ML17335A539
| ML17335A539 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 09/27/1999 |
| From: | Stang J NRC (Affiliation Not Assigned) |
| To: | Powers R INDIANA MICHIGAN POWER CO. (FORMERLY INDIANA & MICHIG |
| References | |
| NUDOCS 9910060021 | |
| Download: ML17335A539 (18) | |
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UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 2055&0001 September 27, 1999 Mr. Robert P. Powers, Senior Vice President Indiana Michigan Power'Company Nuclear Generation Group 500 Circle Drive Buchanan, Ml 49107
SUBJECT:
REVIEW OF PRELIMINARYACCIDENT SEQUENCE PRECURSOR ANALYSIS OF OPERATIONALCONDITION AT DONALDC. COOK NUCLEAR PLANT, UNITS 1 AND 2
Dear Mr. Powers:
Enclosed for your review and comment is a copy of our preliminary Accident Sequence Precursor (ASP) analysis of an operational condition which was discovered at Donald C. Cook Nuclear Plant, Units 1 and 2 on July 15, 1998 (Enclosure 1), and was reported in Licensee Event Report (LER) No. 454/98-018.
The results of this preliminary analysis indicate that this condition may be a precursor for 1998.
In assessing operational events, an effort was made to make the ASP models as realistic as possible regarding the specific features and response of a given plant to various accident sequence initiators. We realize that licensees may have additional systems and emergency procedures, or other features at their plants that might affect the analysis.
Therefore, we are providing you an opportunity to review and comment on the technical adequacy of the preliminary ASP analysis, including the depiction of plant equipment and equipment capabilities.
Upon receipt and evaluation of your comments, we will revise the conditional core damage probability calculations where necessary to consider the specific information you have provided. The object of the review process is to provide as realistic an analysis of the significance of the event as possible.
In order for us to incorporate your comments, perform any required reanalysis, and prepare the final report of our analysis of this event in a timely manner, you are requested to complete your review and to provide any comments within 30 days of receipt of this letter. We have streamlined the ASP Program with the objective of significantly improving the time after an event in which the final precursor analysis of the event is made publicly available.
As soon as our final analysis of the event has been completed, we willprovide for your information the final precursor analysis of the event and the resolution of your comments.
We have also enclosed several items to facilitate your review. Enclosure 2 contains specific guidance for performing the requested review, identifies the criteria which we willapply to determine whether any credit should be given in the analysis for the use of licensee-identified additional equipment or specific actions in recovering from the event, and describes the specific information that you should provide to support such a claim. Enclosure 3 is a copy of LER No.
316/98-005, which documented the event.
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Powers Please contact me at 301-415-1345 if you have any questions regarding this reque"t. This request is covered by the existing OMB clearance number (3150-0104) for NRC staff followup review of events documented in LERs. Your response to this request is voluntary and does not constitute a licensing requirement.
R Sincerely, John F. Stang, Sr. Hoject Manager, Section 1
Project Directorate III Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket Nos. 50-315 and 50-316
Enclosures:
As stated cc w/encis: See next page
Robert P. Powers Indiana Michigan Power Company Donald C. Cook Nuclear Plant Units 1 and 2 CC:
Regional Administrator, Region III U.S. Nuclear Regulatory Commission 801 Warrenville Road Lisle, IL 60532-4351 Attorney General Department of Attorney General 525 West Ottawa Street Lansing, Ml 48913 Township Supervisor Lake Township Hall P.O. Box 818 Bridgman, Ml 49106 Drinking Water and Radiological Protection Division Michigan Department of Environmental Quality 3423 N. Martin Luther King Jr Blvd P.O. Box 30630 CPH Mailroom Lansing, Ml 48909-8130 Gordon Arent Director, Regulatory Affairs Indiana Michigan Power Company Nuclear Generation Group 500 Circle Drive Buchanan, Ml 49107 U.S. Nuclear Regulatory Commission Resident Inspector's Office 7700 Red Arrow Highway Stevensville, Ml 49127 Jeremy J. Euto, Esquire Indiana Michigan Power Company Nuclear Generation Group 500 Circle Drive
