IR 05000317/1985024

Insp Repts 50-317/85-24 & 50-318/85-20 on 850815-0930.No Violation Noted.Major Areas Inspected:Control Room,Plant Structures,Plant Operations,Radiation Protection,Physical Security,Maint,Surveillance & Emergency Preparedness

ML20138G237
Person / Time
Site:	Calvert Cliffs
Issue date:	10/17/1985
From:	Elsasser T, Foley T, Trimble D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20138G173	List: IR 05000317/1985024 ML20138G168
References
RTR-NUREG-0660, RTR-NUREG-0737, RTR-NUREG-660, RTR-NUREG-737, TASK-1.C.1, TASK-2.B.1, TASK-2.B.2, TASK-2.F.2, TASK-2.K.3.01, TASK-2.K.3.05, TASK-2.K.3.25, TASK-TM 50-317-85-24, 50-318-85-20, IEB-80-11, NUDOCS 8510250435
Download: ML20138G237 (16)

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U. S. NUCLEAR REGULATORY COMMISSION

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Region I  !

Docket / Report: 50-317/85-24 License: DPR-53 50-318/85-20 DPR-69 Licensee: Baltimore Gas and Electric Company Facility: Calvert Cliffs Nuclear Power Plant, Units 1 and 2 Inspection At: Lusby, Maryland

] Dates: August 15 - September 30, 1985

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1. ~ bkll2S p (p.Foley,SegResidentInspector

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'dat4 I

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f g C. Trimbi

/ W sident Inspector

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/0 lif[$

'datif I Approved:

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T. C. Elsafp IObl i V, Chief date'

Reactor Projects Section 3C ,

Inspection Summary:

August 15-September 30, 1985: Inspection Report 50/317-85-24; 50/318-85-2 ;

i Areas Inspected: Routine resident inspection of the Control Room, accessible i parts of plant structures, plant operations, radiation protection, physical

! security, plant operating records, maintenance, surveillance, emergency pre-paredness exercise, IE Bulletin close out, meetings with public officials, fuel i

shipment, licensee action on TMI Action Plan items, and reports to the NR Inspection Hours totalled 210 hours0.00243 days <br />0.0583 hours <br />3.472222e-4 weeks <br />7.9905e-5 months <br />.

j Results: Although_no violations were identified, one area described within

] this report, section (8) regarding Reactor Coolant Pump Seal maintenance, -

displays a general lack of supervision and inadequate quality control. This is l- not typical of management's performance and may be used to support

justification of future SALP findings.

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DETAILS

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' Persons Contacted Withih this report period, 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 this period, Unit I was shut down for a two week outage to inspect cooling water supply hoses to stator bars due to high l

Main Generator RTD readings. Unit 2 was operating at reduced power while troubleshooting condenser Moisture Separator Reheater (MSR) in-leakage i problems and performing preventative maintenance due to marine growth i

(cleaning heat exchangers). On August 27, Unit I was returned to servic Both units continued full power operations with short power reductions for cleaning of marine growth from salt water system component On September 19, a small fire occurred on No. 11 Emerge'ncy 6,iesel Genera-tor due to an injector leak. No damage occurred to the diesel and it was returned to service within four hours as discussed in Section On September 30, Unit 1 tripped from full power due to a suspected fault in the feedwater heater level circuit, described in Section During August 21-23 both residents attended a Counter Part Meeting at the Regional Headquarter On September 10, the licensee conducted the Annual Emergency Preparedness Exercise. One resident participated in the drill while the other and a team of NRC inspectors and consultants observed. The results of this exercise are documented in Inspection Report 317/85-25; 318/85-2 On September 26, the licensee commenced preparations for Hurricane Gloria, at a time when it was located several hundred miles south of North Carolina. The licensee displayed conservatism in manning their emergency facilities well in advance of the storm posing an actual threat.

