IR 05000317/1982007

IE Insp Repts 50-317/82-07 & 50-318/82-07 on 820413-0511. Noncompliance Noted:Failure to Follow Requirements for Tagouts & Failure to Have Operable Hydrogen Analyzer During Cycle 5.Page 6 Withheld (Ref 10CFR73.21)

ML20054F756
Person / Time
Site:	Calvert Cliffs
Issue date:	05/18/1982
From:	Architzel R, Mccabe E, Trimble D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20054F731	List: IR 05000317/1982007 ML20054F730 ML20054F743
References
50-317-82-07, 50-317-82-7, 50-318-82-07, 50-318-82-7, NUDOCS 8206170290
Download: ML20054F756 (20)

Text

DCS 50317 820417 020421 50318 820417 50320 790328 820314 820504 820320 820319 820429 820402 820321 820503 820407 The report details 820316 820328 contain Safeguards Info l 820407 (Page 6 only)

820401 i

U. S. NUCLEAR REGULATORY COMMISSION THE INFORMATION ON THIS Region I PAGE IS DEEMED TO BE APPROPRIATE FOR PUBLIC 50-317/82-07 DISCLOSURE PURSUANT TO Report N /82-07 10 CFR 73.21 50-317 Docket N DPR-53 C License No. DPR-69 Priority --

Category C Licensee: Baltimore Gas and Electric Company P. O. Box 1475 Baltimore, Maryland 21203 Facility Name: Calvert Cliffs Nuclear Power Plant, Units 1 and 2 Inspection At: Lusby, Maryland Inspection Conducted: April 13 - May 11,1982 Inspectors: 5~ Z R~. E. Architze), Senior' Resident Reactor Inspector date signed C~.

ll Y 07 Trimble, Resid'ent Reactor Inspector b 7s date signed Approved By: CO i 5'/IB / Tr?.

E. C. McCabe, Jr. , Chief, Reactor Projects date signed Section 2B Inspection Sumary:

Inspection on 4/13 - 5/11/82 (Combined Report Nos. 50-317/82-07and50-318/82-07).

Areas Inspected: Routine, onsite regular and backshift inspection by the resident inspector (119 hours0.00138 days <br />0.0331 hours <br />1.967593e-4 weeks <br />4.52795e-5 months <br />). Areas inspected include the control room and the accessible portions of the auxiliary, turbine, service, and intake buildings: radiation protection; physical security; fire protection; plant operating records; plant operations; main-tenance; radioactive waste releases; open items; TMI Action Plan Items; Containment Leakage Test requirements; and reports to the NR Violations: Three: Failure to follow requirements for tagouts (detail 9.c), failure to have operable hydrogen analyzer during Cycle 5 (deta.1 ll.c), and containment leakage rate greater than allowed (detail 1 , e pYd7$dO0 o !$$$f7 M ed b - ..[ p S-F1-82-56

,._ PDR l (Tignat CopyloffCopies

'

1 r w irza, p pg7y- 6 /8Z- I Pages

c ! c,:

lDate)" ~~

'

. .;SCaJECT (0 tion)

n..C . .. . ... i JIl o:iS

__

_____- _-- --- - - -

..

_ DETAILS Persons Contacted The following technical and supervisory level personnel were c entacted:

J. T. Carroll, Ganeral Supervisor, OperationsM. E. Bo R.L.E.Dunkerl Denton, General Supervisor, Training / Technical Services W. S. Gibson,y, Shift Supervisor J. E. Gilbert, Shift SupervisorGeneral Supervisor, Electrical & Controls A. M. Hetrick, Radiation Safety Enginee,-R. P. Heibel, P J. R. Hill, shift Supervisor L. S. Hinkle, Engineering halyst Electrical & Control Section Lenhart, Radiological J. F. Lohr, Shift Supervisor Support Supervisor e y Unit W. Latha G. S. Pavis, Engineer, OperationsR. G. Mathews, Assistant G J. E. Rivera, Shift Supervisor L. B. Russell R. B. Sydnor,,EngineerPlant Superintendent Electrical & Controls D. Zyriek, Shift SupervisorJ. A. Tiernan, Manager,, Nuclear Power Other licensee employees were also contacted. Licensee Action on Previous Inspection Findings

_

Yellow Dots on Control Boards yor inspector verified that the yellow dots have been removed fDuring Control Remove.(Clo Placement of rom Control Board The NRC 318/82-01), Performance Appraisal Secticn (PAS) report s (317/82-01, on Calvert C section 3.a.(8) dated April 14, 1982 noted that auditor indepen was conducted QA was 5/13/8 also the of the Off Site Safety Review Chairman of the OSSR . . . .a eManager),

Comm completed The subject audit was #81-0SSRC-1 individual replaced the Manager, QA as OSSRC Chaiman la Also, reports of comencement and completion (with summary findi a endar year 1981 ngs) of the CSSRC requested audit were addressed directly to the Vice President

, Supply, as opposed to the OSSRC Chairman direct management reporting chai Manual to ANS wi ch somewhat r from removed his normal the lead 3.2-1976 which states that "While perfoming theThe licensee is audit, they (the auditors)

responsibilityshall for thenot report activity beingto a management representative audited." e who has auditor, at the request of the individual who pervisor e lead was and

_ _ _ _ .

throughout the audit period, audited activities for which his supervisor was i responsible. True auditor independence was not maintained. The inspector reviewed this issue with the Manager, QA on 4/30/82 who stated that various alternatives would be evaluated and long-term corrective action taken to ensure that auditor independence is maintained in future audits of OSSRC activities.

