IR 05000317/1986019
| ML20210A091 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 01/21/1987 |
| From: | Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20210A059 | List: |
| References | |
| 50-317-86-19, 50-318-86-19, NUDOCS 8702060407 | |
| Download: ML20210A091 (23) | |
Text
.
.
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket / Report: 50-317/86-19 License: DPR-53 50-318/86-19 DPR-69 Licensee: Baltimore Gas and Electric Company Facility: Calvert Cliffs Nuclear Power Plant, Units I and 2 Inspection At: Lusby, Maryland Dates: December 1, 1986 - January 12, 1987 Inspectors: T. Foley, Senior Resident Inspector Q Trim e, Resident Inspector Approved: 8 -
/
L E. Tr 1$p, 3 Chief, Reactor Projects Section 3A 'Dat6 Summary: December 1, 1987 - January 12, 1987: Inspection Report 50-317/86-19, 50-318/86-19 Areas Inspected: (1) facility activities, (2) routine inspections, (3) operational events, (4) 10 year ISI refueling outage, (5) maintenance, (6) surveillance, (7) licensee initiatives relating to SALP, (8) environmental qualification of solenoid valves, (9) radiological controls, (10) other NRC concerns, (11) physical security, (12) reports to the NRC, and (13) licensee action on previous inspection finding Inspection Hours totalled 289 hour0.00334 days <br />0.0803 hours <br />4.778439e-4 weeks <br />1.099645e-4 months <br /> Results: Concerns regarding the maintenance of system design basis (Detail 2.c),
and possible " loop holes" within the environmental qualification program are con-sidered significant (Detail 8). Appropriate attention is being provided to these areas. Efforts to formalize a program for tracking Licensee Identified Violations is a positive initiative (Detail 2.b). Air intrusion into the Service Water System
'
discussed in Detail 12 also deserves licensee attention. Problems with the start up of Unit 1 after completion of the ISI outage did not appear to influence the licensee's well-coordinated persistent pace. No violations were identified by the inspectors.
l l
t
!
8702060407 PDR 870127ADOCK PDR 05000317 G_ . - _ , .
-
,
.
.
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: Began this period on day 38 of the unit's ten year In Service In-spection Outage. Critical path was about 2.5 days behind schedule. The licensee had requested and was granted an emergency TS change to allow refueling to be conducted without an operable diesel generator (change expired December 10) and refueling had begun on November 30. The unit continued the outage keeping close to schedule. Work activities proceeded in a systematic, harmonious, and steady manner. However, final repair of the No. 12 DG, repairs to the main generator collector and retaining ring and failure of the #118 reactor coolant pump shaft seal all contributed je to small delays (a few days each) in outage recovery activitie On December 31, the unit was refueled and ready for start up activities while awaiting resolution of the hydrogen seal and main generator bearing problem The revised schedule predicted a start up (parallel to the grid) date between
-
January 5 and 7,1987. Details of the outage activities are documented under
" Outage Activities" included herein (Section 4).
'
Unit 2: Entered the report period at 100% power and continued normal opera-tion throughout the period, exceeding 105 days of continuous operation on December 31, 198 Facility: On December 1, the Chief Executive Officer and the President of BG&E along with members of the Public Service Commission visited the plan A Health Physics Inspection by Region I specialists was conducted during the week of December 1, 198 . 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 rod positions, containment tem-perature and pressure, control room annunciators, radiation monitors, effluent monitoring, emergency power source operability, control room
<
logs, shift supervisor logs, tag out logs, and operating order Licensee Identified Violations 10 CFR 2, Appendix C. V. Enforcement Actions states that "NRC wants to encourage and support licensee initiative for self-identification and correction of problems". The resident inspectors have urged the licensee to improve their methods for self-identification of problems and estab-lish controls to formally capture and track problems that meet the guid-ance provided in 10 CFR 2, Appendix C for a Licensee Identified Violatio _ _
.
.
The following is a list of problems of a minor nature which the licensee has identified, incorporated into some tracking system, and otherwise meets the requirements of 10 CFR Event Date Nature of Violation
~
Exposure of minor * 10/18/85 Adm. Procedure CCI-800B Refuel pool drained to less than 23 feet above the Core with only one SDHX operable 12/10/86 T.S. 3.9. Failure to perform receipt survey of transported radio-active materials 11/04/86 10 CFR 20, CCI-800B Failure to obtain POSRC approval of a procedure change within 14 days 12/19/86 T.S. 6.8. These events were reviewed with the resident inspector who ascertained that the licensee's corrective actions were acceptabl * Details are discussed in Section 9 of this report, c. System Alignment Inspection Operating confirmation was made of selected piping system trains. Ac-cessible valve positions and status were examined. Power supply and breaker alignment was checked. Visual inspection of major components was performed. Operability of instruments essential to system perform-ance was assessed. The following systems were checked:
--
Unit 2 High Pressure Safety Injection System
--
Unit 1 Emergency Diesel Generator System
--
Unit 2 Service Water System *-
- For this system, the following items were reviewed: The licensee's sys-tem lineup procedure (s); equipment conditions / items that might degrade system performance (hangers, supports, housekeeping, etc.); instrumenta-tion lineup and operability; valve position / locking (where required) and position indication; and availability of valve operator power suppl Weakness in Preservation of System Design Basis Requirements During a recent walk down of the Unit 2 Service Water (SRW) system, the inspector noted that an eight inch diameter branch line supplying cooling water to the steam generator blowdown heat exchanger (SGBHX) is not automatically isolated during post accident conditions. Other branch lines supplying nonessential cooling loads, such as the turbine building supply and the Spent Fuel Pool heat exchanger lines, are automatically i
._ _ _ -
.
.
isolated. The Updated Final Safety Analysis Report (FSAR), Section 9.5.2.2, states that "during LOCI (loss of coolant. incident) both (SRW)
subsystems have identical heat loads and flow requirements. Each sub-system will cool a maximum of two (2) containment air coolers and one diesel generator".