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At various times during this period, the resident inspectors met with local officials within the Emergency Planning Zone to discuss emergency preparedness and concerns regarding the Calvert Cliffs plan ,

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Other NRC inspections which occurred at this facility during this period involved Emergency Preparedness, Environmental Qualification of Components, Operator Licensing, Security, Control Room Habitability, and Radiation Protection. On September 27, 1985, the NRC staff issued a proposed fine of $50,000 for violations identified during site inspections during June and July 1985 regarding operability of the Post Accident Sampling Syste _

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, Both plant cleanliness and Control Room professionalism and environment

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remain very good. . Operations personnel have continued to exercise con-1 servative judgment in the operation of the facilit . Licensee Action on Previous Inspection Findings

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(Closed) IE Bulletin (80-80-11) Masonry Wall Desig See Section 12 for details.

i Review of Plant Operations Daily Inspection During routine facility tours, the following were checked: manning, access control, adherence to procedures and LCO's, instrumentation, recorcer traces, protective systems, control rod positions, Contain-ment temperature and pressure, control room annunciators, radiation monitors, radiation monitoring, emergency power source operability,

, control room logs, shift supervisor logs, tagout logs, and operating j order No violations were identifie System Alignment Inspection Operating confirmation was made of selected piping system train Accessible valve positions and status were examined. Power supply and breaker alignment was checked. Visual inspection of major com-ponents were performed. Operability of instruments essential to system performance was assessed. The following systems were checked:

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Unit I Component Cooling checked on August 30, 198 i

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Unit 1 and 2 Spray System checked on August 18-20, 1985.*

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Unit 1 Auxiliary Feedwater System checked on August 18, 198 ,

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Unit 1 and 2 Containment Spray Systems checked on September 11, 198 *For this system, the following items were reviewed: The licensee's i system lineup procedure (s); equipment conditions / items that might degrade system performance (hangers, supports, housekeeping, etc.);

instrumentation lineup and operability; valve position / locking (where required) and position indication; and availability of valve operator power supply,

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In addition to the above, the licensee's approved instructional material for the Containment Spray System was reviewed. The material is well organized and reflects the actual plant system including the

, proper valve lineup and operational status. The inspector also I

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f I discussed the proper system function with a reactor operator who was thoroughly familiar with Containment Spray System operation and

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functio During the visual inspection of major components of the containment

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spray system, the inspector observed a rope used to signify a con-tamination barrier to be pulled through the handwheel for the #21 shutdown heat exchanger outlet valve. This discrepancy was corrected by the on duty radiation control technicia No violations were identifie c. Biweekly and Other Inspections During plant tours, the inspector observed shift turnovers; boric acid tank samples and tank levels were compared to the Technical Specifications; and 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 clean-liness were evaluated. Verification of the following tagouts indi-cated the action was properly conducte Tagout #16302, Unit 2 Saltwater System checked on September 12, 198 Tagout #162768, #12 Saltwater Header checked on August 18, 198 '

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Tagout #16446, Spent Fuel Pool Cooling checked on August 24, 198 Tagout #16496, Saltwater Pump checked on August 24, 198 During this period the inspector informed the licensee of a recent diesel generator brush rigging failure (due to metal fatigue) at the Millstone Unit 3 plant. The generators for the Calvert Cliffs diesels were made by the same vendor as those at Millstone (different i

model number, however). The licensee received more detailed

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information about the failure from the NRC Region-based metallurgical engineer who had investigated the Millstone event. The licensee then had their spare generator examined (that generator was undergoing i repair at a vendor facility) and learned that the bases of their

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brush rigging alarms are fastened to the end cover of the generato Those at Millstone are fastened in a different manner (via an eccentric nut and shaft), and the failure apparently occurred as a result of deficiencies unique to the Millstone fastening design. The licensee, therefore, does not believe the generators are susceptible to the same problem. However, they plan to inspect diesel brush rigging at the next available opportunity.

I The inspector noted that the temperature scale on the (30'-200')

Delta T recorder in the Control Room (measures temperature difference

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between two elevations on the older meteorological panel) was printed

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in degrees Celsius. This Delta T is used in conjunction with Emer-gency Response Plan Implementing Procedure (ERPIP) 3.0, Revision 12, as one means of determining the atmospheric stability class (the backup method) used for calculating offsite dose estimates. The procedure however, requires the Delta input information to be in degrees Fahrenheit. A small error in Delta T (on the order of degrees F) can lead to incorrect stability class determinations ,

resulting in a factor of ten difference in the offsite dose projec-

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tion. The inspector discussed this item with the Electrical & Con-

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trols Surveillance Coordinator and later with representatives of the

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licensee's Electric Test Group, who has responsibility for this l

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instrument. The inspector reported the problem to the Emergency Planning Supervisor (EPS) who stated he would take action to correct the problem No violations were identifie . Events Requiring Prompt Notification The circumstances surrounding the following events requiring prompt NRC notification pursuant to 10 CFR 50.72 were reviewed. For those events resulting in a plant trip, the inspectors reviewed plant parameters, chart recorders, logs, computer printouts and discussed the event with cognizant licensee personnel to ascertain that the cause of the event had been thoroughly investigated; identified, reviewed, corrected and reported as

required.

