IR 05000317/1987006

Insp Repts 50-317/87-06 & 50-318/87-06 on 870301-0413.No Violations Noted.Major Areas Inspected:Facility Activities, Routine Insps,Operational Events,Shutdown Cooling Sys Branch Line Cracking,Maint,Surveillance & Physical Security

ML20215L204
Person / Time
Site:	Calvert Cliffs
Issue date:	04/30/1987
From:	Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20215L198	List: IR 05000317/1987006 ML20215L194
References
50-317-87-06, 50-317-87-6, 50-318-87-06, 50-318-87-6, NUDOCS 8705120134
Download: ML20215L204 (14)

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' U. S. ' NUCLEAR ' REGULATORY COMISSION

REGION I

Docket / Report:-50-317/87-06' License: DPR-53

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50-318/87-06 DPR-69 Licensee: Baltimore Gas and El'ectric-Company Facility: Calvert Cliffs Nuclear Power Plant, Units 1 and 2

' Inspection At: .Lusby, Maryland Dates: March 1 - April 13, 1987

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LInspectors: .T. Foley, Senior Resident Inspector D Trimb e, Resident' Inspector _

Approved by: # ~ b. h 4

.E. E. Tr $p, Chief, Reactor-Projects Section 3A /date-Summary: March 1 - April 13, 1987: Inspection Report 50-371/87-06; 50-318/87-06

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Areas' Inspected:-(1) facility activities,-(2) routine inspections, (3) operational

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events, (4)- shut down cooling system branch line cracking, (5) cracking of. control element assemblies, (6) secondary piping inspection program,.(7) protruding re-taining pin on reactor vessel stabilizing lug, (8) maintenance,.(9) surveillance, (10) radiological controls, (11) physical security, (12) Licensee Event Reports,

and (13) reports to the NR Inspection hours. totalled 202 hour0.00234 days <br />0.0561 hours <br />3.339947e-4 weeks <br />7.6861e-5 months <br /> Results: The Updated Final Safety Analysis-Report (UFSAR) does not indicate'that the-quench tank serves.a nuclear safety-significant function; however, the inspec-

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tor noted that, prior to the quench. tank rupture disk failure,- the tank was not being operated as described in the UFSAR and may have been ineffective upon demand.-

The rupture disk failure event also showed a weakness in the licensee's (and per-haps the industry's) understanding of the-effects of steam leakage on safety valve performance (see Sectio'n-3 for details). A crack was identified in a low pressure-safety injection system (LPSI) relief valve branch line. It is important that the root cause of failure be identified and corrected in that the crack occurred in a section of piping common to both LPSI loops which is~not designed to accommodate passive failure (see Section 4 of this report). No violations were foun .

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DETAILS Within 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 Unit 1 At the beginning of the period, Unit 1 had been operating 23 days since the last shutdown. On March 10, the reactor coolant quench tank rupture disk ruptured due to a leaky pressurizer safety valve. The unit was subsequently shut down, the safety valves replaced and the pressurizer vent valves repaired (described in Inspection Report 87-01). The unit returned to power operations on March 15. During the week of March 23, NRC regional specialists reviewed environmental qualification outstanding items and observed apparent inade-quacies in the program. Routine operations continued until April 1, when the licensee determined that their environmental qualification program required improvements and the unit was shut down to correct discrepancies. The licen-see was requested to meet on April 6, 1987, with the NRC staff at Region I to discuss their rethods for ensuring conformance with 10 CFR 50.49 prior to resuming power operations. Immediate corrective actions were initiated. The unit plans to return to power operations after requesting concurrence of-Region Unit 2 On February 28 the unit tripped due to a failure in the lead-lag portion of the feedwater control system. This is described in Inspection Report 87-0 On March 2, the unit returned to power operations. On March 13 the unit shut down to commence its Ten-Year In-Service Inspection and Refueling Outag Major activities consisted of: (1) defueling the reactor, (2) examination of reactor vessel and its internals, (3) steam generator eddy current testing, (4) replacement of secondary system degraded piping, (5) replacement of the main steam isolation valves, (6) refurbishing the main turbines, and (7) major upgrades of the plant computer including installing the Safety Parameter Dis-play System hardware. On March 27, it was determined that both steam genera-tors would require inspection of 100% of the tubes in each generator. This was due to more than 1% of the initial sample of tubes inspected reaching the plugging limi On March 30 the unit was defuele During the inspections of the control rod assemblies, cracks were noted in the lower portion of the center fingers of three assemblies (further details are included in this report). On April 8, reactor vessel weld inspections revealed an indication in a vertical weld in the belt line region of the vesse An NRC specialist inspector examined the licensee's actions regarding this and steam generator eddy current testing during the week of April 6. Further examination of the indication revealed

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it to be a slag inclusion within the allowable tolerance provided by the ASME Code. On April 10, a retaining pin on a reactor stabilizing lug was noted to be in a protruded position (Detail 7 in this report).