The inspector asked the licensee if the ad6ition of the SGBHX branch line
-
(the line was added to the system in 1976 by a plant modification via Facility Change Request FCR 75-007) met the original design basis for the SRW system. He was also concerned that the branch line may not have been installed as safety related. This promptec a licensee design en-gineer to question whether the addition of the branch line could rob the containment coolers of an adequate supply of cooiirg wate The licensee promptly investigated the concern and found the following information. The SGBHX was not identified as safety related in the " red line" drawings of the Q list. However, the review of the construction work package indicated that the line and heat exchanger were installed as safety related. The SGBHX has now been added to the Q list. The addition of the SGBHX branch line without automatic isolation capability appeared not to be in keeping with the design basis. The 10 CFR 50.59 safety analysis for FCR 75-007 was very brief and did not indicate that /
any consideration was given to the possibility of decreasing SRW flow to the containment coolers. Design documentation for the modification, on file at the office of the architectural engineer (AE), included a note indicating that the designers believed that the system design basis allowed credit for immediate operator action to isolate the branch line during an accident condition. Therefore, the possibility of robbing containment cooler flow was not considered. The licensee currently acknowledges that credit for immediate operator action is not a correct design basis assumptio Scoping calculations recently performed by the AE indicated that the branch line (as designed in FCR 75-007), if operated without operator throttling of valves in the line, could reduce containment cooler flow to marginal or possibly unacceptable values. In practice, however, operators found that the branch line provided too much SRW flow to the SGBHX, and they significantly throttled the discharge valve of the heat exchanger. Therefore, adequate flow to the containment coolers was probably always availabl Fortuitously in 1977 (FCR 77-045) a three inch orifice was added to the branch line to reduce line flow without having to throttle and possibly damage the heat exchanger discharge valve: Again the safety analysis for the FCR was brief and indicated no concern for containment cooler flow. It only indicated concern for damaging the discharge valve or heat exchanger due to the high line flow. A recent calculation of SRW system flows, taking into account the SGBHX branch line with the orifice in-cluded, shows adequate cooling water supplied to the containment cooler .
.
, FCR 82-189 was initiated in 1982 and implemented in 1985. It removed the automatic Containment Isolation Signal (CIS) from the steam generator blowdown line isolation valves. Removal of this signal allows blowdown flow to continue in a post accident situation which adds an additional heat load to the SRW system via the SGBHX branch line. The safety analysis for the FCR principally addresses containment leakage (General Design Criteria 57) requirements and does not address the increased heat load on the SRW system. Recent analysis by the licensee shows that the added heat load is relatively small and can be accommodated by the SRW system in a post accident configuratio Because system function was preserved, problems introduced by the above modifications are not safety significant. They resulted because the original system design basis was not adequately understood by the de-signer (s) of a modification. They were possibly aggravated because a document principally containing the design basis (updated FSAR) was not revised to reflect that modification, thereby contributing to an inade-quate safety evaluation of a follow-on modificatio These problems highlight the need for adequate identification and pre-servation of the design basis of systems. The licensee's QA depart-ment recently audited this area; and, although the report has not yet been issued, the inspector understands that auditors identified weaknesses in the ease of access to design basis information, which can hamper design engineer The inspector discussed the issue with the Design Engineering General Supervisor. That individual stated that they recognize that improvements in documentation of design basis requirements are needed. He stated that (1) upgrades have already been made to engineering department procedures to require improved documentation for individual modification packages, (2) the QA department is scheduled to conduct an inspection modeled after the NRC's Safety System Functional Inspection (SSFI) during 1987, and (3) his department plans to do a 10% check of safety related systems to verify preservation of the original design basis through subsequent modifications. If the 10% check identifies significant problems, the sample size will be expande The inspector asked the Principle Engineer, Mechanical Engineering to consider regenerating safety evaluations for FCR's75-007 and 82-18 That individual indicated that these evaluations would be redone.
A general problem with poor quality 10 CFR 50.59 safety evaluations and poor reviews of those evaluations was noted by the NRC Performance Ap-praisal Team during a January 1982 inspection (Inspection Report 317/
82-01, 318/82-01). The licensee initiated efforts to upgrade these evaluations and significant improvements were noted by the NRC. The issue of weakness in licensee preservation of system design basis re-
.
.
quirements is unresolved pending determination of whether the SRW problem was an isolated event and assessment of the adequacy of licensee efforts to make this determination (318/86-19-01). Biweekly and Other Inspections During plant tours, the inspector observed shift turnovers; boric acid tank samples and tank levels were compared to the Technical Specifica-tions; and the use of radiation work permits and Health Physics proce-dures were reviewed. Area radiation and air monitor use and operational status was reviewe Plant housekeeping and cleanliness were evaluate Verification of several tag outs indicated the action was properly con-ducte No unacceptable conditions were note . Operation Events Leak Repairs of Unit 2 Feedwater Flow Nozzles On December 12, 1986, the licensee repaired a leak on an inspection port blind flange associated with the feed water flow nozzle for #21 Steam Generator (2-FE-1111). The repair was done using sealant injection. The unit was operating at power at the time. This was the fourth such injection repair done to this flange since July 198 Steam leakage from this nozzle was causing a drift problem in one of four transmitters providing a reactor coolant system flow signal to the Reactor Protection System (RPS). The affected RPS channel had been placed in a trip condition. (The transmitter is not required to be included in the licensee's Environmental Qualification Program.) The inspectors attended the POSRC meeting in which committee members discussed and approved the repair procedur The inspectors expressed concern to the committee and engineering staff per-sonnel that the stress loads the injection gun could potentially contribute to the joint and its associated closure bolts was not being considere Subsequently, the Manager, Nuclear Operations (MNO) and the Secondary Systems Principle Engineer indicated agreement that injection pressure l should be included in the bolt stress calculation However, apparently I
due to a communications problem within the engineering department, this additional stress was not considered, and the repair was completed on the basis of the original calculation.
l Additionally, a small amount of sealant was added to a similar flange on the i flow nozzle for the #22 Steam Generator to stop a minor leakage problem.
l In a later discussion with the MNO the inspector again expressed concern that failure to consider injection pressure appeared to be a non-conservative approach. The MNO indicated that such consideration appeared appropriate and should be included in future repair procedures.
I
_ _ -__ _ __
_ _ _ _ _ _ - _ _ _ _ _ _ _ _
.
.
Water Hammer Event On January 6,1987 a water hammer occurred in a non-safety related condensate line supplying cooling water to one of two steam generator blowdown recovery system (SGBRX) heat exchangers. The second heat exchanger is cooled by ser-vice water (SRW). Condensate flow was stopped for a period of time while blowdown flow continued; and when condensate flow was reinitiated, a water hammer occurred. Some hanger damage occurred, and a fire water system sprinkler supply header was contacted and broken by movement of the condensate lin A licensee review of governing operating procedures showed a weakness in alerting operators of and preventing water hammers in this line. The inspec-tor asked the General Supervisor, Operations (GS0) if a similar weakness ex-isted in procedures for the SRW system, which is safety related, since it would appear to also be susceptible to water hammer. The GSO indicated they would check these procedures also and make appropriate improvements. Evalu-ation/ Upgrade of the SRW procedures will be followed by the NR No unacceptable conditions were note . Refueling Outage - 10 Year In Service Inspection On December 1, 1986, day 38 of the outage, refueling the reactor had been in progress for one day. With about 22 fuel assemblies in place, two assemblies departed from the full upright (vertical) position and leaned against the core barrel with an approximate 20 degree inclination. This slowed refueling efforts and caused a two shift delay for straightening the "leaners". Re-fueling continued without any other significant occurrences until completion on December 6t As identified in Inspection Report 317/86-18;318/86-18 and addressed in detail below, the licensee applied for and received an emergency TS change (Amendment 124) providing for relief from portions of TS 3.8.1.2 and 3.8.2.2 " Electrical Power Sources - Shutdown". This was done in order to refuel the reactor while simultaneously working on No. 12 Emergency Diesel Generato Work on #12 EDG continued throughout the refueling and for several days thereafter as discussed belo On December 4th, the licensee notified the inspectors that they had identified an anomaly within the main steam line No. 12. The defect appears to be a one-half inch wide, twenty-four inch long circumferential1y wall thinning with
.86 inches remaining of .95 normal wall thickness. Details are reported under section titled " Main Steam Piping Flaw" (Section 7).