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At 1:35 a.m. on September 19, during surveillance testing of #11 diesel generator, fuel oil began to spray out of the #10 (south) fuel injector onto the exhaust manifold. A small fire started. An opera-tor en station quickly shutdown the diesel and extinguished the fire with a CO2 fire extinguisher. No damage was done by the fire. The failed component (nozzle holder) was replaced, and the diesel was declared operable at 5:10 a.m. on the same day. Further investiga-tion showed that a crack had developed on the nozzle holder which evidently propagated to a point where fuel oil was allowed to escape from it. The licensee plans to conduct a metallurgical examination of the failed component and inspect similar components in spare parts i

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storage in an attempt to identify the root cause of failure and ensure the problem was isolated to the one nozzle. The NRC will

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follow licensee actions to identify / correct the root cause of failure (IFI 317/85-24-01).

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At 7:15 a.m. on September 30,1985, Unit 1 tripped from 100*.' power due to an apparent loss of load conditio Plant systems responded l

properly following the trip, and the plant was quickly stabilize Thc exact cause ,of the loss of load could not be determined. The resident inspectors followed the licensee's post trip review and troubleshooting activities.

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t A turbine control panel annunciator indicated that the cause of trip was a high level condition in at least one low pressure feedwater heate For such a trip to be initiated, two level switches ("Hi" and "Very High" i level) in a given feedwater heater must actuate. Prior to the trip the

"Hi" level switches in four feedwater heaters were actuated. The "Very i High" level switches are monitored by the plant computer. In this case, '

however, the plant computer did not show actuation of any "Very High" level switc !

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l The annunciator of the turbine control panel cannot be reset until all l trip initiating signals are cleared. The feedwater heater high level i alarm could not be reset following the trip until the metal caps were j removed from the level switches, suggesting a possible ground proble ! Both the licensee and the inspector independently theorized that a ground j may have developed in one of the "Very High" level switches which, coupled l with a pre-existing partial ground on the associated D.C. bus, could have  !

l created a current path around the "Very High" level switch. This theory i would explain why the computer did not sense closure of a "Very High" j level switch. Other possible causes were investigated also. The licensee ,

veri,fied proper operation of the level switches and replaced the caps. No i J grounds could be detected in the level switches. Due to an internal com-

! munications problem, the licensee did not perform a planned test whereby a <

level switch would be intentionally grounded to see if a trip signal

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resulted. The licensee installed brush recorders in several locations as an aid in determining the cause of any possible repeat events. The plant

was returned to power operation at 8:30 p.m. on September 30. The inspec-l tor recommended to the General Supervisor, Electrical & Controls (GS,E&C) l j that troubleshooting continue on a high priority basis to correct the ,

j partial ground condition on the D.C. bus (#11) and that, in the event of a

! future plant shutdown, that the intentional " level switch grounding test"

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noted above be considered. The GS,E&C stated ground isolation procedures t

have been and will continue to be conducted on a high priority basis and '

] that the grounding test would be considered during plant shutdow !

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No violations were identified, Observations of physical Security )

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Checks were made to determine whether security conditions met regulatory

requirements, the physical security plan, and approved procedures. Those ,

checks included security staffing, protected and vital area barriers, vehicle searches and personnel identification, access control, badging, j and compensatory measures when required.

I During this period the resident inspectors requested the licensee to 1 evaluate whether portions of safety related systems protruding out of I specific vital areas should be enclosed, caged in or provided with additional safeguards. Later during the period these concerns were j identified to NRC security inspectors during the performance of Inspection

Report 317/85-26; 318/85-24. Details are further discussed in the

aforementioned report.