- Buchanan, Ml 49107 David A. Lochbaum Union of Concerned Scientists 1616 P Street NW, Suite 310 Washington, DC 20036-1495 A. Christopher Bakken, Site Vice President Indiana Michigan Power Company Nuclear Generation Group One Cook Place Bridgman, Ml 49106 Mayor, City of Bridgman P.O. Box 366 Bridgman, Ml 49106 Special Assistant to the Governor Room 1 - State Capitol Lansing, Ml 48909 Michael W. Rencheck Vice President, Nuclear Engineering Indiana Michigan Power Company Nuclear Generation Group 500 Circle Drive Buchanan, Ml 49107
LER No. 316/98-005 LER No. 316/98-005 Event
Description:
Potential for High Energy Line Break to Degrade Component Cooling Water System Date ofEvent:
July 1998 Plant:
Donald C. Cook Nuclear Plant, Units 1 and 2 Event Summary On July 15, 1998, with Donald C. Cook Nuclear Plant, Units 1 and 2 (Cook 1 and 2) in cold shutdown, itwas determined that a postulated crack in a Unit 2 main steam line could degrade the ability of the component cooling water (CCW) pumps to perform their design function (Ref. 1). The CCW pumps for both units are adjacent to one another in a semi-enclosed area in the AuxiliaryBuilding. Next to the area where the pumps are located is a pipe chase enclosing two Unit 2 main steam lines and a main feedwater line. This pipe chase can be accessed through any one ofthree doors. Although the pipe chase walls provide a qualified high energy line break (HELB) barrier, the licensee could find no calculations which show that the doors would withstand the energy released from a postulated critical crack.
The CCW pump motors and other equipment are not qualified fora high temperature/high humidity environment. As a result, ifthe postulated HELBwere to occur, the potential would exist for both units to su6er a total loss ofCCW.
The estimated conditional core damage probability (CCDP) associated with this condition. is 6.9 x 10'. This is an increase (importance) of 1.3 x 10'ver the nominal core damage probability (CDP) fora one-year period for Cook 2 of5.6 x 10~. The same results apply to Unit 1 as well.
Event Description On July 15, 1998, with both units in Operating Mode 5, cold shutdown, the licensee determined that a postulated crack in a Unit 2 main steam line could degrade the abilityofadjacent CCW pumps for both units to perform their design function. The condition was reported on August 14, 1998, as an unanalyzed condition in Interim LER 316/98-005, Rev. 0 (Ref. 1).
The CCW pumps for both units are adjacent to one another in a semi-enclosed area in the AuxiliaryBuilding.
Next to the area where the CCW pumps are located is a pipe chase enclosing bvo Unit 2 main steam lines and a main feedwater line, which can be accessed through any one ofthree access doors. Although the walls ofthe pipe chase provide a qualified HELBbarrier, the licensee was unable to find any calculations which show that these access doors would withstand the energy released from a postulated critical crack in a high energy line.
The CCW pump motors and other equipment are not qualified for the high temperature/high humidity environment that would exist followinga HELB.
Fnclasure 1
LER No. 316/98-005 Additional Event-Related Information As stated above, there are two main steam lines and one main feedwater line running through the pipe chase of interest.
This pipe chase contains only main steam and main feedwater (large bore) piping. There are no small bore high energy branch lines in this area. The licensee's preliminary investigation found that there are no high stress pipe segments in this area which are vulnerable to cracks or breaks. There are three access doors between the pipe chase and the CCW room, which open into the CCW room. The length ofpiping adjacent to each ofthe doors is about 20 to 30 feet, which means a total ofabout 60 to 90 feet are situated near the doors. This represents an estimated five percent ofall ofthe high energy piping in the plant (Ref. 2).
References 2 and 3 provides the followinginformation. The pipe chase in question communicates witha steam tunnel, which is a large area.
Roughly 50 percent ofthe total high energy piping in the plant is located in this area. A postulated failure ofthe high energy piping in this large area could send steam into the pipe chase adjoining the CCW rooms. Ifthe pressure increase due to the postulated piping failure is high enough, then the doors from the pipe chase to the CCW pump room may open, and allow steam to enter that room. No calculations were available which showed whether a break in a location in the steam tunnel could create a pressure increase large enough to open the access doors to the CCW pump room.