Steam generator Eddy current testing, pulling six tubes and plugging 21 tubes on No. 11 steam generator and 11 tubes on #12 steam generator was completed on about December 10. Details are discussed under " Steam Generator Tube Plugging".
____________ . .
I
.
On December 10, the reactor head was reinstalled and bolts were torqued on the 13th of December. Subsequently, after replacement of the rotating members (including the shaft and impeller) of Reactor Coolant Pump (RCP) #12A and replacement of the shaft seals for (3 of the 4) RCPs (12A and 128 and 11A)
the RCS was filled on the 20th. Plant heat up began on December 24th. On
'
December 25, RCP #118 shaft seal demonstrated indications of a failed sea The plant was subsequently cooled and drained down for a seal replacemen The seal replacement was completed on December 29, 198 Simultaneous with the above, on December 12, the licensee determined that the main generator collector end retaining ring had been reinstated in the genera-tor and non-destructive testing (NDT) of pits previously identified and ground out was not complete. (NDT had not been accomplished after grinding out the pits.) A determination was made that further examination was necessary to provide confidence that the ring was acceptable for use. The ring was sub-sequently approved for use and reinstalled on the 20th.
'
On December 29, the licensee began experiencing problems with hydrogen seal excessive leakage on the main generator. The seal was disassembled and re-placed by January 3, 1987. Minor problems adjusting turbine bearings and aligning the generator also contributed to these delays. The RCS was heated up on January 1, hydrostatically tested, and then was brought critical on January 3rd after testing main steam safety valves. Low power physics ac-ceptance testing was completed by the 5th. On the 5th of January the genera-tor experienced a stator liquid cooler leak which was repaired, then while rolling the turbine, high temperatures were noted on the No. I bearing of the high pressure turbine. (This bearing had not been disturbed since the pre-vious refueling.) It was subsequently determined that the bearing was dam-aged by dirt and necessitated it being sent to General Electric for repair On January 10th, the bearing was received and reinstalle The licensee again brought the unit critical and rolled the turbine. When at synchronous speed a check of bearing temperatures revealed that the Main Turbine Thrust Bearing temperature was indicating 50 degrees Fahrenheit higher than the previous start up and other reference data. The licensee shut the turbine down and inspected and buffed the thrust bearing. Minor amounts of dirt were also removed. The bearing was reinstalled on January 12, and the unit again commenced power operation at 10:20 a.m. on January 12, 198 Steam Generator Tube Plugging As discussed in Inspection Report 317/86-18;318/86-18, Technical Specification 4.4.5 surveillance inspections resulted in the licensee performing a 100%
inspection of the steam generator tubes for Nos. 11 and 12 steam generator Results of the 100% inspection revealed indications of 20% or greater through wall degradation on a total of 219 tubes from the 16,981 tubes inspecte Thirty-two of these were greater than 40% degraded (plugging limit). An addi-tional 6 tubes indicating less than 40% degradation were plugged for several
_
.
.
reasons: 4 due to degradation at the upper support plate, I because of ex-panded region wear, and 1 tube plugged because it was removed for metallur-gical examinatio The 32 tubes plugged due to being greater than 40% degradated were as follows:
11 tubes were plugged in No. 12 Steam Generator 21 tubes were plugged in No. 11 Steam Generator The licensee submitted a report to the NRC dated December 30, 1986 providing additional detai .
Thermal Cracks In Shaft of No. 12A Reactor Coolant Pump (RCP)
During the current Unit I refueling outage, the No. 12A RCP was disassembled for inspection principally because the pump had been experiencing high sub-harmonic vibration while operating (see Inspection Reports 50-317/86-11, 50-318/86-11, Section 2; and 50-317/86-09, 50-318/86-09, Section 3d for dis-cussion of the vibration problems). Previously, the licensee had obtained relief from ASME Code Section XI In Service Inspection (ISI) requirements for RCP casings for the first 10 year ISI interval. As part of the relief request, the licensee committed to perform a best possible visual casing inspection if a pump was disassembled for another reason. The 12A RCP casing and rotat-ing assembly were generally found to be in very good condition. However, approximately 120 cracks, each about an inch in length, were found in the upper end of a threaded portion of the shaft just below the recirculation impeller. Eddy current testing showed the deepest crack depths to be on the order of 0.090 inches below the root of the threads with a 20% uncertainty factor. Five percent of the cracks were 0.030-0.090 inches in depth; 15% were 0.020-0.030 inches; and 80% were less than 0.020 inches. The licensee's metallurgist has classified the cracks as " thermal cracks". During pump operation large, cyclic temperature changes can occur in this area of the shaft causing thermally induced hoop stresses. The pump vendor, Byron Jackson, and B&W performed an engineering analysis that showed that the cracks would not be expected to grow more than 0.250 inches in depth. The licensee con-servatively elected, however, to install a new shaft and rotating assembl Based upon the licensee's knowledge of the mechanism causing the cracks, similar cracking is likely to be present in the remaining RCP shafts. The pump vendor concluded that there was low risk in returning the remaining three
!
pumps to service for another operating cycle.The vendor's analysis was dis-cussed in a telephone conference on January 7, 1987 between the licensee and NRC Region I office staff personnel. The analysis will be sent to the Region I office for additional revie Emergency Diesel Generator (EDG) 12 Gas Leakage Problem This inspection was made in order to observe the licensee's conduct of pre-viously reviewed test procedures to verify the correction of a major gas leakage problem into EDG 12 jacket water cooling system. This problem caused cavitation of the jacket water pump which resulted in surging jacket water
, _ _ ._. _ . _ - - __ _
.