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No violations were identifie . Review of Licensee Event Reports (LERs)

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l LERs submitted to NRC for review to verify that the details were clearly i reported, including accuracy of the description of cause and adequacy of i l corrective action. The inspector determined whether further information '

was required from the licensee, whether generic implications were indi-

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cated, and whether the event warranted onsite followup. The following ,

j LERs were reviewed.

! r LER N Event Date Report Date Subject  !

Unit 1 i

i 85-08 08/06/85 09/05/85 Reactor Trip caused by

! Motsture Separator High T

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Level i '

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) 85-09 08/06/85 08/29/85 Reactor Trip on Low i Steam Generator Water +

Level, Low Power and

. Feed System in Manual

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85-10 08/07/85 09/03/85 Reactor Trip caused by j Improperly Set Main

{ Turbine Thrust Bearing

! Unit 2 .

85-07 06/26/85 07/25/85 Failure to Perform l

! Required Surveillance on  :

l Noble Gas Monitor j

( 85-08 07/24/85 08/23/85 i

Failure of #21 MSIV to j Fully Close During Surveillance Testing 4 No violations were identified.

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Plant Maintenance The inspector observed and reviewed maintenance and problem investigation i activities to verify compliance with regulations, administrative and main-

! tenance procedure, codes and standards, proper QA/QC involvement, safety i

tag use, equipment alignment, jumper uso, personnel qualifications, radio-

logical controls for worker orotection, fire protection, retest require-l ments, and reportability per Technical Specification The following

activities were included.

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MO#205-222-3818, Rebuilding of Spare RCP Seal observed on September !

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3, 198 i

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PM-2-50-E-A-1, Reactor Trip Switch Gear Preventative Maintenance on lI TCB-1-9 observed on September 19, 198 ,

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MO#205-259-486A, Branch Connection Weld Repair on Salt Water Piping i

! Instrument Root Valve 1 SW-1071 observed on September 25, 198 l

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FTE-57, Reactor Trip Circuit Breaker and Cubical Inspection observed !

on September 19, 198 ,

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MR-E50080, 12 Emergency Olesel Generator Jacket Cooling Pressure [

j Switch observed on September 18, 198 , Reactor Trip Breaker UV_ Device i

i Section 8 of Inspection Report 50-317/85-15, 50-318/85-13 discusses l 1 problems experienced by the licensee with separation of laminated sections i of the armature in the UV device. During this inspection period the l licensee notified the vendor (GE) and other utilities of this proble { This item is being considered by the NRC for possible issuance of an IE

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program _ Upgrades The inspector reviews-d the status of several maintenance related upgrade

! activities described in previous inspection report In the areas of fuse coordination and control (Inspector Follow Items [

84-07-02 on Unit I and 82-27-02 on Unit 2), the licensee has developed a j i computerized load listing which includes designation of proper i

{ type / size / location of fuses for vital AC and DC equipment. This listing l i

is currently being reviewed by the plant staff for identification of -

) possible errors. Following this review, the listing will become a l controlled document. The load listing will be used to upgrade the list of

components affected by losses of power including Abnormal Operating Proco-

{ dure AOP-7 (Loss of Power to Class IE and Non-Class IE Busses). From a

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maintenance standpoint this listing should provide a readily accessible reference for determining proper replacement fuses and if used properly, minimize strictly " replacement in kind" practices. A verification of

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! plant fuse coordination is underway, The individual assigned lead i i

responsibility was on medical leave of absence, and, therefore, the  !

i inspector was not able to determine the extent of progres (

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The Itcensee engineering group is continuing work on developing instrument

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loop drawingsf which will assist technicians in quickly identifying loop components without having to refer to multiple prints l and/or references. By the end of 1985, they expect to complete 300-400 of j some 600 safety related loop In total, the effort will generate 1500-1800 loop drawings,

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l A mechanical maintenance procedures task force has recently been formed to ,

correct known procedure deficiencies and draft new procedures where l

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needed. The task force is made up of a cross section of maintenance l

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foremen, a QC inspector, an engineer and an engineering technician. The l effort is expected to last at least a year. In fact, it may become a permanent staff functio This effo-t should significantly upgrade j maintenance procedure ;

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The licensee is developing software for their Integrated Corrective Action Program (ICAP) to identify plant problems / trends. This system will track l component failures and help determine root causes of those failures which establish a trend. It is anticipated that this system will be usable in about nine months.