However, according to References 2 and 3, one end ofthe steam tunnel is open to the turbine building. Therefore, the turbine building provides a large, potential escape path for steam generated from postulated breaks in the piping in the steam tunnel. The other end ofthe steam tunnel is also open to a very large, potential steam escape volume. Due to the existence ofthese potential escape paths, only those postulated pipe breaks that occur close to the doors leading from the pipe chase to the CCW rooms are likely to send steam into the room that houses the CCW pumps.
Modeling Assumptions The frequency ofHELBs in main steam lines and main feedwater lines used in this analysis was derived from data in NUREG/CR-5750 (Ref. 5).
In this rcport, the mean frequency per critical year for steam line breaks/leaks outside containment, based on seven events in 729 critical years, is estimated to be 1.0 x 10'"- per year.
The frequency for feedwater breaks/leaks, based on tivo events in 729 critical years, is 3.4 x 10'er year.
Ofthe seven steam line events that contributed to the 1.0 x 10'per year frequency, only one occurred in a main steam line. Since the area next to the CCW rooms contains only main steam lines (i.e., no small bore piping or branch lines), only this event was considered applicable to the issue being analyzed.
However, this event was also dismissed from further consideration, since itconsisted ofa sample probe failure in a main steam line that would not have been large enough to pressurize the large area and cause a door to open. The frequency for steam line breaks/leaks was therefore estimated to be 7 x 10 per year, using Bayesian update methods with 0 events in 729 critical years.
Based on Reference 5, the two events that contribute to the main feed line break frequency occurred at Millstone Point Units 2 and 3. The root causes ofboth these breaks were erosion and corrosion.
Therefore, these hvo failures may be applicable to the area under consideration.
(Reference 6, the NRC's Mechanical
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LER No.
316/9S-005'ngineering Branch Technical Position, MEB 3-1, does not provide a basis to exclude these failures from the initiating event frequency calculation for this area, since it does not require postulation offailures attributed to erosion and corrosion.) As a result, the estimated frequency remained at 3.4 x 10'er year.
The criticalityfactor for Unit 2 is 0.68 (Ref. 5). The criticality factor for Unit 2 was used in this analysis to calculate the initiating event frequency rather than the factor for Unit 1 because the piping in the pipe chase ofconcern is associated with Unit 2. As a result, the frequency is 4.7 x 10~ per year (0.68 x 7 x 10") for steam line breaks/leaks, and 2.3 x 10 i per year (0.68 x 3.4 x 10') for feedwater breaks/leaks.
The frequency ofHELBs is therefore the sum ofthe two frequencies, or 2;8 x 10'per year.
The above estimate applies to HELBs in main steam lines or main feedwater lines anywhere in the plant. To determine the initiating event frequency in the specific area ofinterest, the above frequency was multiplied by 0.05, the percentage ofthe piping in the pipe chase that is located in the vicinityofthe access doors.
Steam from a pipe break anywhere in the tunnel could potentially enter the pipe chase.
However, due to the large potential escape paths, itwas assumed pat only breaks which occurred in the piping in the vicinityofthe doors to the room that houses the CCW pum'ps would be capable of opening any one of the three doors.
Since approximately 5% ofthe piping is in the vicinityofthe doors, the estimated frequency ofHELBs in thb area ofinterest is therefore 0.05 x 2.8 x 10', or 1 4 x 10~ per year.
As stated in Reference 1, the CCW pump motors and associated equipment are not qualified for a high temperature/high humidity environment.
Operating experience was reviewed to investigate the response of pumps that are not qualified to high humidity to events that impose those environmental conditions on these pumps.
First, approximately 80 LERs that reported water spray, cascade, flood, or high humidity problems affecting pumps were identified using the NRC's Sequence Coding and Search System (SCSS) LER database.
Ofthese, a sample ofapproximately 50% were reviewed and 4 were identified for detailed review, since they contained information on pumps impacted by steam environments. The review identified whether the pumps failed when subjected to high humidity or temperature environment. Ifa failure did occur, the nature ofthe failure was examined to determine the recoverability. Some observations from this review are as follows. Of the four events that were reviewed in detail (LER 302/91-003 and 251/90-008), during two events, pumps failed when exposed to steam environment due to moisture intrusion in to the motor winding. These did not appear to be recoverable.