.
pressures (high then low) with the low pressure dropping below the low pres-sure trip point which shuts down the engine. Previous history of this problem is reported in Inspection Report 317/86-16; 318/86-1 The licensee had concluded a major overhaul / rebuild of the diesel engine which
'
included: 1) replacement of Jacket water liners, gaskets, and seals, and 2) exhaust boots removal, inspection and replacement with new gaskets in order to overcome the leakage proble The inspector reviewed licensee test procedure ETP 86-21 EDG Post Ove.-haul Run-In Test and the licensee's installed gas measurement system for detecting leakage by venting the gas from the jacket water cooler top vent and from each of the twelve engine cylinder jacket water outlets into the collection heade The licensee's test approach and test methods appeared adequate for determin-ing whether the major leak had been corrected by the engine rebuild /modifica-tions. Test procedure ETP 86-21 required progressively loading the engine in incremental steps from no load to full (2500 KW) load. The engine showed no evidence of off gassing until the load was raised to 1900 KW. At 2500 KW the off gassing rate was determined to be approximately 42 liters per hou The source of the leak was not identified. The licensee then modified the -
test plan in an effort to pinpoint the leakage source by installing gas vents on the outlet of both turbo-chargers and again proceeded to sequentially and progressively load the engine. The off gassing was essentially the same as before. By venting the outlet water discharges individually from engine cylinders, from the jacket water cooler, and from each turbo-charger and then venting them collectively, the licensee concluded that the gasses appeared to be caused by the control side turbo-charger. Site chemistry determined that the gasses were exhaust gasses by .aasurement with detection tubes for CO. The licensee replaced the control side turbo-charger with a spare and again proceeded to load the unit. With the new turbo-charger off gassing into the jacket water cooling system was observed at 1300 KW. The volume of gas into the jacket water at higher loads was essentially unchanged from the pre-vious run Since the replacement turbo-charger did not resolve the problem and to locate the source of the leak, the licensee stopped the test in order to conduct extensive evaluation and planning as to how to proceed in order to pinpoint the cause of the off gassing proble The planning session led to licensee's decisions to modify the test plan to include substantial additional instrumentation, determine by gas chromatograph the C0 and 20 present in intake air, exhaust, and in off gas samples, replace cylinder liner adapter seals, isolate turbo-charger cooling by installing a separate cooling loop, isolate the jacket water keep warm loop and to test each cylinder separately by shutting off the fue Other vents were installed on the jacket water cooling discharge of each cylinder, two high point vents and the discharge of the air intercoolers and turbo-cha rger . _. . ._ - --
.
.
Running the diesel and venting each vent showed excessive gassing emitting from the air intercooler vent The licensee performed an air pressure drop test on the air coolers and found excessive leakage across the tubes of the cooler. Both air intercoolers were replaced and the jacket water cooling gas was almost entirely eliminate The licensee retorqued several adapter gaskets after removing all of the test instrumentation, then commenced performance testing. No gassing was eviden The licensee ran the diesel for several hours to satisfy themselves that they had resolved the problem. A three hour run at 2500 KW was performed followed by a one hour run at 3000 KV without operator action to satisfy Technical Specifications that the diesel was operable. After completion of this run the jacket water cooling heat exchanger was vented. Approximately 10 cc of gas or about 2 seconds of gassing was evident. The inspector witnessed this testing and venting. This is considered very little and is about the same as what the other diesels manifes Subsequently, an additional 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> run was performed at 2500 KW with no operator action (i.e., without venting). The inspector witnessed this testing cnd the venting at the completion of the test and was satisfied that the gassing problem was resolved by replacing the air intercoolers and torquing adapter gaskets around the combustion chamber The licensee has subsequently revised their procedures to require that the jacket water cooling system be vented only at the end of operating a diesel and that any significant gassing be reporte Emergency Technical Specification Change for Emergency Diesel Generator The licensee requested an emergency temporary change to their Technical Speci-fications Sections 3/4.8.1. "AC Sources", and 3/4.8.2, "On Site Power Distri-bution Systems", for Unit This temporary change for Mode 6 would allow the licensee to conduct refueling without an operable emergency diesel genera-to It expired: (1) prior to draining the refueling pool below the 23 foot t
level, (2) upon restoring EDG #12 to an operable status, or (3) at 11:59 on December 10, 1986, whichever came firs The inspector obtained a copy of Amendment No. 124 issued on November 28, 1986 to determine if the licensee was complying with the revised Technical Speci-fications and any other commitments stated therein. The major changes to the Technical Specifications were as follows:
(1) TS 3.8.1.2.a was modified to state that one 500 KV off site circuit be-tween the off site transmission network and the on site class 1E distri-bution system must be operable; l
l I
__ _. _ _ _ _ _ . _ . _ _ . . . . _ .
.
.
(2) TS 3.8.1.2.b requiring an operable EDG was replaced by requiring an operable 1000 KW, 480 VAC portable diesel generator (PDG) and an operable 69 KV off site power circuit (SMECO);
(3) TS 4.8.1.2 was changed to verify operability of the 500 KV and 69 KV off
-
site circuits at least once per shift and to verify the operability of the PDG at least once per 31 days; and (4) TS 3.8.2.2 was modified to delete the requirement to have an operable EDG and the associated action statement was modified to require estab-lishing containment integrity in accordance with TS 3.9.4 within four hours following a complete loss of off site AC powe The inspector also noted the following commitments by the licensee in the Safety Evaluation to Amendment No. 124:
, '
(1) the refueling pool temperature would be maintained below 100 Degrees Fahrenheit while the 12 EDG was inoperable to provide an adequate tem-perature margin below 140 degrees Fahrenheit for decay heat removal in the event of a loss of shutdown cooling; (2) the equipment hatch would be maintained in a vertical position rather than resting it horizontally on the structure steel supports, so that in the event of an AC blackout, hydraulic jacks could be used to close the hatch; and (3) the main steam isolation valve (MSIV) for the 11 steam generator (SG)
would be kept closed during tube pulling actions so that containment integrity was ensure The licensee was using a modified version of Surveillance Test Procedure (STP)
0-90-1, " Breaker Lineup Verification" to ensure they met the new requirements of their emergency temporary TS change. The inspector observed the perform-ance of STP 0-90-1 and concluded that the licensee was meeting the new TS requirements. The inspector also reviewed the Unit 1 Control Room Log book from October 28, 1986 to December 3, 1986 and noted that this procedure had been performed at least once per shift, as required. The inspector also re-viewed the temporary change to STP 0-90-1 that tested the operability of the PDG. The test was successfully performed on November 26, 1986, before re-fueling was commence The inspector checked the refueling pool temperature and found it to be ap-proximately 80 degrees Fahrenheit. The equipment hatch was also closed with at least four bolt integrity ensured. The licensee was also maintaining the MSIV shut for the 11 SG during tube pulling operation In conclusion, the inspector determined that the licensee was meeting the re-quirements and commitments of their emergency Technical Specification change (Amendment No. 124).
l l
l l
._ _ . . ~ , _ _ _ _ _ _ . . _ __
.
.