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l Reactor Coolant Pump Seal Maintenance On September 3, 1985, while observing the rebuilding of a Reactor Coolant

!~ Pump (RCP) seal package (Procedure RCS-21, Revision 5), the inspector noted that the stationary carbon face for one of the seal stages was installed incorrectly (upside down). The inspector pointed this out to 4 the lead mechanic and the QC inspector. Because the stage is assembled in [

] an inverted position, the nomenclature on the sides of the carbon face .

J (stamped " front" and "back") is confusin !

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The procedure provided adequate guidance in this area. The problem  !

appeared to be training related. The inspector reviewed the training record for the lead mechanic but could find no indication of training on j seal rebuilding. The inspector discussed this with the General

! Supervisor, Maintenance and Modifications (GS,MAM). After additional

, review, the GS, M4M determined that (1) the mechanic had previously worked j en seals but not in a lead capacity, (2) the individual had received only sporadic training on RCP seals, and (3) the foreman assigned the mechanic

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to the lead job because he, by recollection, mistakenly thought the mechanic had previously acted in that capacity. The GS,M&M stated that he was preparing a request for vendor training on RCP seals and other selected plant components. Additionally, he stated that they will,

through the procedure writing task force noted above, establish

] prerequisites in procedures which i.clude necessary personnel

training / qualifications. Those qualifications will correspond with

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training provided by the established maintenance training program. This l item was also discussed with the Plant Superintenden i I Licensee efforts to establish controls to assure that only properly qualified personnel are assigned lead responsibility for maintenance actions will be followed by the NRC (IFI 318/85-20-01). ,

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. Review of Completed _ Maintenance t

i The inspector reviewed documentation associated with six completed l maintenance activities. No unacceptable conditions were identified l

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i RCP Motor Shaft

During the period the licensee continued overhauling a spare RCP motor

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which had been removed from Unit I during the Spring 1985 refueling

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outage. The licensee reported that the motor shaft inadvertently dropped several inches during handling and contacted the floor. This was i apparently caused by a failure of maintenance personnel to precisely follow the procedure. No apparent damage was done. The shaft was shipped off site for further inspection for damag Weld Repair to Salt Water piping On September 18, the inspector observed a weld repair at an instrument !

branch line connection to the #12 Salt Water Header (Maintenance Order

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205-259-486A). The inspector later reviewed associated welder '

qualifications, the governing welding procedure, and applicable industry l codes to ensure the weld was properly performed. No unacceptable

! conditions were identified. The QC inspector was well qualified to inspect this activity in that he had previous experience as a nuclear

welde l 4 L

, No violations were identifie ; Surveillance Testing I

The inspector observed parts of tests to assess performance in accordance with approved procedures and LCO's, test results (if completed), removal i

! and restoration of equipment, and deficiency review and resolution. The !

j following tests were reviewed:

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STP #0-29-1, CEA Partial Movement observed on September 23, 198 .

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STP #M-211-2, Secondary CEA Position Display Out of Sequence Alarm Check observed on September 23, 1985.

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During a review of "STP-0-29-1, CEA Partial Movement" test, the Procedure J Review Group (tasked to ascertain that procedures fully meet all TS i requirements among other things) questioned whether all portions of TS 3 3.1.3.1 were being fully implemented. Technical Specification 4.1.3.1,

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the "CEA Motion Inhibit" surveillance, requires that CEA Motion Inhibit be j demonstrated at least once per 31 days by a functional test which verifies j that the circuit maintains the CEA group overlap and sequencing require-

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ments of specification 3.1.3.6 (tested by STP-M-211-2), and that the cir-cuit also prevents any CEA from being misaligned from all other CEA's in

] its group by more than 7.5 inches (tested by STP-0-29-1).  !