- Review of Plant Operation - Routine Inspections Daily Inspection During routine facility tours, the following were checked: manning, ac-cess control, adherence to procedures and LCO's, instrumentation, recor-der traces, protective systems, control room annunciators radiation monitors, effluent monitoring, emergency power source oper, ability,. con-trol room logs, shift supervisor logs, and operating order No unacceptable conditions were note Biweekly and Other Inspections During plant tours, the inspector observed shift turnovers; the use of radiation work permits and Health Physics procedures were reviewed. Area radiation and air monitor use and operational status was reviewed. Plant housekeeping and cleanliness were evaluate Steam Generator Eddy Current Testing With Unit 2 shut down (Mode 6) for a refueling outage and steam generator (SG) eddy current testing in progress, on March 26, 1987, the licensee reported that inspection results to date exceeded the Technical Specifi-cation (TS) surveillance threshold for classification as Category C- A C-3 category means that more than 10% of the total tubes inspected are degraded or more than 1% of the inspected tubes are defective. Three

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percent (256 tubes) of the total number of tubes are required to be in-spected on each SG. At that time, six tubes on SG21 and four tubes on SG22 had been found to be defective (exceed the plugging limit). In this situation, TS require 100% inspection of all tubes in each SG. These results were not unexpected since the licensee purposely concentrated the inspection on tubes with previously identified imperfections and on tubes in areas of the SG where problems were anticipate Further inspection of the licensee's eddy current testing program was conducted by an NRC specialist inspector during the week of April 6, 1987 (Inspection Report 318/87-10).

t Breakage of Lifting Sling L

L On March 24, 1987, a nylon sling (rated for 8 tons),,used for moving com-

! ponents such as the upper guide structure lift rig and core support lift l rig, broke during removal of the upper guide structure (UGS) tripod assembly from the upper VGS lift rig. The UGS lift rig was installed l

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. 4 on the UGS at the time and the UGS was outside the reactor vessel resting in the refueling cavity lay-down area. The tripod assembly weight was less than the rated load for the slin Nylon slings are not periodically load tested by the licensee. Instead, they are visually inspected at regular intervals for signs of wear or degradation. The sling that broke had been recently inspected. This type of nylon sling is used to move the UGS lift rig over the vessel and install the lift rig onto the UGS. Nylon slings are r.ot used to lift the UGS itsel The licensee investigated the event and determined that workers experi-enced difficulty in removing the tripod assembly. While trying to cor-rect the problem, they apparently caused an excessive load to be placed on the sling. Operating instructions for riggers will be upgraded to better ensure that the weight of lifted objects is known prior to lifts or that load measuring / limiting devices are used. Training on the in-cident and procedure changes will be provide The inspector encouraged the licensee to consider load testing at least those slings used to move lifting rigs over the reactor vessel. The licensee stated they would evaluate this. The NRC will review the conclusions of this evaluation (Unresolved Item 318/87-06-01).

Potential Charging System Susceptibility to Single Failure In reviewing an NRC publication, Power Reactor Events, NUREG/BR-0051, Vol. 8, No. 4, the inspector noted an event that occurred at another Combustion Engineering designed facility (Palo Verde Unit 2) which may have implications for Calvert Cliff The Calvert Cliffs charging pump arrangement is similar to that at Palo Verde. Three charging pumps are in a parallel configuration and share a common suction heade Each charging pump has a discharge pulsation dampene Each pump has a relief valve located in the discharge piping between the pump and its discharge check valve. Each relief valve re-lieves back to its pump's suction line. At Palo Verde, a bladder in an idle pump's (Pump A) discharge pulsation dampener ruptured. Later, operators noted a loss of charging flow from the running charging pump (Pump E). Attempts made to start Pump A were unsuccessful. The third pump was tagged out at the tim An evaluation was conducted by the licensee to determine how a leaking bladder in the discharge pulsation dampener of a non-running pump could gas bind a running charging pump. Engineering personnel determined through testing that the discharge pressure of a non-running pump can decay rapidly due to discharge relief valve design leakage as well as leaking drain valves. With normal gas pressure (1500 psig) in the dis-charge dampener and the discharge bladder failed, the discharge system