Outage Related Training Through discussions with operators, operations staff, procedure review and training reports, lesson plans and operator required reading the inspector ascertained that the following training was accomplished:
The Operations Training Section conducted training for both the licensed and plant operators program on Facility Change Requests (FCR) installed during the Unit 1 outage. The following FCR's were reviewe Coast Down Review for Unit 1
--
79-43 Stator Liquid Cooling Runback
-- 81-141 Herma Valves
--
16A & B Feedwater Heater Modifications
--
80-16/83-1050 N2 System
--
84-1094 Auxiliary Feedwater Modifications
--
83-1057 Core Exit Thermocouples Display System
--
84-0043 Amertap System
-- 86-116 Nitrogen and Hydrogen to the Volume Control Tank Specific simulator training sessions were conducted to reacquaint operators with the positive temperature coefficient conditions which existed during start u No unacceptable conditions were identified during review of any of the above activitie . Plant Maintenance The inspector observed and reviewed maintenance and problem investigation activities to verify compliance with regulations, administrative and mainten-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 re-portability per Technical Specifications. The following activities were in-cluded:
--
PM 1-5-E-R-6 and FTE-514KV Breaker Chec ETP-11 Post Installation Acceptance Testing of #11 and #12 Main Steam Isolation Valve Preparations for Leak Repairs of Main Feed Line Flow Nozzl M0-206-280-906 Overhaul of Main Steam Relief Valve MO-206-231-298A #12 MSIV Installatio __
- . - . - - ._ -- -
-
.
.
--
M0-206-337-298A Emergency Diesel Generator Troubleshootin PTP-1-RCS-10Y-1 10 Year ISI Hydrostatic Test of the RC No unacceptable conditions were note . Surveillance The inspector observed parts of tests to assess performance in accordance with approved procedures and LCO's, test results (if completed), removal and re-storation of equipment, and deficiency review and resolution. The following tests were reviewed:
--
STP M521-1, Unit 1 Engineered Safeguards Features Actuation System Re-sponse Time Testing, observed on December 12, 198 STP 0-8-C, Testing of #12 Diesel Generator following corrective mainten-ance for air in leakage into water cooling system observed on December 10, 198 STP-0-68-1 Refueling Cycle Valve Position Indication Tes PTP-1-RCS-REF-1 Refueling RCS Hydrostatic Tes STP-M-3-1 Main Steam Safety Valve STP 0-7-1, ESF Logic Test,Section VII C, Testing of Two Containment Purge Valves on SIAS signal (A-9).
--
STP 0-4-1, Revision 13, Integrated Engineered Safety Features Test ob-served on December 22, 198 No unacceptable conditions were note . Licensee Initiatives Relating to SALP Main Steam Piping Flaw As part of a non-mandatory licensee program to examine piping for indications of corrosion / erosion problems (see Section IV.D. of Systematic Assessment of Licensee Performance Report No. 50-317/84-99; 50-318/84-99), ultrasonic meas-urements were taken on #12 Steam Generator Main Steam Line at the second elbow (ISI Weld #34-MS-1205-8) downstream of the flow restrictor. Downstream of the field weld joining the elbow to the horizontal pipe, reduced wall thick-ness readings were recorded on the bottom side of the 34 inch pipe. The minimum wall thickness required by the original construction code (ANSI B31.1-1967) is 0.95 inches. Readings as low as 0.86 inches (90.5% of minimum wall) were found immediately adjacent to the weld in a one-half inch band 24 inches long (22.5% ef the circumference).
-- _ ._ -.. - . - _ , - _ - _ _ - _. - . _ , -.
.
.
The licensee believes the probable cause to be grinding of the edge of the pipe to achieve proper fit up for welding during construction. This conclu-sion is based on the following:
(1) seamed piping normally is difficult to fit up and some grinding may be
-
required to-provide a smooth continuous surface between pipe sections; and (2) a radiograph of the area taken during construction was compared with one taken on December 3, 1986 and both films showed a darker band in the same area indicated as thinned wall by ultrasonic testin The licensee performed a stress evaluation and a recommendation was made to the Plant Operating and Safety Review Committee (POSRC) to accept the piping
"as is". On December 3, the POSRC accepted the recommendatio On December 4, 1986 a conference call on this problem was held with the NR On December 10, the licensee made a presentation to NRR in Bethesda, Marylan On December 11, a follow up conference call was held between the licensee and NRR to discuss additional actions needed and reporting requirements. Based on these discussions, the licensee performed a fracture mechanics analysis as allowed by ASME Code Section XI. On December 16, this analysis together with a primary stress limit analysis were submitted to NRR as supporting attachments to a request for relief from the primary stress limits specified in Section XI of the ASME Code, Article IWB 3610(b) (1983 Edition through Summer 1983 Addenda). Additionally, on December 19, the licensee requested an update to ASME Code Section XI, 1983 Edition through Summer 1983 Addenda, for the subject weld onl On December 19, 1986 the NRC granted interim approval to update this flaw to the requirements of the 1983 Section XI Code and interim relief from the ASME Section XI primary stress limits for this flaw only. This interim relief will expire upon the issuance of a final approval along with the issuance of an appropriate safety evaluation or upon a determination that ASME Code relief or update is not acceptable for this fla The inspector noted that a main steam line piping support located in the vicinity of the thinned pipe has had a history of breakage probably due to vibration induced fatigue failure. The licensee had also noted this and had quantitatively determined that support failure would not overstress the pipe in the thinned area. At the inspector's request, the licensee calculated the additional stresses that would be placed on the piping in the thinned region if the support totally failed. Those stresses when combined with previously existing stresses were found to be within design limit . Environmental Qualification of CV 4070 and 4071 Solenoid Valves On December 30, 1986 the licensee notified the resident inspectors that on December 24, during an investigation of slow stroke times of the 1-CV-4070 j and 4071 valves (solenoid / air operated steam flow control valves to the Unit __ _ ,. .-- . _ ,
.
.
1 Auxiliary Feed Water Steam pump), a determination was made that the same valves for Unit 2 were not environmentally qualifie It was discovered that Unit I utilized ASCO solenoid valve model No. ASCO NP 8320A-172V and was suitably environmentally qualified (EQ) for the main steam isolation valve (MSIV) room as required by Qualification No. SV-0042 and properly documented in Calvert Cliffs Instruction (CCI) 208 Qualification Maintenance Requirement Sheet. However, Unit 2 (the operating unit) utilized for the same application and in the Unit 2 MSIV rooms ASCO solenoid model No. ASCO NP 8320A-174V. The
...174 model was listed for use on the Auxiliary Feed System, East Piping Penetration Room and Service Water Pump Room as per Qualification No. SV-0043 also in CCI 208. The .. 174 model is not listed as being environmentally qualified for the MSIV roo Engineering performed an initial evaluation of the differences between the valves and determined that: the 174 model had a larger orifice and a design pressure of 60 psi; the 172 model had a smaller orifice and a design pressure of about 100 psi, otherwise the valves were identica The Performance Group Personnel noted that the 174 model was being utilized where 66 psi pressure was being applied, greater than the allowable design pressure. A discussion with the vendor indicated that the 60 psi design value was not to be exceeded. The licensee replaced the valve with a model 172 versio During this replacement it was noted that the splices to the valves were not environmentally qualified in that they were made by bolting the two wire leads together and wrapping 3 or 4 turns of standard electrical tape around the joint. The fact that the electrical splices were not environmentally quali-fied results in the solenoid valves being nc qualified as wel Should the solenoids "short out" or fail, the air would remain on the CVs 4070 and 4071 (solenoids.are energized to operate). The CV valves would not func-tio However, a motor driven Auxiliary Feed Pump exists which would also
tend to ameliorate the problem in that it is also aligned for automatic in-itiation.