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The review by the Procedure Review Group determined that the CEA Motion

] Inhibit circuit is fully tested and demonstrates Control Motion Inhibit J

(CMI) operability by a functional test of the circuit during STP-0-29-1 i which provides an actual Control Element Inhibit when a four inch deviation between any

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CEA and its group position occurs. Both the Deviation Alarm and Control Motion Inhibit (CMI) alarm are verified along with demonstrating the (

i inability to move the Control Element as required by the TS. However, i STP-M-211-2 " Secondary CEA Position Display Out of Sequence Alarm Check" l verifies that the group overlap and sequence requirements are met by verifying only that the out of sequence contact in the CMI control circuit ,

actuates under varying voltage conditions (picks ups and drops out) and '

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! also verifying the out of sequence alarm actuates. It does not check that ;

the CMI alarm actuates nor demonstrates the actual CMI operable by a

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functional tes i The licensee has revised STP-M-211-2 to verify the CMI alarm actuation,

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and to verify the voltage at the CMI relay as well as checking the out of ,

i sequence alarm. The Instrument and Control Supervisor also stated that a !

! TS amendment request is under development to revise the wording of the TS surveillance requirement 4.1.3.1.

I The inspector reviewed the surveillance and the applicable schematic

diagrams of the CMI circuit to verify that the CMI circuit was being

] functionally tested once per mont !

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i No violations were identifie l

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10. Meetings with Public Officials 3 i On September 13, 17, and 19, 1985 the inspectors met with the Civil i Defense representatives of Calvert County, St. Mary's County and

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Dorchester County respectively. Discussions involved emergency preparedness support by the licensee, resources, communications, training, cooperation, attitude of the surrounding public and any unresolved '

concerns regarding the nuclear unit '

Each county representative provided positive / favorable responses to each

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of the topics above. The representatives indicated that the surrounding

] public constituents appeared to favor or display a neutral feeling toward

! the existence of the plant and the potential effects during an emergency.

) The inspectors observed each county's Emergency Operations Center and

attendant communications. Each meeting appeared beneficial to both the i

county and the NRC representative . Annual Emergency preparedness Exercise '

On September 10, 1985, the licensee conducted the Calvert Cliffs Annual '

i Emergency Preparedness Exercise. Both State and local governments i

! participated. One resident inspector participated in the exercise, and 1 the second inspector acted as an observer along with other Region I and l NRC consultant personnel. The media informed the public of this exercise.

The Public Notification System was activated. Further details are provided in Inspection Report 317/85-25; 318/85-22.

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1 IE Bulletin Followup The inspector reviewed licensee actions on the following IE Bulletin to

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determine that the written response was submitted within the required time .

i period, that the response included the formation requested including i i adequate corrective action commitments, and that the licensee management !

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l had forwarded copies of the response to responsible onsite manag2 men '

The review included discussions with licensee personnel and observations

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and review of the item discussed below.

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IEB 80-11. On July 18, 1985, the NRR staff informed the licensee ;

that they had completed their review of licensee IE Bulletin 80-11, 7 Masonry Wall Design, submittals (Safety Evaluation dated November 21, '

l 1984 and Supplement dated July 18,1985). The licensee's response to '

i the bulletin was found to be acceptable and provided reasonable

! assurance that all safety related masonry walls will withstand the ,

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specified load conditions without impairment of wall integrity or the

! performance of the required safety function. The inspector toured -

! the Auxiliary Building and selected eleven block walls as a sample ,

l group. He then confirmed, with the licensee's engineer responsible j for the IEB 80-11 effort, that these walls has been included in the

! analysis program. All but four walls were included in the IEB 80-11 l effort. Those four walls had been subsequently added as shield walls i

] under Facility Change Request FCR 80-100 The inspector confirmed l 1 that those shield walls had been designed to meet or exceed the '

l requirements for walls included in the IE8 80-11 review. No

) unacceptable conditions were identifie This bulletin is close !

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13. Radiological Controls j{ i l

j Radiological controls were observed on a routine basis during the l

reporting period. Standard industry radiological work practice :

l conformance to radiological control procedures, and 10CFR Part 20 l i requirements were observed. Independent surveys of radiological '

i boundaries and random surveys of non-radiological points throughout the r facility were taken by the inspecto j No inadequacies were identifie , f

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1 Fuel Shipment J

During this period the licensee, working with the Department of Energy (DOE), shipped one fuel assembly off site to the DOE Material  !

i Characterization Center (operated by Pacific Northwest Laboratories, PNL) ,

j for distribution to repository experimenters. This work is being done to t i assist 00E in the development, design, and construction of fuel storage !

repositories and storage medium I i

j During this shipment the title to the fuel was transferred to DOE prior to l the fuel leaving the site and therefore transportation of the shipment (

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, would be performed under DOE Regulations. Although notification is not !