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pressure would decrease below the normal bladder pressure, resulting in the expanded gases reaching the pump discharge relief valve which in turn could leak the gas back to the suction of all three pump At Calvert Cliffs, credit is taken in the safety analysis report for charging flo Because the above scenario represents a case where a single failure could lead to a loss of charging system flow, the inspec-tor asked the licensee to evaluate its potential for occurrence at this facilit The NRC will review the conclusions of this evaluatio No unacceptable conditions were noted.

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3. Operational Events Pressurizer Safety Valves At 1:02 a.m. on March 10, 1987, with Unit 1 operating at full power, the rup-

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ture disk on that unit's quench tank failed. Prior to that time reactor coolant system (RCS) leakage, believed to be through the pressurizer safety valves to the quench tank, had been steadily increasing over a several week period from the detectable threshold of about 0.2 gpm to 1 ;pm immediately prior to rupture disk failur Coincident with the event, a noise spike occurred on the acoustic monitor associated with pressurizer safety valve RV200. raising speculation that a safety valve may have momentarily lifted and been the cause of the disk failure. The unit was shut down at 11:40 a.m. on March 10, and the licensee conservatively elected to do a check (a test which is not required by the NRC or code required) of the setpoints of the safety valves (using a hydroset test device) with the valves still installed in the reactor coolant system (RCS). RCS temperature was 425 F at the time of the test. Technical Specifications require the lift setpoints for the safety valves to be 2565 psia (* 1%) for RV201 and 2500 psia (i1%) for RV200. The test indicated that RV201 had an average lift pressure of 2705 psia (+5.5%

error) and RV200 had an average lift pressure of 2470.3 psia (-1.2% error).

The plant was placed in cold shutdown and the safety valves were replace The Updated Final Safety Analysis Report, Section 4.2.2.2 states the following:

"The quench tank is designed to prevent the discharge of the pressurizer relief or safety valves from being discharged to the containment. The steam discharged into the quench tank from the pressurizer is discharged under water by a sparger to enhance condensation. The normal quench tank level of 135 cubic feet is sufficient to condense the steam released from the pressurizer safety and relief valves. The steam released as a result of the uncontrolled rod withdrawal is based on no coolant letdown or pressurizer spray."

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"The water temperature rise in the quench tank is limited'to 160* F,:as-

.suming a maximum initial water temperature.of 120*F. The gas volume in the . tank is sufficient to limit the' maximum-tank pressure after the above steam release to 85 psia. The quench tank is' equipped;with-a'demineral--

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ized water supply to cool the tank after a steam discharge into i , .,!

"The quench tank can condense the steam discharged during a lo'ss-of-load incident as described in Section 14.9 without exceeding.the-rupture disk set point of 100 psig, assuming normal closing of the safety valves at the end of the incident. It is'not designed to' accept a_ continuous un-controlled safety or relief valve discharge. The rupture. disk vents to the containment atmospher psig." Normal operating pressure for the tank is. .!

- :i That same report, however, does not indicate that the quench tank. serves'a nuclear safety significant functio Priortotheevent,operationspersonnel-wereexperiencingLincreasingdiffi--

culty in compensating for the effects.of steam heating of the quench tank due to the safety valve leakage. Approximately every 30 minutes they-were cooling the tank by draining off the heated water to the reactor drain tank, sometimes venting the tank to the waste gas system, and adding cooler demineralized water to the tank. As much as 80uu gallons of demineralized water was bein added each 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> operating shift. The cooling evolution would take as much as 40 minutes. At least one operating shift would drain the tank down to the-10 inch lev'el_during the cooling sequence. That-low level would leave'the discharge sparger uncovered. Upon completion'of the cooling cycle, tank'

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D pressure would increase'at a rate of about 20 psi per hour. . Water temperature,.

as indicated by an instrument located low in the tank, would increase from about 115'F to as high as 215"F in a 30 minute perio At about 11:30 p.m. on the night of the event, quench tank temperature was approximately 115"F and tank pressure was about 25 psig, which was at-the top of-the pressure instrument indication range. Operators delayed adding de-mineralized water to the tank because an RCS leak rate check was in progres and water addition would affect the accuracy of the check. No tank cooling was performed between 11:30 p.m. and the time of the event (approximately a 1.5-hour period).