This item is unresolved pending licensee action and subsequent NRC:RI review (317/82-07-01,318/82-07-01).

The NRC PAS report also pointed out licensee weaknesses in the quality of l written safety evaluations (SE) for facility design changes accomplished l pursuant to 10CFR50.59. It stated that SE's for numerous Facility Change 1 Requests (FCR) had been reviewed and quoted the SE's for FCR's 79-1024 on l the halon system and 81-1011 on fire barrier modifications. It pointed out the following observations associated with SE's:

--

Failure to provide "the bases for detemination that the change does not involve an unreviewed safety question";

--

"nothing more than simple statements of conclusion providing no bases for the detemination"; and

-- " required the reviewer to accept the evaluation on the assumption I that proper installation would resolve any concerns".

The inspector reviewed the SE's for the FCR's referenced in the PAS report and three additional FCR's (80-1027 on the halon system, 80-1017 on the replacement of solenoid valves, and 79-1055 onESFASresetmodifications).

One of the three additional FCR's reviewed (80-1027) exhibited the problems discussed in the PAS report. The SE's for FCR's 79-1024 and 80-1027 stated only that "Halon systems are not required to be safety related or function in a seismic event. However, the systems are seisrically supported to preclude the possibility of falling on safety related equip.nent". The SE for FCR 81-1011 stated only that "Ductwork will be purchased and installed SR (safety related) and will be seismically supported. Barriers are seismically designed and installed safety related. Barriers will close up openings between existing structure and will be seismically designed and installed safety related".

10CFR50.59(b) requires that records of changes to a facility as described in the Safety Analysis Report (SAR) be maintained which include written SE's l providing the bases for detemination that the changes do not involve unreviewed safety questions (USQ), A USQ is involved if the probability or consequences of an accident or malfunction of equipment important to safety previously evaluated it, the SAR may be increased, or the possibility for an accident or malfunction of a different type than any previously evaluated in the SAR may be created, or if the margin of safety as defined in the bases for any Technical Specification is reduced. The SE's for FCR's 80-1027, 79-1024, and 81-1011 do not provide sufficient bases infomation to adequately support their conclusions that no USQs existed in that they were not sufficiently detailed in their discussions of FCR and applicable SAR design criteria to make any meaningful comparisons. They ;

did not sufficiently describe what accidents or malfunctions (if any) were addressed in the SAR or what items were considered in reaching the conclusion that the changes did not increase the probabilities of SAR described accidents or malfunctions or introduce accidents or malfunctions different than those evaluated in the SA _- . - - _ - -

_ _ _ _ _ _ _ _ _ _

.

The inspector determined that the above examples of 10CFR50.59 Safety Evaluations were indicative of historical lack of depth of the Safety Evaluations, confirming the validity of the findin mance Appraisal Team (Report 317/82-01, 318/82-01)gs of the Report and Inspection NRC's Perfor-317/82-05, 318/82-05 (failure to evaluate certain aspects of a facility change). The NRC will closely follow the licensee's corrective actions in this area, which are required to be detailed in writing bv the licensee in response to the referenced inspection reports (317/82-0) ')2, 318/82-07-02).

3. Review of Events Requiring One Hour Notification to the NRC The circumstances surrounding the following event requiring prompt NRC (one hour) notification via the dedicated telephone (ENS-line) was reviewe At 7.39 a.m. on 4/17/82 a technician attempting to post a tagout on the Unitsupplying breaker 1 Controlpower Element Drive to Unit System 2 Control (CEDM)

Element mistakenly Assembly op(ened the CEA) 21 causing it to drop into the reactor core. At 7:41 a.m. CEA 20 dropped when the same technician opened its supply breaker. The shift super-visor, after failing to establish communications with the technician, in anticipation of additional CEA drops ordered that Unit 2 be manually tripped. (Unit 1 had been shutdown earlier that day for a refueling outage.) Prior to the Unit 2 trip, pressurizer levei fell 30 inches below its program value. The licensee notified the NRC Operations Center by ENS at 8:11 Safety systems functioned as designed following the trip.

4. Radioactive Waste Releases Records and sample results of the following liquid and/or gaseous radioactive waste releases were reviewed to verify conformance with regulatory requirements prior to releas Gaseous Waste Permit G-039-82, Unit 1 Containment Modified Purge, released on 4/18/82. Group I release rate 1.46 x 105 m3/sec.,

Group II release rate 1.25 x 102 m3/se Release of Reactor Coolang Waste Monitor Tank 12 on 4/11/8 Total released 4.51 x 10- curies, excluding tritium and noble gase Liquid Waste Release Pennit R-033-82,12 RCWMT released 5/6/8 Expected curies released 2.99 E-2 (pre-release results).