There was one event where the pumps continuously ran even when water had collected in the lower motor bearings (LER 285/92-031).
The forth event (LER 272/90-033) appeared to be a recoverable pump failure.
Exact count of failures and demands could not be used to estimate a failure probability due to biases in reporting failed versus successful pumps exposed to moisture. However, in light ofthese observations, a probability of 0.5 appears to be a reasonable estimate for the probability offailing both CCW pumps and the spare CCW pump when exposed to the steam environment.
Considering the nature ofthe failures (e.g., shorts in motor windings), itwas assumed that for this specific situation, recovery ofthe CCW pumps would not be credible.
Ifthe CCW pumps failed due to the postulated steam environment, cooling to the reactor coolant pump (RCP) seals would be lost. Even though the RCP seals can also be cooled by seal injection, since the charging pumps require CCW for charging pump seal cooling, the seal injection function would also be lost. With no seal cooling, the Westinghouse type RCP seals would degrade rapidly. The D. C. Cook Nuclear Plant Individual Plant Examination (IPE) (Ref. 4) assumes that the RCP seals willfail with a probability of 1.0 ifseal cooling
LER No. 316/98-005 is unavailable for one hour. This assumption is overly pessimistic since all 8 RCPs at D.C. Cook Units 1 and 2 have newer Westinghouse high temperature seals.
Based on the RCP seal failure models suggested in NUREG/CR-4550 (Ref. 7), forthe new high temperature seals, the failure probability when seal cooling is lost for an extended period is 0.19.
Ifan RCP seal LOCAwere to occur, according to the modeling discussed in the Cook IPE (Ref. 4), and based on a review ofactual RCP seal LOCA events, high pressure injection (high prcssure, low volume) would be needed to mitigate the accident.
However, all four high pressure injection pumps at the D. C. Cook plant are cooled by CCW, so a non-recoverable loss ofCCW would lead to a loss ofhigh pressure injection. According
'o the D.C. Cook FSAR (Ref. 3), all high pressure injection (HPI) pumps at Cook are highly dependent on CCW.
The seal and lube oil heat exchangers of the two safety injection pumps are cooled by CCW.
In addition, the pump gear, lube oil, and seal exchangers ofthmentrifugal charging pumps are also cooled by CCW.
Even ifthe HPI pumps could inject for a short duration, in order to terminate the RCP seal LOCA and stabilize the reactor coolant system (RCS), the RCS must be cooled down and depressurized.
With CCW unavailable, the operator would be expected to trip the RCPs.
Therefore, forced circulation would be unavailable. Withonly natural circulation in the RCS and auxiliary feedwater (AFW)available, it is unlikely that the RCS would be stabilized before the HPI pump seals would be damaged due to loss of cooling.
Therefore, the probability offailure ofall HPI pumps, given that CCW was unavailable due to steam intrusion, was assumed to be 1.0.
Since the CCW for both units would have failed due to the steam environment, cross-tie capability was not credited in this analysis.
Anaiysis Results Figurc 1 shows the accident sequence that leads to core damage.
This sequence consists ofthe following:
~
A main steam line break occurs in the high energy pipe chase in the vicinityof one ofthe three doors leading to the CCW pump room.
~
Failure ofthe running and standby CCW pumps and the spare CCW pump due to high humidity and high temperature environment.
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Failure ofthe RCP seals given failure to recover any CCW pump and restore seal cooling to the RCPs.
The results ofthis analysis are based on one key assumption.
Since there are no calculations showing the capability ofthe CCW pump room pipe chase access doors to withstand the pressures created by steam line or main feed line breaks, at least one ofthem would open during a break, allowing steam to enter the CCW pump room.
Since failure ofthe CCW pumps could lead to an RCP seal LOCAand also fail the mitigating capability (i.e.,
the HPI pumps), a steam line break or a main feedwater line break in the vicinityofthese doors could result in core damage.