The inspector discussed the event with the operators involved and licensee engineering personnel. He also contacted the manufacturer of the safety valves. The most probable cause of the event appears to be as follows. Rup-ture disks can possibly weaken after periodic cycling (rupture disk vendors have stated this to the licensee) and rupture at a pressure lower than desig Apparently, operations personnel were having great difficulty controlling the quench tank pressure / temperature and pressure increased to a disk rupture point. A safety valve probably did not open because the valve vendor indi-cated that, if the valve had opened, it would probably have opened fully and pressurizer pressure and/or level changes would have occurred. No such changes were noted. Steam leaking through the safety valves would undergo

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. 7 an expansion process resulting in high moisture content steam (perhaps 30%

moisture) in the discharge pipe. This would probably lead to accumulations of condensate in the lines. The sudden reduction in quench tank pressure due to disk rupture could have caused the flashing of this condensate to steam and accounted for the noise spike on the acoustic monito The safety valve manufacturer indicated that operation of a safety valve with leakage equivalent to 1 gpm liquid is an unstable condition. The vendor was unwilling to predict valve performance in this kind of conditio Prior to the event, the POSRC had discussed the RCS leakage problem. Their primary concerns, however, centered on the waste problems associated with the tank cooling. Possible safety valve setpoint drift or valve instability were not strong consideration One contributing reason for the licensee living with such high leakage into the tank was that shutdown would require them to make repairs to leaking pressurizer vent valves (Technical Specification 3.4.13, action b, requires repair of these valves prior to entering Mode 2 following the next Hot Shut-down of sufficient duration), and repair parts were not immediately availabl The inspector expressed concern to the Manager, Nuclear Operations (MN0) that the quench tank had not been operated as designed and may have been ineffec-tive on demand, and that the effects of steam leakage on safety valve perform-ance were not adequately understood by plant staff and the POSRC. Stronger consideration should have been given to possible valve instability by the POSR The MNO stated that he had asked the Engineering Department to inves-tigate the effects of steam leakage on safety valve performance. Additionally, he stated that the removed safety valves were going to be shipped to a labora-tory for testing to see if the setpoints truly were out of specification or if there was an error in their in place test. This would be a first step in better understanding valve performanc The MNO stated the POSRC would give stronger consideration to possible effects of leakage on the valves in the futur The NRC Office of Nuclear Reactor Regulation asked the licensee to assess the affect on safety analyses of operation with valve setpoint outside the Tech-nical Specification tolerance of +1%.

4. Cracking in Shutdown Cooling System Branch Line With Unit 2 shut down for a refueling outage (Mode 6 operation), at 1:30 on March 24, 1987, a small leak developed in the vicinity of a socket weld of a branch line for a relief valve (2RV439) for the shutdown cooling system piping. The relief valve was located on a section of piping which is common to both shutdown cooling loops, making isolation for repair impossible without securing the normal shutdown cooling path. Fuel was still in the reactor with the vessel head remove About 11:30 p.m. on March 24, 1987, the leakage increased and appeared to be through a crack in the 1/2-inch branch line wal The crack was reported to extend about halfway around the line circumferenc ,. ,

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About. 8:00.'a.m. 'on ~ March 25, the licensee secured shutdown cooling to isolate and drain down the line for repairs. Cooling for the fuel was provided v utilizi i pool an.ng d discharging the spent' fuel cooling to'the system reactor cavity.taking suction from the spent fuel

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' The section of cracked pipe was removed, and, ,as a temporary repair, a short capped end pipe was-welded in place at the point where the branch line pene-

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tr.ates the shutdown cooling piping. The Plant Operations and Safety Review Committee (POSRC) approved the. temporary repair'in advance ~and determined that

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the relief valve was not needed for current plant conditions. The inspector:

i observed the temporary repair and examined-the section of cracked pipin .

.The^ crack appeared to have originated from the socket joint. fillet weld, (on the pipe side of_the weld), extend into the pipe wall and travel (at about

.a 45 degree. rise angle) approximately halfway around the pipe circumference.