-- Containment Release Permit G-049-82, Unit 2 Vent via ECCS Pump Room on 5/6/82. Group I rglease rate 8.81 E+2 m3 /sec., Group II release rate 5.37 E-2 m3/se No unacceptable conditions were identifie :

l

l l

- __ __ _ _ . . _

- __ _ _ _ _ _ _ _

5 Plant Maintenance The inspector observed and reviewed maintenance and problem investigation activities to verify compliance with regulations, administrative and maintenance procedures, and codes and standards, proper QA/QC involvement, safety tags use, equipment alignment, jumpers use, personnel qualifications, radiological controls for worker protection, fire protection, retest require-ments, and reportability per Technical Specifications. The following activities were include Troubleshooting of Unit 2 CEDM 38 after rod drop on 4/17/8 MR-82-8194, Modification to Electrical Penetration (FCR-79-65)

45 foot elevation, west penetration on 4/20/8 MR-82-8016, Steam Generator 12 Support Plate Rim Cut, implemer. ting Maintenance Procedure SG-14 (approved 4/19/82) observed 4/26/8 No unacceptable conditions were identifie . General Orientation Retraining The inspector ai. tended General Employee Orientation Retraining, Part I (facility access) and Part II (radiation protection) on April 15, 1982. The training was comprehensive in nature and in accordance with the lesson plan. The examination for Part II training was prepared by the Institute of Nuclear Power Operations as part of a pilot program to develop generic radiation protection retrainin The inspector noted that the examination appeared to be comprehensive and was more difficult than historical exams for Part II training. The instructor commented that a higher failure rate was being experienced on the newer examination (about 30%) requiring more instensive retraining for selected individual No unacceptable conditions were identifie . Observation of Physical Security the inspector checked, during regular and off-shift hours, on whether selected aspects of security met regulatory requirements, physical security plans, and approved procedures, Security Staffing

--

01servations and personnel interviews indicated that a full time trember of the security organization with authority to direct physical security actions was present, as require Manning of all three shifts on various days was observed to be as require Physical Barriers Selected barriers in the protected area (PA) and the vital area (VA) were observe Random monitoring of isolation zones was performed. Observa-tions of truck and car searches were made. One finding relating to the protected area barrier is addressed on the following page.

_- . _ _ _ ._ . _ _ _ _ - .- . . _ _ _ _ - _ _

.

7 Access Control Observations of the following were made:

--

Identification, authorization, and badging;

-- Access control searchts;

.

-- Escorting;

-- Communications;

--

Compensatory measures when require Bomb Threat One bomb threat was received during this reporting period. The required security procedures were followed. Appropriate searches were conducted with negative result Potential Strike During this inspection period the licensee made preparations to cope with a threatened local union picket line of pipe insulators against an onsite subcontractor. The picket line, anticipated to begin about 4/19/82 was never established. The inspector reviewed the licensee's preparations and arrangements for coping with the picket lin No unacceptable conditions were identifie . Licensee Action on NUREG 0660, NRC Action Plan Developed as ~a Result of the 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 descri (enclosure 1 to NUREG 0737, Clarification of TMI Action Plan Items)ptions

. Licensee letters containing commitments to the NRC were used as the basis for accept-ability, along with NRC clarification letters and inspector judgment. The following items were reviewe I.C.6, Verify Correct Performance of Operating Activities. This item had previously been inspected and remains open pending implementation of licensee commitments. During the review of the tagging associated with a Unit 2 CEDM drop and reactor trip on 4/17/82, the inspector noted that independent verification was not require CCI 112C, Safety and Safety Tagging requires a second, independent verification of correct implementation of equipment control measures for the use of apparatus service tags, including return to servic These are the principal tags in use at the site for both mechanical and I&C maintenance work. For the use of low voltage permits (600 volts or lower) an independent verification is not required. In addition, the return to service position is not required to be l

l _ _ _ . __ specified or documented, just the lifting of the tags. For the use of high voltage electrical equipment (greater than 600 volts) CCI ll2C requires an independent verification of switch position by the job supervisor and in addition, potential tests by electricians to verify the equipment is deenergized. Documentation of these checks is not required. The inspector noted that this methodology was not according to the guidance of I.C.6 nor the licensee's comitments in their letter dated December 15, 1980. The licensee stated that they were investigating methods to implement independent verifications for High and Low Voltage Permits. This item is unresolved (317/82-07-04, 318/82-07-04).

-- II.K.3.17, ECCS System Outages. The inspector reviewed the licensee's second submittal supplying infomation on Emergency Core Cooling System unavailability. The letter, dated April 13, 1982 was in response to an NRC request to go beyond a listing based on LER's and include outages due to surveillance testing, planned and unplanned, and preventive maintenanc The inspector noted that the licensee's submittal did not include all preventive maintenance. As an example, removal of the Service Water and Component Cooling Water Heat exchangers from service to mechanically clean tubes was not included, however, the length of time these were out-of-service for preventive maintenance had been the subject of a previous unresolved item. The licensee acknowledged the inspector's coments and stated that a review would be perfomed of the Calvert Cliffs preventive maintenance program and revised outage infomation forwarded to the NRC by May 28,1982. This item is unresolved (317/82-07-05, 318/82-07-05)

pending resubmission by the licensee and NRC review.

9. Review of Plant Operations Daily Inspection The inspector toured the facility to verify proper manning and access control, and observed adherence to approved procedures and LCO Instrumentation and recorder traces were observed. Status of control room annunciators was reviewed. Nuclear instrument panels and other reactor protective systems was examined. Control rod insertion limits were verified. Containment temperature and pressure indications were checked against Technical Specifications. Stack monitor recorder traces were reviewed for indications of releases. Panel indications for on-site /offsite emergency power sources were examined for automatic operability. Control room, shift supervisor, tagout log books, and operating orders were reviewed for operating trends and activitie During egress from the protected area, the inspector verified operability of radiological monitoring equipment and that radioactivity monitoring was done before release of equipment and materials to unrestricted us These checks were performed on the following dates: April 15,17,19, 20, 21, 27, 29, 30, May 5, 6, 7, and 10,198 On 4/21/82 the inspector obserycd that Unit 1 shutdown cooling flow was 2200 gallons per minute. The unit was in Mode 5 and drained

down to the top of the hot leg to facilitate getting water out of the steam generator U-tubes. The Reactor Coolant System was being borated to refueling concentration. The inspector questioned the operator about the minimum requirement for shutdown cooling flo Technical Specifications for Modes 4 and 5 require that at least 2 coolant loops (of 4, including 2 shutdown cooling and 2 reactor coolant) be operable and at least I be in operation. (Undercer-tain conditions all flow can be stopped for up to I hour.)