Thus the increase in core damage frequency associated with this condition is 1.3 x 10 ~
LER No. 316/98-005 (1.4 x 10' 0.5 x.19) per year. The overall nominal core damage frequency is 5.6 x 10'er year [estimated using the NRC's SAPHIRE-based model for the D. C. Cook plant]. Therefore, the conditional core damage frequency (CCDF - conditional frequency ofsubsequent core damage given the failures observed during an operational event) is 1.3 x 10'+ 5.6 x 10' 6.9 x 10'er year. For a one-year period, the associated CCDP is 1-exp[(6.9 x 10'/year) x (I year)] = 6.9 x 10'. The nominal CDP forthe same period is I - exp[(5.6 x 10'/year) x (1 year)) = 5.6 x 10'. Using these two values, an increase in CDP (importance) of 6.9 x 10'-5.6 x 10'= 1.3 x 10'is estimated.
Acronyms AFW CCDF CCDP CDF CDP CCW HELB HPI IPE LOCA RCP RCS auxiliary feedwater conditional core damage frequency conditional core damage probability core damage frequency core damage probability component cooling water high energy line break high pressure injection individual plant examination loss-of-coolant accident reactor coolant pumps reactor coolant system E
References LER 316/98-005, "Potential for High Energy Line Break to Degrade Component Cooling Water System," August 14, 1998.
2.
Personal communications, R. J. Stakenborghs (American Electric Power) and S. Weerakkody (U. S.
Nuclear Regulatory Commission), July 13 and 15,'999.
3.
Donald C. Cook Nuclear Plant, Units I and 2, Updated Final Safety Analysis Report 4.
Donald C. Cook Nuclear Plant, Units I and 2, Individual Plant Examination Revision I, October 1995.
5.
J. P. Poloski, et. al., Rates ofInitiating Events at U.S. Nuclear Power Plants: I987'- 1995, NUREG/CR-5750, December 1998.
6.
Relaxation in Arbitrary Intermediate Pipe Rupture Requirements (Generic Letter 87-11), Branch Technical Position MEB 3-1, "Postulated Rupture. Locations in Fluid System Piping Inside and Outside Containment," Rev. 2, June 1987.
LER No. 316/98-005 7.
"Analysis of Core Damage Frequency for Internal Events:
Expert Judgement Elicitation,"
NUREG/CR-4550, Vol. 2, April 1989.
INITIATINGEVENT ACCESS DOORS CCWPUMPS HIGH ENERGY PREVENT STEAM SURVIVESTEAM UNE BREAK FROM ENTERING ENVIRONMENTTO SEAL COOUNG IN PIPE CHASE CCW PUMP ROOM PERFORMFUNCTION HELB-PC NS-CCS-RM CCW-COOL CCW-PMP-REC SEQUENCE NO.
END STATE OK OK OK CD COOK 1, ASP PWR B HIGH-ENERGY LINE BREAK EVENTTREE
4 f
GUIDANCE FOR LICENSEE REVIEW OF PRELIMINARYASP ANALYSIS
Background
The preliminary precursor analysis of an operational event that occurred at your plant has been provided for your review. This analysis was performed as a part of the NRC's Accident Sequence Precursor (ASP) Program.
The ASP Program uses probabilistic risk assessment techniques to provide estimates of operating event significance in terms of the potential for core damage.
The types of events evaluated include actual initiating events, such as a loss of off-site power (LOOP) or loss-of-coolant accident (LOCA), degradation of plant conditions, and safety equipment failures or unavailabilities that could increase the probability of core damage from postulated accident sequences.
This preliminary analysis was conducted using the information contained in the plant-specific final safety analysis report (FSAR), individual plant examination (IPE), and the licensee event report (LER) for this event.
Modeling Techniques The models used for the analysis of 1998 events were developed by the Idaho National Engineering Laboratory (INEL). The models were developed using the Systems Analysis Programs for Hands-on Integrated Reliability Evaluations (SAPHIRE) software. The models are based on linked fault trees.
Four types of initiating events are considered: (1) transients, (2) loss-of-coolant accidents (LOCAs), (3) losses of offsite power (LOOPs), and (4) steam generator tube ruptures (PWR only). Fault trees were developed for each top event on the event trees to a supercomponent level of detail. The only support system currently modeled is the electric power system.
The models may be modified to include additional detail for the systems/ components of interest for a particular event.