' At the close of;the' inspection' period, the cause of theLfailure had not been

! determined.- ~ The licensee suspected that it may have been'a low cycle fatigue failure. One reason for this' preliminary conclusion was that the branch

piping did not appear adequately supported and experienced vibration. No supports existed between the branch line connection point to the shutdown L cooling ~ piping and a point approximately 8 feet downstrea A similar relief

line on Unit 1 is of a different configuration and has a support close to the p ._ point where the branch line joins the shutdown cooling lin The-licensee plans to add an additional support to the Unit 2 branch line.and restore line' relief capability prior to reloading fuel into the reactor vesse m Licensee personnel recall that a similar failure may have occurred at this

.. location approximately 7 years ago. The licensee has initiated a search of F the. maintenance' history to review the details of that failure. Understanding-the root cause of this failure is important for_the following reasons:

n '(1).this piping is used for both shutdown cooling and low pressure safety-injection-(LPSI), (2) this se'ction'of piping is common to both LPSI loops,

and (3) the LPSI system was'not designed to accommodate. passive failur ._(However, failure-of this small 1/2-inch diameter line-would not cause LPSI

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to be inoperable.) The licensee intends to examine the failed piping at their i metallurgical laboratory. The NRC will follow-licensee action to determine-root cause of failure-(318/87-06-02). Based upon the_results of this~ analysis,

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the NRC will determine if further a:: tion is required to preclude additional

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failures at possibly. susceptible locations. The licensee plans to do inspec-

, tions for other susceptible locations. This and other corrective actions will l

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be included in a licensee event report and will be reviewed by the NR l

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During the Unit 1 refueling / ten year ISI inspection in Fall 1986, the licensee replaced all of the unit's control element assemblies (CEA) with new CEA's.

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. They performed eddy current testing and profilometry checks on the removed CEA's to check for cracking and strain in the inconel clad.

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The center finger of the CEA's is composed of a stack of inch long B4 C pellet 'The outer fingers are composed of B4 C pellets with'a silver-indium-cadmium lower tip. Higher: strain-levels are typically experienced in the center finger because.the lower 84C pellets tend to grow more with exposure to neutron flux than the~ silver-indium-cadmium tips. The upper limit used by the licentae is 1% plastic strai The examinations on the removed Unit 1 CEA's showed a crack in the lower por-tion of the clad on one element's center finger. That element had relatively high strain which led the licensee to.believe the crack was strain relate The cracked CEA had originally been used on Unit 2 and was subsequently shifted to Unit Because.many elements showed relatively low strain, the licensee planned not to immediately replace all CEA's in Unit 2 with new elements (during the cur-rent spring 1987 refueling outage) but instead, to select and use the lower strain, irradiated CEA's available from Units 1 and During the current Unit 2 outage, three more CEA's were found to have cracked center fingers and 13 other elements had partial through-wall cracks. Some of the cracking had occurred in lower strain element The licensee evaluated the possible consequences of CEA finger. crackin The cracking had not led to filger diameter growth significant enough to cause mechanical rubbing or bindiri, of the fingers with their guide tubes. The licensee stated that boron loss due to leaching is not believed to occur until approximately 50% of the B10 is depleted. A hot cell examination of a CEA~

exposed to higher fluence than the Calvert Cliffs CEA's showed an average boron depletion in the lower 8 4C pellets of 38.5%. Therefore, they did not-feel leachability was a proble ;

The licensee initiated a conference call on April 9 to NRR and Region I. They descriaed their . findings to date and stated they would not reuse CEA's with cracks or partial crack Cracked CEA's would be replaced with-low strain Unit 1 CEA's. They said they were performing a record reviw to determine if the cracked CEA's had come from a common purchasing lot which might indi-cate a manufacturing error. They will provide a follow up report on this review to the NRC. The NRC asked that the NRC be advised if a root cause determination is reached. This was the first such cracking observed in a Combustion Engineering designed facilit . Secondary Piping Inspection Program In response to a Region I Temporary Instruction (TI-87-02) regarding licensee secondary piping inspection programs, portions of the following were forwarded to the Region A secondary piping inspection program has been in effect since May 1984; how-ever, it prircipally included only two phase flow areas such as extraction steam and steam drain piping. Heater drain pump discharge piping (single-