Technical Specifications for Reactor Coolant System flow requires at least 3000 gallons per minute during any dilution of the reactor coolant. Technical Specifications for refueling operations (Mode 6)

require at least I shutdown cooling loop be in operation at 3000 gallons per minute, however, this is allowed to be relaxed to 1500 gallons per minute if the water level is drained below the mid-plane of the hot leg. Because no dilution was in progress there was apparently no specified requirement for flow. The inspector noted that the conditions listed for reduced flow in Mode 6 were more coninon occurrences in Mode 5, for example during replacement of Reactor Coolant Pump seals and the evolutions in progress on 4/21/8 The basis for the Technical Specifications included reasons for the specified flow (Mode 6) to ensure sufficient cooling capacity, to minimize the effects of a boron dilution incident and to prevent boron statification. The inspector noted that these were valid concerns in Mode 5 as well and stated that the licensee should consider requesting an amendment to specify required Reactor Coolant flow in Modes 4 and 5. .'his item is unresolved (317/82-07-06)

and will be further reviewed by the NRC.

b. Weekly System Alignment Inspection Operating confirmation was made of selected piping system train Accessible valve positions in the flow path were verified correc Proper power supply and breaker alignment was verified. Visual inspections of major components were performed. Operability of instruments essential to system perfonnance was verified. The fol-lowing systems were checke Various system lineups in the Units 1 and 2 east and west 10 foot Penetration Rooms on 4/16/82, including Service Water lineup to Containment Coolers 12, 14, 22, and 24, Containment Spray and Low Pressure Safety Injection Valve Low Pressure Safety Injection train 22 on 4/19/8 Unit 2 Component Cooling Water lineup in the Component Cooling Water and ECCS Pump Rooms on 4/27/8 Containment Spray train 22 on 5/7/8 No unacceptable conditions were identifie . _ _ _ _ _ _ - - _ --__ -

10 _ Biweekly Inspection Verification conducte of the following tagouts indicated the action wa s properly

--

Penetration, verified on 4/20/82.Tagout 19022, on Loca

-

Tagouc .9140, 21 Charging Pump 011 Leak, verified on 4/30/82 .

Tank levels were also confimed. Boric acid tank cation samples

--

During a review of the Unit 2 Tagout Book on 5/5/82 pector the ins noted to that Service Water Pump 22 was listed as lock positio tagged i placed and independently The tagout had been verified issued on 4/30/82 and on 5/1/8 Later, during a Pump 22 was neither in pull toInvestigation .

lock nor tagged restored to service on the same day the ta . A was on file in the Tagging Authority's Offic ,

!

Record did not document tag removal and restoration ne-to n up by either the administrative procedure initial or independent checkcr, required by i of Calvert Cliffs Instruction ll2C, safety and Safety Ta  !

regarding service the clearing is a violation of tags and restoration of equipment to (318/82-07-06),

,

' _0ther Checks During plant tours, the inspector observed shift turnovers I

, security pemits, protective clothing and respirators. practices r ati monitors were reviewed. status of personnel monitoring practic i

!

with TS LCO Plant housekeeping and cleanliness was evalu TS LCOs, including RCS Chemistry and Activity, ySecondary Other Ch Activity, watertight doors, and remote instrumentation

-- and were che About 2:30 p.m. on 4/15/82, during an alignment of the Unit 1 Refueling Water Tank (RWT) to the Spent Fuel Pool (SFP) p -

cation fed system, through a malfunctioning approximately 150 psi relief 2500 gallons of borated wate valve SFP cooler 11 to the miscellaneous waste receiver tank, 0-RV-1997, .

The valve

--

was quickly isolated and repaired onnvolve The the followi were posted beyond their expiration dates.On 4/19/8

.

- - - - - - - - _ - - - - - - - - , , - - - - - - - - - - - - - . - - - -

SWP N Expiration Date 82-286 4/13/82 82-284 4/13/82 82-173 4/14/82 82-176 4/14/82 This was pointed out to the on-duty principle radiation-chemistry technician. The expired SWPs were removed by 4/20/82.

-- During a tour of the Unit 2 Charging Pump Room on 4/30/82 the inspector noted that the door to the enclosure for Charging Pump 22 had been blocked open. The enclosures had recently been installed as part of the fire protection plant upgrade, however, the door was not labeled as a fire door. The licensee stated that the door in question was a fire door and that the Charging Pump enclosure doors would be closed and appropriately labeled. This item is unresolved (318/82-07-07) pending completion of the licensee's actions and reinspection by the NRC.