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required under DOE Regulations for this shipment, DOE agreed to notify, by f

telephone, each State the cask would pass through, and provide the minimum j

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information necessary to maintain the confidentiality and safeguard ,

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j Resident inspectors observed activities associated with the movement of '

fuel within the Spent Fuel Pool, crane loading and interlocks, and the loading of the fuel in the Type NLI 1/2 cask. This was performed in accordance with FH-33, Revision 2 " Fuel Handling Procedures for Use of .

Spent Fuel Shipping". Witnessing of licensee surveys and independent }

l surveys of the cask prior to leaving site were performed by the inspec- i i tors. Radiation levels as measured by the inspectors were much less than ,

the limits imposed by DOE requirement I

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No violations were identifie !

i l i 1 Licensee Action on NUREG-0660, NRC Action Plan Developed as a I j hesult of the TNI T d dident The NRC's Region I Office has inspection responsibility for selected j action plan item These items have been broken down into numbered i

! descriptions (Enclosure 1 to NUREG-0737, Clarification of TMI Action Plan  !

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Items). Licensee letters containing commitments to the NRC were used as a basis for acceptability, along with NRC clarification letters and inspector judgmen The following items were reviewe t i '

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Item I.C.1 Short Term Accident and Procedure Review. This item has

! been addressed in Inspection Report 317/80-05; 318/80-08. The l l licensee has completed all aspects of this item except implementation [

and training of the revised symptomatic procedures. The procedures have been and are currently in the Control Room for operator  ;

, familiarity, and training is in progress. A revised due date for l

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this issue has been established as December 31, 1985, by a Confirma-i tory Order to the licensee dated July 16, 1985. This item remains  ;

} ope I

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Item !!.B.1 Reactor Coolant Vent System. This item was addressed in t Inspection Report 317/82-05; 318/84-07. The system is currently 1 acceptable and considered closed. Additional items associated with

! the system are as follows:

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i (1) Emergency procedures for operation have not been finalized in the new ,

I symptoms format utilizing the Owners Group Emergency Guidelines '

(tracked under Item I.C.1). Previously established procedures cur-

, rently exist for operation of the system. This item will be followed l under I.C.1 due December 198 J~

(2) On September 4, 1995, concerns regarding a LOCA and/or Personnel

$afety during an unintentional lifting of the solenoid operated pilot  !

valves were discussed between the Senior Resident Inspector, and the Licensee Project Manager and representatives of Reactor Systems ,

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Branch, NR The size of the RCS vont line (1/2 inch) is such that a i (

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, single charging pump has the capacity to make up for the volume lost should the two in series solenoid valves inadvertently open. This alleviates the concern during a small break LOCA. The other concern was regarding personnel safety during inadvertent venting. The RCS t Head Vent at Calvert Cliffs is routed directly to the Quench Tank which provides a closed volume. This alleviates the personnel hazard which exist at plants where the system is vented to Containment atmosphere.

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11.8.2 Plant Shielding. This item was addressed in Inspection Report i 317/84-05 dated June 25, 198 This report found this area j acceptable except for a small section of tubing from the Post j Accident Sampling Station PASS which was identified to be a potential

cause for radiation scattering (84-05-01). The inspector reviewed a

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draft evaluation entitled " Evaluation of Radiation Doses Associated with the CE System for Post Accident Analysis for Calvert Cliffs

Nuclear Power Plant" performed by J. Stewart Bland Consultants In The evaluation stated that radiation scattering / shine from the Post

, Accident Sampling System (PASS) would be in the order of 2.171 r/h during use after the defined accident. The evaluation further states, sources for this determination include direct dose from the J PASS skid behind the shield wall, shine dose from system operation,

! and direct dose from the HPGP lines (Germanium Detector). The draft i

evaluation appeared to include the dose from the six inch portion of

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the PAS $; however, this aspect of the shielding of the PASS during

' use was also reviewed by NRC radiation specialist during the specific review of the Post Accident Sample System (Inspection Report 317/85-16; 318/85-14). Acceptability of the shielding issues regarding the PASS are addressed and tracked in the aforementioned repor This item is considered closed under the residents tracking of TMI related items.