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, 10 phase flow) was included because of problems experienced in this area at other plants. Inspection of main steam piping and main.feedwater piping downstream of the main feedwater pumps (single phase flow) was included because these j are high energy lines with significant hazard potential if failure occurre ' Main steam reheat lines were added following the occurrence of a small leak on the Unit 2 cold reheat line. Feedwater pump suction line inspections were added following the Surry event, and the Unit 1 suction line was inspected l during the recent refueling outage (no significant degradation was found in l the Unit 1 suction line). l The licensee's program concentrates on selected systems where problems had been experienced both here and at other plants. They then look at system geometry and concentrate on locations where high flow or flow perturbations-exist such as downstream of flow control devices, fluid restriction devices and in elbow Since most of the problems they have experienced have occurred where there is high moisture content steam, these locations received high priorit The licensee stated they strongly believe problems are heavily linked to piping geometry. Calvert Cliffs' program includes inspection at 2276 locations on Unit 1 and 3035 locations on Unit 2. A location can include more than one fitting and have multiple NDE sample points. One location, as a minimum, consists of a one- to three-inch grid, 360 degrees around the out-side radius of the fitting for one pipe diameter downstream of the fitting, i.e., a six-inch elbow would consist of 147 U.T. measurements, 360 degrees around and 6 inches downstrea The licensee determined that, for piping runs where they know wall thinning is very likely to have occurred, a total line replacement is more efficient than performing the prerequisite NDE examinatio In the past, Calvert Cliffs has experienced three significant piping ruptures

, (in a 10-inch MSR to heater drain tank line in the spring of 1985; in a 14-inch extraction steam line.to the #15A feed water heater in November 1984 in which one individual received minor injuries; and in a 14-inch drain line from one of the #26 feed water heaters to a #25 heater). To date the licensee has l spent $2.5 million on this program. In the-last Unit 1 outage, they replaced i

1596 feet of piping. A similar replacement is planned for the Unit 2 outag Additionally they plan to replace the Unit 2 cold reheat lines. The efforts on Unit I have resulted in a reduction in an NDE rejection rate on new loca-tions checked from 20% to 10L They believe the erosion / corrosion problem will continue throughout plant life and will require significant monitoring effort to keep it under contro Calvert Cliffs' program was identified as a INP0 Good Practic . Protruding Retaining Pin on Reactor Vessel Stabilizing Lug During the visual (video camera) inspections of the Unit 2 reactor vessel a retaining pin was noted to be protruding (approximately 0.350 to 0.431 inches)

out of a shim on the vessel stabilizing lug mounted at the 120 degree position on the vessel interior wall. There are six stabilizing lugs equally spaced circumferential1y near the bottom of the vessel. Each forms the tongue of a " tongue and groove" assembly. Double lugs (called core snubbers) are mounted to the outside of the core barrel and from the groove of the assem-

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, 11 blies. These assemblies restrain vibrational movement of the lower portion of the core support barrel which could be induced by coolant flow. Two shims are mounted on the sides of each vessel stabilizing lug and are held in place by four bolts. Retaining pins are inserted into holes in the sides of the shims which face the core support barrel and fit into holes drilled in the heads of the bolts attaching the shims to the vessel lug. The shims are peened to prevent backing out of the retaining pin The licensee discussed the problem with the vessel manufacturer (Combustion Engineering) and, based upon that vendor's recommendation, determined that the pin could be left as-found without corrective actio The following in-formation was considered in arriving at this conclusion: Sufficient clearance exists between the pin (in the protruded position)

and the opposing surface of the core snubber that there was reasonable assurance that the pin would not be broken off during reinstallation of the core support barrel. Clearance was estimated to be 0.100 inche The core support barrel is closely guided during insertion by the stabil-izing lugs resulting in little radial movement of the barre There were no indications of contact of the pin with the core barrel during barrel removal; during operation, the pin is prevented from fully backing out of the shim by the opposing surface of the core snubber. The pin is 0.875 inches long and the clearance between the shim and the opposing surface of the core snubber is 0.531 inches; if the protruding pin no longer was capable of preventing the shim at-taching bolt from backing out, that bolt's movement would be limited by physical contact with one of the lugs attached to the core barrel. This contact would not prevent later removal of the core barrel. This contact would prevent the bolt from falling out of the assembly; if the pin does fall out into the vessel, there would, in the vendor's opinion, be little likelihood of it passing through the flow skirt and the core barrel lower support structure. Additionally, the lower end fittings and retention grids of the fuel assemblies should, unless the pin broke into small pieces, prevent entry of the pin into the core re-gion; and radiation levels in the area of the pin were very high and probably would result in significant exposure to a diver who might try to reinsert the pi At the end of the inspection period the core barrel had been reinserted into the vessel, and the licensee intended to formally document the above consi-derations in the form of a safety analysis and have the POSRC review that