--

About 9:30 a.m. on 4/20/82 a fire broke out on the second floor of a temporary 2-story building under construction east of the South Service Building. The onsite fire brigade extinguished the fire within 10 minutes. The local fire department responded within 15 minutes. No safety-related equipment or radioactive materials were involve The inspector observed the actions of the onsite fire brigade and security measures to allow rapid access for the local fire department (SolomonsIsland). No unacceptable conditions were identifie About 1:00 p.m. on 4/14/82 an approximately 1 inch layer of spent resin was found unifonnly spread over the top of a shipping cask liner, contained by a 2 inch lip around the liner outside circumferenc The spillage occurred during a transfer operation of resin from the spent resin metering tank at about 3:00 p.m. on 4/13/82. No resin spread outside of the shipping cask. A small resin sample measured 4 mrem /hr on contact. The liner top measured 400 mrem /hr on contact. The outside of the cask measured 15 mrem /hr on contac No personnei exposure or contamination problems resulte Subsequent invetigation showed that about 150 cubic feet of resin had been transfeired to the cask liner. The personnel involved during the event hcd underestimated the amount of resin in the holding tank and bei'eved they were only transferring about 90 cubic feet. There is a level indicator on the resin metering tank. Level is estimateo based on the number and volume of ion exchangers flushed to the tank. The transfer operation had been interrupted by a continuous air monitoring system (CAMS) alann at 3:00 p.m. which resulted in a 1 to 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> evacuation of the are A followup air sample showed zero MPC iodine and particulate activity and the following gaseous activit . - _ _ _ ---

'

Isotope ~ Activity,uci/cc Xe 131m 1.72 x 10-8 Xe 133 1.76 x 10-6 Xe 133m 1.72 x 10-8 Xe 135 4.9 x 10-11 The liner may have overfilled during the interruption. The inspector discussed the event with radiation safety and operations personne He expressed concern to the General Supervisor of Operations (GS0) on 4/20/82 that the exact cause needed to be identified and corrective action taken to prevent recurrence. The GS0 stated that a radiation safety engineer had been assigned to investicate the inchient to determine appropriate corrective actions. This item is unresolved pending licensee action to identify and correct associated problems and subsequent NRC review (317/82-07-07).

10. Containment Leakage Testing During the week of March 8, 1982 the inspector discussed clarification of 10CFR50 Appendix J requirements with the licensee. A copy of an internal NRC memorandum from the Director, Division of Systems Integration, NRR to the Director, Division of Resident and Regional Inspection, I&E dated January 11, 1982 was handed to the licensee. The position of the memorandum was basically that improvements in pathway leakages performed on paths testable in Type B and C testing completed during the outage time preceeding a periodic integrated containment leakage test must be added to the as found integrated result This would allow leakage information obtained fron the "as is" Type A (integrated)

test to be used to assess the containment condition and its integrity following a period of plant operation. The licensee disagreed with the NRC position, however, the inspector stated that this was the position which would be enforce On April 13, 1982 the licensee sent a letter to the Operating Reactors Project Manager formally stating their disagreement with the NRC position in the January 11, 1982 memorandu About 4/27/82 the inspector was informed by the licensee thet 9 penetrations, including electrical (4) and piping (5) penetrations had been repaired or removed on Unit 1 following the refueling shutdown which commenced on April 17, 1982 without testing for the "as found" leakage. The inspector held a meeting with the licensee on April 28 to discuss this issue. The inspector expressed concern that the licensee had decided to repair the penetrations without prior testing. This decision had not been discussed with the NRC nor was the April 13, 1982 letter disagreeing with the NRC position distributed to the Resident Inspector. The inspector informed the licensee that failure to make prior measurements of pathway leakage meant that it was impossible to detemine improvement for the purpose of calculating the "as found" integrated contain-ment leakage and that the 1982 Integrated Test would be considered to be a failure. The inspector also querted the licensee concerning whether any additional repairs were anticipated prior to Type B and C testing. The licensee stated that none were planned, but if any repairs were indicated they would test for the "as found" condition.

_ . _ - _ . . ___ _ , . _ _ _ _ _ _ . _- _ _ _ _ _ _ _ _ - . _ _ _ .

The licensee stated that a review could be made of the 9 repairs in question in order to establish an upper boundary of leakage for those paths which had 1 valve or barrier still intact. In addition, they stated that data was available from the previous Type B and C tests which could be used as the basis for improvement, notwithstanding any unquantified increase during Cycle 5 operation. The inspector stated that this area was unresolved (317/82-07-08)

and would be examined by a Specialist NRC Inspector during the review of the integrated test results. The inspector further noted that the point regarding integrated test failure became moot following discovery by the licensee (paragraph 11) that Unit I had been operated throughout Cycle 5 with contain-ment leakage above allowable.

11. Review of Licensee Event Reports (LERs)

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 corrective action. The inspector determined whether further information was required from the licensee, whether generic implications were indicated, and whether the event warranted onsite followup. The following LERs were reviewe LER N Date of Event Date of Report Subject Unit 1 82-09/3L 3/14/82 4/14/82 RPS CHANNEL B HI POWER, THERMAL

'

MARGIN / LOW PRESSURE & AXIAL SHAPE INDEX TUS BYPASSED; TH INPUT FAILING LOW 82-10/3L 3/19/82 4/12/82 CEA PULSE COUNTING SYSTEM &

