established procedures cur-

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rently exist for operation of the system. Also, E0P-8." Functional

Recovery Procedure" makes reference to 01-1 G " Reactor Coolant Vessel Head and Pressurizer Vent System" which provides for the

operation of the system. This item is close No inadequacies were identified.

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1 Radiological Controls

Radiological controls were observed on a routine basis during the reporting period. Standard industry radiological work practices and conformance to

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radiological control procedures and 10 CFR Part 20 requirements were observe Independent surveys of radiological boundaries and random surveys of non-radiological points throughout the facility were taken by the inspecto Allegation During this period on April 17, 1986, an anonymous allegation was made regard-ing possible unauthorized entry into a High Radiation area on the 5 foot West Penetration area of Unit 2. This information was immediately transmitted to NRC Regional Management. A preliminary inspection was conducted. The inves-tigation included discussiens with the Supervisor-Radiation Controls, the Radiation Controls Shift Supervisor, the Instrument and Control Supervisor and the persons involved. Results of these inquiries were transmitted to the NRC regional office staf A secono part of the allegation was received by the resident inspector on May 6, 1986, regarding the uncontrolled use of High Radiation area keys. The alleger informed the inspector where a set of uncontrolled keys could be located. The inspector obtained the set of keys and, together with the Man-ager of Operations and Health Physics Supervisor, ascertained that these keys, in fact, could provide access to locked.High Radiation areas. The keys were turned over to the licensee. A telephone conversation was held between the Vice President, Nuclear Power and NRC management regarding these allegation An NRC letter was went to Baltimore Gas and Electric dated May 6, 1986, re-questing a response and a description of corrective actions, if appropriat Immediate corrective actions on the part of the licensee consisted of changing all of the locked High Radiation area doors (about 17) with radiation levels greater than 100 mr/h An additional 17 door locks were changed where radi-ation levels vary significantl Thirty-five padlocks are also being changed on licensee controlled sources and other sensitive items / area Technical Specifications 6 J2 requires that keys to High Radiation areas re-quired to be locked shall be under the separate administrative control of the Supervisor-Radiation Control and the Operations Shift Supervisor. Resolution of tnis item is pending the licensee's response to the NRC May 6 letter. This ,

i-item is unresolved (318 '86-07-03). i

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1 Review of Periodic and Special Reports Periodic and special reports submitted to the NRC pursuant to Technical i Specification 6.9.1 and 6.9.2 were reviewed. The review ascertained: Inclu-sion of information required by- the NRC; test results and/or supporting in-formation; consistency with design predictions and performance specifications; i adequacy of planned corrective action for resolution of problems; determina- l

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i tion whether any information should be classified as an abnormal occurrence,.

l and validity of reported informatio The following periodic reports were <

reviewed:

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February and March Operating Data Reports for Calvert Cliffs No. I Unit l and Calvert Cliffs No. 2 Unit, dated March 7 and April 8,1986, respec-tively.

13. Observation of Physical Security  ;

Checks were made to determine whether security conditions met regulatory re-

, quirements, the physical security plan, and approved procedures. Those checks

, included security staffing, protected and vital area barriers, vehicle 3 searches and personnel identification, access control, badging, and compen-

satory measures when required.

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14. Unresolved Items Unresolved items require more information to determine their acceptability and one such item is discussed in Detail 1 . Exit Interview Meetings were periodically held with senior facility management to discuss the inspection scope and findings. A summary of findings was presented to the licensee at the end of the inspectio l