,
This condition, having the splices unqualified, appears to have existed since i
installation of modification Field Engineering Change FEC No. 79-1062-489 dated January 4, 1983, which replaced a model 172 with a model 174 in order i to improve the stroke time of the CVs. The licensee has expressed a serious j concern regarding this event, as to how these splices and valves were inade-
- quately treated in the EQ program. The Operations Manager has ordered that i
a Calvert Cliffs Event Report be generated to ascertain the cause of this oversight.
i l
This appears to be contrary to the Environmental Qualification of electric
, equipment rule as stated in 10 CFR 50.49. This issue is being transferred i to regional specialists for resolution and aisposition, and is considered un-resolved (318/86-19-02).
! " ,~
l l
t
___
.
l -
9. 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 Independent surveys of radiological boundaries and random surveys of non-radiological points throughout the facility were taken by the inspecto ~
Inadvertent Exposure of a Minor During the week of November 24, 1986, the licensee notified the resident in-spector and Region I of an individual, who had been employed as a contractor from late 1985 to mid 1986, and was under eighteen years of age during a por-tion of this employment period. The individtal had received an exposure of 108 mrem during the quarter when he was under eighteen years of ag During this inspection, a follow up of this licensee report was performe During this follow up, the coordinator for the contractor who supplied the under aged individual, the licensee's security screening supervisor, and various dosimetry unit personnel were contacted. The contractor employment questionnaires completed by the individual were reviewed. In the 1985 ques-tionnaire, the individual stated his date of birth (DOB) as December 31, 196 A character reference from a local labor union stated tnat he had been a mem-ber of the union for three years as of October 198 Security forms signed by the individual in October 1986 gave his DOB as December 31, 1967. Review of dosimetry records showed a first TLD issue date, first termination date, rehire date, and second termination date of: October 18, 1985, May 16, 1986, November 24, 1986, and November 25, 1986, respectively. Dosimetry records indicated the following exposures and exposure periods: 108 mrem (WB) from October 18 to November 25, 1985; zero mrem (WB) for the first quarter of 1986; and zero mrem (WB) from April to May 16, 1986. Dosimetry forms signed by the individual in October 1985 stated a DOB of December 31, 1966. Dosimetry forms filled out and signed by the individual in November 1986 showed a 008 of December 31, 1967. A dosimetry clerk noticed the discrepancy in the DOBs and asked to see the individual's driver's license which had the year of birth as 1967. A licensee representative stated that the individual then verbally admitted that his correct birth date was December 31, 1967 and that he had consciously used a different date when applying for employment in 1985. The licensee barred the individual from site acces The licensee revised security procedures subsequent to initial arrival of the individual to require verification of information provided by all wocka.c The procedure revisions for a full background investigation became effective in March 1986. These revisions were made by the licensee without knowledge of the incorrect information provided by the individual of concern. This revision should preclude recurrence of this proble The recent identification of birth date differences (November 1986) was made by dosimetry personnel prior to this security review for this individual's most recent work perio .
.
This occurrence constitutes a falsification of employment records by an in-dividual resulting in the inadvertent exposure of the individual to occupa-tional radiation. The exposure records indicated that the individual received 108 mrem whereas 10CFR 20.104 prohibits minors from receiving greater than 125 mrem. Therefo're, the individual was not over exposed. However, Calvert
-
Cliffs Instruction CCI 800 " Radiation Safety Manual" Section B " Administrative Limits" prohibits individuals less than 18 years of age from receiving ANY occupational radiation exposure. In this regard, this requirement was vio-lated for a period of 3 months prior to the individual becoming eighteen years of ag This is a licensee identified violation which meets the requirements of 10 CFR 2, Appendix C for not issuing a citatio No unacceptable conditions were identifie . Other NRC Concerns The following are concerns raised by the inspectors which are, in the inspec-tors' opinion, deserving of a lesser priority than concerns identified in the cover letter of this repor The licensee should be aware of the concerns, evaluate and prioritize the issues within their own work loa Potential Source of Air Intrusion into Service Water System On May 20, 1980, Unit 1 experienced a complete loss of Service Water (SRW)
event due to system air binding. A large instrument air system to SRW 1eak had developed in an after cooler for an Instrument Air Compressor (IAC).
Because the SRW branch line supplying cooling water to the air compressors is fed from and returns to both SRW subsystems simultaneously (the branch line is automatically isolated from both SRW subsystems in a post accident condi-tion), the air affected both subsystems. To prevent recurrence, the licensee installed large capacity automatic vents on each SRW discharge line from the air compressor after coolers. Air flow sensing devices were installed in the outlet lines for these vents to provide an alarm to alert operators of air intrusion in the system. Considerable interest was focused on this event by the NRC because it represented a situation in which the failure of a non-l safety related component led to the disabling of redundant safety related ( systems. In post accident conditions SRW cools the containment coolers and diesel generators.
t In addition to supplying the after coolers, SRW is also supplied, by separate piping, to the cylinders and intercoolers of the compressors. During the i inspection period the inspector noted that the cooling water to Unit 2's IAC l #21 and Plant Air Compressor does not appear to have access to an automatic l vent until after the water enters both SRW safety related subsystems 'nd i
'
passes downstream of the SRW pumps. The inspector noted that, although auto-matic vents are installed on the casing of the Unit 1 SRW pumps, no such vents I are installed on the Unit 2 pumps. Conceivably, air could enter the SRW system through a cracked cylinder head or leaking head gasket in an air com-l
. - -. .
- _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .
.