INCORE DETECTION SYSTEM INOPERABLE 82-11/3L 3/21/82 4/16/82 CEA 21 DROPPED INTO CORE 82-12/3L 3/16/82 4/15/82 11 and 12 CHARGING PUMPS INOPERABLE 82-13/3L 3/16/82 4/15/82 12 CHARGING PUMP OUT-OF-SERVICE FOR MAINTENANCE & 13 CHARGING PUMP INOPERABLE 82-15/3L 4/07/82 4/23/82 PRESSURIZER LEVEL EXCEEDED 5%

PROGRAM BAND 82-16/3L 4/01/82 4/27/82 ECCS EXHAUST FILTER TRAIN INOPERABLE 82-17/3L 3/22/82 4/21/82 12 CONTROL ROOM A/C UNIT INOPERABLE 82-18/3L 4/06/82 5/04/82 12 ECCS PUMP ROOM EXHAUST FAN REMOVED FROM SERVICE FOR SHAFT BEARING REPLACEMENT 82-19/3L* 4/15/82 4/29/82 HYDROGEN ANALYZER INOPERABLE

_ _ _ _ ___ _ . _ _ .

LER No. Date of Event _Date of Report ' Subject'

Unit 1 82-22/3L* 5/03/82 5/04/82 UNIT 1 OPERATIONS IN EXCESS OF 200 DEGREES PERFORMED WITH COM-BINED LEAKAGE RATE OF GREATER THAN 0.60 La FOR ALL PENETRATIONS AND VALVES SUBJECT TO TYPE B &

C TESTS DURING CYCLE 5 Unit 2 82-15/3L 3/20/82 4/19/82 NEGATIVE LIMIT SET POINT FOR CHANNEL A 0F RPS AXIAL SHAPE INDEX TU OUT OF SPECIFICATION 82-16/3L 4/02/82 4/30/82 PLANT COMPUTER FAILED CAUSING LOSS OF CEA PULSE COUNT SYSTEM

& INCORE DETECTION SYSTEM 82-17/3L 4/07/82 5/04/82 23 CHARGING PUMP REMOVED FROM SERVICE WHILE 22 CHARGING PUMP OUT-OF-SERVICE 82-19/3L 3/28/82 4/27/82 CEA 38 REED SWITCH POSITION INDICATOR CHANNEL GIVING ERR 0NE0US INDICATION b. For the LERs selected for onsite review (denoted by asterisks aLove) the inspector verified that appropriate corrective action was taken or responsibility assigned and that continued operation of the facility was conducted in accordance with Technical Specifications and did not con-stitute an unreviewed safety question as defined in 10CFR50.59. Report accuracy, compliance with current reporting requirements and applicability to other sf:s systems and components were also reviewe LER 82-08/3L (NRC Inspection Report 317/82-05, 318/82-05) - In reviewing this incident the inspector learned that the plant operators incorrectly believed Component Cooling Water Heat Exchanger (CCHX) 11 was back in service when 1 of 2 posted sets of equipment tags had been cleared. The licensee principally attributed the cause to the failure to enter the CCHX 11 inlet valves in the Locked Valve Deviation Log, which is reviewed by l operators during shift turnover and poor coninunications during shift turnove The inspector discussed this event with the General Supervisor of Operations (GS0) on 4/15/82 and stated that the NRC felt this

event was significant in that it represented a failure of the operators on duty to carry out their basic responsibility of being cognizant of plant status. The GS0 agreed and stated that he would further discuss the event with his operators and remind them of their responsibilities in this area. This item is un-resolved pending licensee action and subsequent NRC review (317/82-07-09).

. -__-_ _ _ _ .-. . _ _ _

.

c. LER 317/82-19. On April 15, 1982 the licensee discovered that the flow path from the containment to the hydrogen analyzers was isolated. This was discovered during flow testing of the sample lines to hydrogen analyzer cabinet IJ222, which was inoperable due to modifications to satisfy TMI TAP Item II.F.1.6. The licensee discovered that the test pressure would not bleed off after the containment isolation valves were opened. A similar test at 6:10 p.m. on the lines to the cabinet IJ220, the redundant analyzer, which was being relied upon as the required analyzer (T.S.3.6.5.1),

showed a similar problem. The analyzer was declared inoperable, personnel entered the containment, discovered that the three manual stop valves to the cabinet were shut, and reopened the valves at 6:30 p.m., terminating the event. Subsequent investigation showed that the manual stops to the redundant analyzer were closed, and a flow test on Unit 2 was successfully performe The licensee detennined that the valves had apparently not been returned to service following local leak rate testirig (between November 21-28, 1980)

consequently all Unit 1 operations in Modes 1 and 2 during Cycle 5 were without the required hydrogen analyzers. Licensee review of this event revealed the following principal causes and planned corrective action (1) The valves did not appear in the NSSS Sampling Operating Instructions' valve list and consequently no verification of the valves' position prior to entering Mode 4 on January 8, 1981 was performe (2) The tagging procedure used at the time of this event did not provide for returning valves to a specified position when tags were cleared nor did it provide for a second individual verifying that the valve is returned to its proper position after a tagou A task force reporting directly to the Plant Superintendent had been established in February,1982 to walk down all piping systems within Calvert Cliffs with the following objectives:

(1) Verify the correct arrangement of valves on the piping and instru-ment diagrams (P& ids) and to add or delete valves from the P& ids and the operating instructions' valve lists to reflect as-built condition (2) Ensure that the numbering, descriptions, and operating positions of all valves listed in the Operating Instructions' valve lists are correc (3) Attach metal identification tags to each valv Every process system valve in the plant is to be physically checked regard-ing its location, function and operating position at the conclusion of this effort. The Operating Instructions' valve list for each system will be checked to ensure that all valves are included along with their correct number, description, location, and operating positions after each system is walked down to ensure completeness and accuracy of the valve list All valves in the facility will have metal identification tags attached for facilitating valve lineup checks, restoration of equipment to service and to minimize system transients due to misoperation of valves. All