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-analysis. Several members of the POSRC had been apprised of the;results of-

the discussions with the vendor and were involved 11n.the' decision'to reinsert the core ~ barre . Plant Maintenance-The inspector observed and reviewed maintenance and problem investigation activities to verify compliance with regulations, administrative.and mainten-

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ance procedures,' codes and standards, proper QA/QC involvement, safety tag

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

controls for worker protection, fire protection,' retest requirements, and reportability per Technical Specifications. The following activities were included:

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. M0 #207-068-248A, Troubleshooting of Speed Control ' Circuitry for #22 AFW Pump. observed on March 13, 198 Repacking of LPSI System Valves with Chesterton Packing observed on March 18, 198 Temporary Repair of-Leak on Unit 2 LPSI System Relief Valve Branch Piping observed on March'25, 198 PM #2-24-J-R-201,-Setpoint Check for Service-Water Pressure Switch on

1. 21 Diesel Generator observed on March 24, 1987J No unacceptable conditions were note . ' Surveillance

The inspector observed parts of tests to assess performance in accordance with approved procedures and LC0's, test results-(if completed),. removal and re-storation of equipment, and deficiency review and resolution. The following

'. tests were reviewedi

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STP M-514-2, W.R.N.I Channel Calibration.

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STP M-20, Inspection of #21 Diesel Generato Eddy current testing of Unit 2 Steam Generator Tube Installation.of steam generator nozzle dams in preparation for surveil-

-lance testing of steam generator tube No unacceptable conditions were note .

, 13 1 Radiological Controls Radiological controls were observed on a routine basis during the reporting period. Standard industry radiological work practices, conformance~ to radio-logical control procedures and 10 CFR Part 20 requirements were observe The inspector observed the installation of the steam generator nozzle dam Health Physics controls were excellent. Personnel installing the dams were well-trained. ALARA principles were fully observed and personnel exposure minimized. Nozzle dam equipment was in good repair and functioned as designe No unacceptable' conditions were identifie . Observation of Physical Security Checks were made to determine whether security conditions met regulatory re-quirements, the physical security plan, and approved procedures. Those checks included security staffing, protected and vital area barriers, vehicle searches and personnel identification, access control, badging, and compensatory meas-ures when require No unacceptable conditions were note . Equipment Qualification (EQ)

During the week of March 23, 1987, an NRC inspection identified discrepancies in the licensee's EQ program. The principle deficiency noted was the presence of taped splice On April 1, 1987, the licensee elected to shut down Unit 1 to correct discre-palcies. Details of the NRC inspection will be provided in Inspection Report 317/87-07;318/87-0 The inspector monitored the licensee's corrective actions for the remainder of the inspection period (details on these actions will be provided in In-spection Report 317/87-10; 318/87-11).

13. 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 cor-rective action. The inspector determined whether further information was required from the licensee, whether generic implications were indicated, and whether the event warranted on-site follow up. The following LER's were reviewed:

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V ,~3

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y : sb '14 LER N = Event Dat'e Report Date Subject-Unit 1-87-04 '02/01/87.- 03/02/87 Reactor Trip.as a Result of Turbine Runback  ;

87-06* 03/10/87- -04/07/87

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Pressurizer Safety Valves 200 and 201-e Setpoints Out of Specification Unit-2 l 87-02 02/28/87- '03/25/87 Failure of-Lead / Lag Circuit in Feed--

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water. Regulating Valve Control. System Leads to Low Steam Generator Water Level Reactor Trip

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• Detailed examination of these events is documented in paragraph 3 of this

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inspection' repor , No-unacceptable conditions were note . Review of Periodic and Special Reports Periodic and special reports submitted to the NRC pursuantLto Technical Speci-'

fication 6.9.1 and 6.9.2 were reviewed. The review ascertained: inclusion of information required by the NRC; test results and/or supporting information;-

consistency with design predictions and performance specifications; adequacy

=of_' planned corrective action for resolution of problems; determination whether any information should be classified as an abnormal occurrence, and validity of reported,information. 'The following periodic reports'were reviewed:

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February Operating Data Reports for Calvert Cliffs No.- 1 Unit and-Calvert-Cliffs No. 2 Unit, dated March 9, 198 No unacceptable conditions were identifie . Exit Interview Meetings were periodically held with senior facility management to discuss the inspection scope and findings. A summary of findings was presented to the licensee at the end of the inspectio l

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