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II.B.2.(3) Plant Shielding (Equipment Qualification). This was

! addressed in Inspection Report 317/84-05. Subsequently, additional inspections have reviewed equipment qualifications in Inspection l

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Report 317/84-27 and the inspection of the Post Accident Sample ~

System Inspection 317/85-16; 318/85-14. Together these inspections i

have encompassed all aspects of Plant Shielding. This item is close ,

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II.F.2.3 Instrumentation to Detect Inadequate Core Cooling (Level

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' Instrumentation). Letters from Baltimore Gas and Electric to the NRC, J. R. Miller, dated October 26, 1983 and April 10, 1984 provide I both a schedule to install the Reactor Vessel Level Monitoring System >

i (RVLMS) and a description of the syste The Combustion Engineering Heated Junction Thermocouple System (HJTC), consists of (2) separate channels each containing (2) sensing

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probes, signal processing equipment and an operator interface. Eight

, (8) HJTCs are mounted in each of the (2) separate probe assemblies

which are located in the upper guide structure installed in a vacant i

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part-length Control Element Assembl The probe assemblies use the difference in the heat sink characteristics of water and steam to ascertain the water leve The schedule for full implementation of the RVLMS is June 1987 for Unit 2 and June of 1988 for Unit 1. The inspector reviewed the Safety Analysis for the FCR 80-010 and had no unanswered concern II.K.3.(1) Auto PORV Isolation. This item was addressed in Inspection Report 317/81-17. This report stated that the licensee submitted a letter to the NRC dated August 11, 1981 which concluded that automatic PORV isolation is not necessary at Calvert C1tff The NRC reviewed this information and in a Safety Evaluation Report to the Itcensee dated October 12, 1983 concluded that the existing system installed met the item II.K.3 requirements. This was based on: accurate PORV indication, emergency power being supplied to the PORV's and their associated block valves, and operators being trained to appropriately respond to available indicator The inspector reviewed the above items to ascertain that, in the inspector's view, the PORV indication was accurate and that operators were trained in this area. The power supplies were verified to be from a vital buss. This item is close II.K.3 (5) Auto Trip of Reactor Coolant Pumps (RCP). The licensee submitted a letter to the NRC dated August 11, 1981 stating that a system to automatically trip the RCPs is not warranted at Calvert Cliffs. Additional correspondence to the NRC from the Combustion Engineering Owners Group dated July 29, 1982 recommended that two pumps be tripped during a depressurization that causes a Safety Injection actuation, and that the additional two pumps be tripped upon confirmation of a Loss of Coolant Accident (LOCA). Several meetings and much correspondence between the NRC and BG&E occurred since these initial letters. Currently the NRC's review is nearing conclusion. A Safety Evaluation Report is forth coming in the near future. The licensee has been responding to the NRC's concerns as they are generated. Currently, the licensee's procedures require the operators to leave two pumps on and trip two pumps off. This item remains ope II.K.3.(25) Reactor Coolant Pump Seal Integrity Following Loss of Offsite Power. This item was previously addressed in addressed in Inspection Report 317/82-16. Subsequently, many discussions and much correspondence has transpired between the licensee and the NRC. The licensee continues to maintain that the need for compunent cooling water (CCW) flow or automatically starting the CCW pumps is not required to insure RCP seal integrity at Calvert Cliffs because of the design of the pum The NRC in a letter to BG&E dated April 23, i

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2 1985 requested additional information in order to support the acceptability of the licensee's proposed resolution of the issu ! This item remains ope '

16. Review of periodic and Special Reports j

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: i

, Inclusion of information required by the NRC; test results and/or j supporting information; consistency with design predictions and

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performance specifications; adequacy of planned corrective action for

! resolution of problems; determination whether any information should be i

classified as an abnormal occurrence, and validity of reported  :

information. The following periodic reports were reviewed

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June, 1985 Operations Status Reports for Calvert Cliffs No. 1 Unit '

j and Calvert Cliffs No. 2 Unit, dated July 16, 198 . <

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July. 1985 Operations Status Reports for Calvert Cliffs No. 1 Unit  !

and Calvert Cliffs No. 2 Unit, dated August 12, 198 ,

j 17. Exit Interview ,

Meetings were periodically held with senior facility management to discuss

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the inspection scope and findings. A summary of findings was presented to

)I the licensee at the end of the inspectio ,

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