. ._ - - -

walkdowns and updated valve lists will be complete for all safety related systems for both units by December 31, 198 Further, the licensee stated that Calvert Cliffs Instruction ll2C Safety and Safety Tagging was revised in June,1981 to incorporate a l system by which 2 operators are used to return equipment to service and to verify that the equipment is returned to service correctl I The procedure provides for documentation of this verification and of l the repositioning of valves and other components after maintenance or i testing. If the Senior Control Room Operator directs valves to be repositioned differently from the nomal operating position after testing due to operating conditions, this is also documented. With j the revision of this instruction, additional verification is being perfomed by qualified operators of the position of equipment restored to operability after testing or maintenance consequently minimizing the possibility of a recurrence of this even .

The inspector reviewed the circumstances surrouding this event including discussions with personnel and review of documents and the repor The following procedures and drawing were reviewe B, NSSS Sampling System, revision 4 approved 1/20/8 Coment: This procedure describes the operation of the H2 analyzing system. As noted by the licensee, the valve check-list appended to the procedure did not include the stop valves inside the containment. This procedure also provided the path, through the H2 analyzers, to obtain post-accident containment radioactivity samples pending installation of the Post-Accident Sampling Syste A, Hydrogen Recombiners, revision 1 approved 3/2/7 Comment: This procedure does not address use of the hydrogen analyzer reading B, Hydrogen Purge System Operation, revision 2 approved 3/20/79. Comment: System operations did not rely on readings from the hydrogen analyzers.

' -- E0P5, Loss of Reactor Coolant, revision 12 approved 3/6/8 Comment: This procedure requires placing the hydrogen recombiners in service prior to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the start of the incident, with-cut reliance on H2 readings. The safety analysis presented in Section 14.19 of the FSAR, concludes that the recombiner would be started when hydrogen concentration reaches 3% or approximately 9.55 days after the start of the LOC OM 463, Piping and Instrument Drawing for the Gas Analyzing System, Units 1 and 2, revision 3 dated 5/26/81. Coment: This drawing shows the valves in question and lists their position as locked ope (Containment No.1 North Shield, Containment No.1 Elevation 135, Containment No. 1 Elevation 189.)

-- _ _ _ _ _ _. _ _ -_ _ _ .---.-- _-. _ , _ _ _ _ _ _ ~ _ - -

_ . , _ - - _ . .

.

--

STP M-571-1, Local Leak Rate Tests, revision 3 approved 9/24/8 Coment: This procedure isolates the hydrogen analyzer flow path but does not include restoration lineups. The inspector questioned various operators concerning tagging for the purpose of local leak rate testing (not required by the procedure). They stated that the penetrations may or may not be tagged, depending on the particular circumstances. The inspector questioned the licensee regarding this aspect in light of the statement that revised tagging requirements would minimize the potential for recurrence. The licensee stated that the STP would be revised to require taggin The inspector also questioned the licensee concerning short-tenn corrective action in case another, similar system was misaligned as a result of local leak rate testing without subsequent proper lineup on startup or as otherwise necessary. Because Unit 1 shutdown the next day following the event no further action was necessary (all local leak rate testing is to be controlled by tags). The licensee stated that Unit 2 penetra-tions which were isolated during local leak rate testing would be investigate Technical Specification 3.6.5.1 requires that two independent containment hydrogen analyzers shall be operable in Modes 1 and 2. Continued operation in a degraded mode is allowed for a period of time with one analyzer out-cf-service. Unit 1 operation during Cycle 5 without an operable hydrogen analyzer is a violation (317/82-07-10) of Technical Specification 3.6.5.1. LER 317/82-22. At 2:00 p.m. on May 3,1982 the licensee confinned that from 12/18/80 until 4/18/82 all Unit 1 operations in excess of 200 degrees had been perfonned with a combined leakage rate greater than allowed by Technical Specifications. This was discovered during a review of the latest Containment Local Leak Rate Test Procedure (STP M-571-1, revision 3 approved 9/24/80) and the latest test results completed December 18, 198 Technical Specification 3.6.1.2.b requires that containment combined leakage rate shall be less than 0.60 sigLa for (La)= 0.2 percent all penetrations andby weight of the containment valves airBper subject to Type and24 hours at ,T C test p(La Pa are defined in 10CFR Part 50, Appendix J.)ype TheA,results B, andof C the teststest and completed on December 18, 1980 were found to be 0.773 La, however, the required action of restoring the leakage to within limit prior to exceeding 200 degrees was not take One contributing factor which led to operation above allowable containment leakage limits was an error introduced into STP M-571-2 during a general revision on 9/24/80. At that time, the limit, previously stated simply as the maximum allowable leakage - 207,600 sccm (standard cubic centimeters per minute), was changed to list 207,600 scem as the administrative limit and 346,247 as the Technical Specification limit. The engineer changing the procedure apparently confused La (346,247 sccm), the maximum allowable

, - , - ,

'

l

leakage rate (10CFR50, Appendix J definition) with the Technical Specification limit (0.6 La).