.
pressor and possibly air bind the SRW pump The inspector pointed out this possible source of air intrusion to the licensee and asked that it be evalu-ated to determine if additional vents may be warranted. This evaluation will be followed by the NRC resident inspector Augmentation of Spent Fuel Pool Cooling Section 4d of Inspection Report 317/86-18;318/86-18 discusses the licensee's efforts to anticipate decay heat load in the spent fuel pool during the recent Unit 1 full core off loa If decay heat exceeded the capacity of the Spent Fuel Pool Cooling System (SFPCS), the licensee planned to augment the SFPCS with the shut down cooling system (SDC) system. A procedure governing this operation was prepared. Actual decay heat was found to be well within SFPCS capacity, and SDC augmentation was not neede During this inspection period the inspector learned that the flow path for this augmented cooling possibly has never been used. The inspector was con-cerned that as the fuel pool continues to fill with expended fuel assembles, decay heat load will increase and, in the event a full core discharge is necessary, augmented cooling via the SDC system may be necessary. Therefore, the flow path should, prior to planned usuage, be verified operable by l actual test. The inspector discussed this concern with the General Supervisor, Operations who indicated he would evaluate the need for testin . 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 Discovery of Fake Bomb On Site About 12:15 p.m. on December 10, 1986, an employee discovered an object which appeared to be a possible bomb in the men's locker room of the North' Service Building. Control room and security personnel were notified. Appropriate actions in accordance with the site security plan were taken and the object was determined to be harmless. The object consisted of three red canisters taped together with a piece of rope coming out of the top. The letters " TNT" were painted on the side. At the close of the inspection period the licensee was continuing an investigation of the even No unacceptable conditions were note . Review of Periodic and Special Reports Periodic and special reports submitted to the NRC pursuant to 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; l
l
_ _ - _ - _ _ _ _ _ _ - _ _ _ _ _ _ _ - _ _ - _ _
O
.
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 report was reviewed:
-
--
November Operating Data Reports for Calvert Cliffs Units 1 and 2 dated December 7, 198 No unacceptable conditions were identifie . Licensee Action on Previous Inspection Findings (Closed) Inspector Follow Item (317/86-08-01, 318/86-08-01) Comparison of Licensee Analytical Results to BNL Results of Water Samples. On completion of the analyses of water samples by the licensee and Brookhaven National Laboratory, an evaluation was to be made. The analyses were completed and a comparison evaluation was performe Calvert Cliffs Split Sample Comparison BNL CC
--
Simulated RCS:
Boron (ppm) 5940 692 Floride (ppb) 1 (ppm)
Chloride (ppb) ----
196 Feedwater #1 Ammonia (ppb) 160 328 Hydrazine (ppb) 66 48 Silica (ppb) 38 43 Feedwater #2 Iron (ppb) <100 49 Copper (ppb) < 50 31 The boron and floride analyses will be resolved at a subsequent inspectio This item is close (Closed) Inspector Follow Item (317/82-01-52) Need a Software NCR Syste Quality Assurance Procedure QAP-26, Revision 35, now includes software dis-crepancies within the definition of non-conformances (Attachment A-2). This item is close (Closed) Unresolved It2m (317/85-28-02) Proposed Manager of Nuclear Opera-tions Department Does Not Maintain A Senior Reactor Operator License Per ANSI 18.1 Requirements. The licensee manager position corresponding to that de-scribed by the ANSI standard is the General Supervisor, Operations. The in-dividual currently filling that position actively maintains a senior reactor operator license. This item is close . _ _ _ . _
. . .
.
?
-
.
14. Unresolved Items I IJnresolved items require more information to determine their acceptability and are discussed in Sections 2.c and . 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 .. ..
___-______ ________ _ . _ _ _
--
J{lH 21 '87 12:1 NRC CALVERT CLIFFS P01 puno ,jp'
'
! %
T.e . i
'
.
T W J/7Nm
,
M'e u s NucitAn sicutATony co'/ ussiou Pa%:<>. w ie'ea,u-- .. a
- w , %
{
INSPECTOR'S REPORT roley "T-
.g.n o OfGee of inspection and Enforcement --
l
! """' Thomas Fole IrioD,_ b,b
'
.
David TriFble
-, -
.
uc6%5tl .8% Con I"" \I,", coco rr e.c ie e gis OR uto.tt tt*0a1
'
%C it v PMDuf'atl e g 's' _
_% ant A a( can Baltimore Gas & Elec. C A0 ATTN: d f Tiernan. vice
~
X ' - ' " " '
" - " " ' TNifVTT7 RF ~Bfdf ff0 a
~
v3 T
va
!
President.Huclear Ere.rg)
_
_
'-"""' 652 1 8 _ nli *
i P_ 0. Rm_1475
__ - J~ '7 '
a - al'ac ___
l
.Baltinnre Maryland 21203 ~-
" i ' I'~ - ~
$ _
j Ps eiOD 08 '%vil'tiaist % 'IN SFE C110*3 -% '5 - 'O
- *0ea s%5'ICTs04Plas0*vtoav 1 TD l - ptGto4AL OFFeC4 5TAff ! dam %2afow COOL C# a(Ga0%rHQ MD CA* vp uO f _
pt". Atity'Tv (See stuJ C*M usw e, a,3n Car vR 2 - 9t$10tNiaN5PECTOR '] O1'*t h y nees , vem s eNM em )
JT6 Mpg.M,.j,@{ i - a'ca"(t ^=^'5"
. .-
-
~.~~-,t- <n.-
a" 8't C2.'N P1 b 5'ON 88- * 'T>* *
I -~=*~-=ms
. .
o -==~~
_
DRP 3A stW%atACTcq ~p ~
y-= ; y -l
"*"""' __
I'PI O' *C val v CON 0sCflo ets t. ewe be.arw v i '
. 42 - 5 Af t'Yv t sent pomu5st 12 - -GVT Vs587 01 1%C#DfNT 50 - P.A%1 Sf le - 8%O0847 l ) 97 - PIC'al 3. PEGION AL orr!Gi tmth 11. myts et vtn
! 68 - f M04CEMthli eb - VENDOR 15 - 1%vitfiC A1104 es 12. twervf artetaPO47 j . , . . . , _ _ .
.,,,.
- -
_ ,- cui .. suo<v e,- u.1 ace a * F e a g. .sg,*g ret.D^65
.
-
_. m _ ,.. . - m _ .... g , _u_,u,o.,
. ~ . . , . . . _
- - ...
iorat %ousta
..
_
_
,.3 f * ( o ' -
onvouvous.~o 1%5pm;t wi.ni coss g a g%cg agaoms co%,A % a m o w ro=s .Ito ne oa v at o= ttng r. on agroat Tea %5u.ftat oats j f , . co .,
-
- l .. c , . .t. ,
2 * V10tATsON i LE T, .. .
Enf51UED ro o . tuvinicu a 7 e o A . c o e o ACTaOg m - ,m ;-
.. vo.45,o=.pe
. uro.,
,e ,o , , i - vis
. .
uo om, vn wo on, g- m:. .v. m_ .a. ,nm: i 5 g p) 7ppy r_:::.wg.:. :.. ~~- ~.~ r.a. .,n.g_ ,,wr. ;
-
. ,
. ~; .,
J [ [
l w e,%,2. .. , .
gr. 3;,?: as
. 6, .. . :;.u u e .-
'g,b veooa usvn t* !
a, .,:oua %.o....,m woosttelosouower Q anon w.vvat a mse ap
_
woova nto sottows-
___
E "
! .! !" :- :s[
. i > u: V t,i m .