The inspector independently calculated the required leakage rates using a Containment Free Volume (FSAR Section 5.1.2.1) of 2,000,000 ft3 and ,

Pa of 50 psig with a resultant leakage rate of 207,700 secm. This l rough calculation confirmed the licensee's conclusion that the administra- l tive limit specified in STP M-571 was in reality the Technical Specification limit (0.6La)- I The inspector reviewed the following procedures.

--

STP M-471-1, Air Locks Door Operability and Leak Rate Test, revision 2 approved 9/3/80. Coment: This was a general revision for format and content. An administrative limit of 207,600 seem was added and a TS limit of 346,247. The Plant Operations and Safety Review Comittee (POSRC) approved the revision in meeting 80-120 on 9/3/80.

-- STP M-571-1, Local Leak Rate Tests, revision 3, approved 9/24/8 Comment: The POSRC approved the revision in meeting 80-130 on 9/24/80. This procedure change was also a general revision and changed the administrative and TS limit.

--

Results of STP M-571-1, Local Leak Rate Tests, completed 12/18/8 Coment: The remarks section contained the following note:

"The Administrative leakage limit (running total of all test, including data from the previous performed LLRT on penetrations not tested yet this outage) of 207,600 sccm was exceeded, running total is 267,615.21 scem with 232,051.34 due to the leakage of penetrations ZWB8, ZWC3, ZEC2, and ZEC MR issued for corrective actio Follow up Action MR's issued to Electric Shop for pene-trations, further FCR pending. Final leakage 267,709.75 sCCm."

The POSRC approved the completed test results in meeting 81-22 on 2/2/82.

The inspector reviewed the POSRC meeting minutes listed above and noted that all items reviewed were approved without comment. Several members present were questioned regarding the content of the review but they indicated that it was too far in the past to recall. The POSRC Chaiman indicated that the STP results were probably approved because the procedure stated that the results were between the administrative and TS limits and ccrrective actions had been initiated.

The inspector noted that the test failure was caused principally by four electrical penetrations (total leakage 0.67 La). The penetrations involved were all Type 2E Electrical Penetrations made by Amphenol, Sams Division.

The inspector reviewed historical test results for the four penetrations and noted the following progressive deterioration: _ _ _ _ _ _____ _ _ _ _

,

. .

Penetration Preop 5/76 3/77 3/78 ~7 /79 10/80 ZWB8 10 (1419) (28772)

ZWC3 4 0 0 22 1810(2917) (46408)

ZEC2 5 0 -

240 4790(4464) (76777)

ZEC7 3 0 -

94 3380(1310) ~(80112)

Total 22 (10,110) (232,069)

Parenthetical values are as-left condition. Other values are listed as-found. All numbers in scc The inspector asked the licensee about individual limits (both administrative and absolute) for the results of individual penetrations. Although valves (Type C tests) contained such limits,none were specified for the electrical penetrations. The licensee stated that the valve values were obtained from codes and standards, however, these were not available for electrical penetrations. As a result the licensee started up with 39% of the allowable combined leakage coming from a single (ZEC7) penetration, without successful repair. This was another contributing factor to the even The inspector questioned the licensee concerning the as-found condition of the penetrations following Cycle 5 operation in light of the noted progressive deterioration. This information would allow quantification of the leakage to detemine how much above the limit the leakage was at the end of the cycle. The inspector was infomed that these penetrations were included in those which had been imediately removed from the containment without prior testing upon shutdown on April 17,1982 (see paragraph 10). This action was contrary to the NRC position on Type B and C leakage testing and resulted in an inability to establish how bad the leakage was at the time of shutdown. The penetrations are bein type (Conax Type 2E Electrical Penetrations)gThe .

replaced with anwill penetrations improved be welded to the containment liner versus the previous design which incorporated a bolted joint with two concentric 0-rings. In addition, the cable passages have been changed to include an improved mechanical joint and better epoxy material. A Type A (integrated) test will be perfomed after the current refueling outage. The inspector stated that operation of the facility between 12/18/80 until 4/18/82 with a combined containment leakage rate greater than allowed was a violation (317/82-07-11).

The licensee stated that although similar procedural errors existed in the Unit 2 procedures, the actual results of Unit 2 combined leakage tests were always within required limits.

12. Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted pursuant to Technical Specification 6.9.1 and 6.9.2 were reviewed. That review included the following:

Inclusion of infomation required by the NRC, test results and/or supporting infomation consistency with design predictions and perfomance specifications,

- . _ _ __ --

-

-

planr.ed corrective action adequacy for resolution of problems, determination whether any information should be classified as an abnormal occurrence, and validity of reported information. The following periodic report was reviewe '

-- March,1982 Operations Status Reports for Calvert Cliffs No.1 Unit and Calvert Cliffs No. 2 Unit, dated April 15, 198 l

During the review of the March,1982 Operations Status Report the )

inspector noted that the report distribution was not according to 1 the latest Technical Specification change (issued March 9,1982). l The licensee stated that a copy of the March report would be sent to the correct addressee and that the distribution would be cor- l rected for future reports. A subsequent revised report was sent on May 5,1982 to the correct distribution.

13. Unresolved Items Unresolved items are matters about which more information is required to determine whether they are acceptable. Unresolved items are discussed in paragraphs 2, 8, 9,10,11, and 12 of this report.

1 Exit Interview Meetings were held with senior facility management periodically during the course of this inspection to discuss the inspection scope and findings. A summary of findings was also provided to the licensee at the conclusion of the report perio _

>

,