E e i b o 5.B_d, s.18e 3 t : ji m,I
-
- I r, i 5:[ {1 R*{ p_id_ i :: j!
i:
re: '_:i
. - t I E. E ,t .! > u
.
. . . - e _ V :
- .: si V<* . uO/ha71M _. _f4 h Dio i liil uddtM03lb d[ LOP
,
-
i3,o tono i I..I *
i -liiI l i/3 !OP _ i iiii 13 i l
-
1 -
ei . .. a '
i a ii_ ii_ i liil
_ ,, i i
--
i liil_ o aa ;e i ub/l2/ol _aM Ii2io ^
aJii1 -- -> A/J2441F ao i i i . l_
! * 4p IiiI
_M i ,0. 0 i liiL i Ji/ /ioio
-
ili_i_L
__
l __ J i , li,l
- --
' i e
,,
l i_ I
-
_
3 > i i i
_, 4 , , , ,
I4 . I o
,,
u$Y317ha.L'. _a,24LO. C'
-
, ,
iI..I liii Adel2oAlh
_ _
i
i/3 10i0 . _i_i/ iM J_.Li i i
._i_Lia_L
_ _
_ _ '
__ a _t_ i .i ._ i liil
._ i i - i i iI 1L
'
u _t> . . i1 _d_
ii lii!
-
n e -i
._
i uf8AJ?ML L _uA).Rp .
I i 1_LE5ZL17Lalb e _n
,#
3 1
,B Iii!_
4 ,M. 0 a1,,i
_ , Io1 L al Ec
_ _
iIeiI
.c.. . . s. <m. ~a .
%+ >no% o
. _ ai ii -_ _ i l u r i i-
.. i l - i il IlQ. { r'*.o' ~'=- wi! 91 6'W u P. 'n: _t t___1J -_i_1 J o
'
_ni _ a ni 7:C--V O 31 4 { 4 .* .;.;114%ci,< is G VE) w": . A ; alpl WMR.12+
_ _1 i y JI i a I-_
CHECK HERE IF H0DULE DATA 15 CONTINurn nu orvrow i=3
i JAN 21 '87 12817 NRC CALVERT CLIFFS P02
-' ~ ~
wopu6s .%,o.watic=
=ocos a .o,wa r.o.,
(
'
)'.1,, woous *yerva .sa bg e r-Ei, wcpuss eco noaowv, g wo u. ,,wusta 5* ar y woesa nic 3o rgg
-
. - - - . 3o i ., *E ? $E = I 5 1 T$ hi k5 $b: iE
.5 : 7: RI ; if: :_ !;$ xi e c i :
. E 5riiFr E 3 .
5 a xi :; ;5:
- ii E i I 3i 2i f
- U f ;ch:le I rSg ;
!
i ao : # $
-
i i
!:
a5 : i i n
- : 2 sh::1 t82 iia I
a e f h I t ' t _Ct O _
! ___ !_1_ t _
- I I ! _f 1 !
'
t 1 1 1 _1 l
__
i _1 dl@ -
J __ I J __ ', I I _1 1 e i
_
' i i .
,
_ - . -- .. -
_ . _J e t i I 1 1 1 I '
.1 1 1 I f I
"
.__
___ _ ._ -- -
-t i e i f Iii t 1 J 1 tl fLf 7.#M /R /40
. .
._
. . -l ,11 . , ,li,I ^
, ! , , , I
_ . _ _
. mi u_ , 4 ji,.]_ .
, , , , , I
_
C l l c
._ _. . I I l - --I _1 I 1 i l __ 1 f 1 f f l
I
%J 1 i t e e i !. t t i157222dl5 '
_ _u d !.m i I..I 4 . il 41
'
>> i i 21 a
, iY /,4 0 _ i _ I i i_ I '
i i i i iI
, , , , ,1,4 1 -
i _
,, , , i l o , , ,, , l..'l a
,4 i i i 1 IVi/l7,oelb
-
-
.- I i M Mio , I , , l_ .i ,LiJ -
ie i i i I
. . . .
! , ,/ ago . Ii,I *
. i i . i I I I e i t i
_ i I e i e i e C.ac.t stc.txt es 3 I I Wie * *. . u t t . ts tica a 1 l l 3 i t _[ 1 l l __ __
l t t J l 1__
- l22ls ls '_- 1: '
12: '3 15 k ' "se it M 7: *?~'- :n e
~
'
- e! is s' s it '~ it is ac 'r
- ]a 2l a {$ '
-
McDutt i=se nua'ch webuts .=*cowa teae
"C.; l wetw6t hwwet e ams' bg g uCDutt ala pottowup f,f,; ! *CDut %wulf 4 W1P d2 p 903JLE'lO i i . UE E rr 3n - . tE Ea e 6 E > >E b 5k heE e
X =
$" E
$,3 , e
~
3122" ( s' % I E SE h er
a E
s a
- I
- 06=
b fI if I x! 3 . DT z 3 3 iE
,_
. .I au II fe3 E.3a Gh3 m- iA$
a u -
b
.
I t I[
!
a E
-
33s aI aw
~ IE E a E, 5 E m_O E . f$$
h"E u * $ l 3$
_
- I 1 I I J t I I I 1 i .1 l i 1 1 1 11 1--
'
1 I 1 i f f 1 '
t j l- t i I f e i _t i _ __i -l1- 1 1 '
se i 1 1 !
__
i t t I i 1 0 #
1 1 J f _ _ f _
. i 1 I i 1 ] '
i i i i __, I i-- i I ._r . , I,iI ^
_ i_ i __ii _ i _ i_
_
- -
'
.
__I 1 .,_1 I I i 1 [ _,_J l _I f I !
_ _ f e
__
_
$ __ 1 1 JL_,, I
'
, , , , . l.,1 o
._
, s '
, 4 _ i l
^
8 I f I f f i e i i
_
e i e _ ,1, ] l1L.'_ axai _ .i l __ -
_ _J l i f I I i '
i l l I I!
L _ u __ .. i lii l--- '
i u_1 i - _ _tJ_
_ f f 1 8 ' I f '
t I J l _ ___ 1 _I _ _
,I,t 1M
._ i u_ _u ib liii di _i .I i i l l' _1 . . . ii n , , a, _
, I,iI '
, , , , i I
. 1 I _1 i i If i i i _t i , i e c*c.isicvt c c 26 a * os m via c . g g g g g g g 3
- '"- " - ' ec l g_y g g g al 21'.-5)$ .. ' n ' -l:3} aj 'S j ._ .' ' O scj
'
l2 3]a i2 lis 1$ is .~ '~is ts
_
la ' i's ~ ~ b +s ?.7e es a :rtt!.fi8
_ _
-_ .