This may include additional equipment or mitigation strategies as outlined in the FSAR or IPE. Probabilities are modified to reflect the particular circumstances of the event being analyzed.
Guidance for Peer Review Comments regarding the analysis should address:
Does the "Event Description" section accurately describe the event as it occurred' Does the "Additional Event-Related Information" section provide accurate additional information concerning the configuration of the plant and the operation of and procedures associated with relevant systems' Does the "Modeling Assumptions" section accurately describe the modeling done for the event?
Is the modeling of the event appropriate for the events that occurred or that had the potential to occur under the event conditions?
This also includes assumptions regarding the likelihood of equipment recovery.
Enclosure 2
~ '
Appendix G of Reference 1 provides examples of comments and responses for previous ASP analyses.
Criteria for Evaluating Comments Modifications to the event analysis may be made based on the comments that you provide.
Specific documentation willbe required to consider modifications to the event analysis.
References'should be made to portions of the LER, AIT, or other event documentation concerning the sequence of events.
System and component capabilities should be supported by references to the FSAR, IPE, plant procedures, or analyses.
Comments related to operator response times and capabilities should reference plant procedures, the FSAR, the IPE, or applicable operator response models.
Assumptions used in determining failure probabilities should be clearly stated.
Criteria for Evaluating Additional Recovery Measures Additional systems, equipment, or specific recovery actions may be considered for incorporation into the analysis.
However, to assess the viability and effectiveness of the equipment and methods, the appropriate documentation must be included in your response.
This includes:
normal or emergency operating procedures.
piping and instrumentation diagrams (P&IDs),'lectrical one-line diagrams,'esults of thermal-hydraulic analyses, and operator training (both procedures and simulator),'tc.
Systems, equipment, or specific recovery actions that were not in place at the time of the event will not be considered.
Also, the documentation should address the impact (both positive and negative) of the use of the specific recovery measure on:
the sequence of events, the timing of events, the probability of operator error in using the system or equipment, and other systems/processes already modeled in the analysis (including operator actions).
For example, Plant A (a PWR) experiences a reactor trip, and during the subsequent recovery, it is discovered that one, train of the auxiliary feedwater (AFW) system is unavailable.
Absent any further information regrading this event, the ASP Program would analyze it as a reactor trip with one train of AFW unavailable.
The AFW modeling would be patterned after information gathered either from the plant FSAR or the IPE. However, if information is received about the use of an additional system (such as a standby steam generator feedwater system) in recovering from this event, the transient would be modeled as a reactor trip with one train of AFW unavailable, but this unavailability would be mitigated by the use of the standby feedwater system.
The Revision or practices at the time the event occurred.
mitigation effect for the standby feedwater system would be credited in the analysis provided that the following material was available:
standby feedwater system characteristics are documented in the FSAR or accounted for in the IPE, procedures for using the system during recovery existed at the time of the
- event, the plant operators had been trained in the use of the system prior to the event, a clear diagram of the system is available (either in the FSAR, IPE, or supplied by the licensee),
I previous analyses have indicated that there would be sufficient time available to implement the procedure successfully under the circumstances of the event under analysis, the effects of using the standby feedwater system on the operation and recovery of systems or procedures that are already included in the event modeling.
In this case, use of the standby feedwater system may reduce the likelihood of recovering failed AFW equipment or initiating feed-and-bleed due to time and personnel constraints.
Materials Provided for Review The following materials have been provided in the package to facilitate your review of the preliminary analysis of the operational event.
The specific LER, augmented inspection team (AIT) report, or other pertinent reports.
A summary of the calculation results.
An event tree with the dominant sequence(s) highlighted.
Four tables in the analysis indicate:
(1) a summary of the relevant basic events, including modifications to the probabilities to reflect the circumstances of the event, (2) the dominant core damage sequences, (3) the system names for the systems cited in the dominant core damage sequences, and (4) cut sets for the dominant core damage sequences.
Schedule Please refer to the transmittal letter for schedules and procedures for submitting your comments.
References 1.
R. J. Belles et al., "Precursors to Potential Severe Core Damage Accidents: 1997, A Status Report," USNRC Report NUREG/CR-4674 (ORNL/NOAC-232) Volume 26, Lockheed Martin Energy Research Corp., Oak Ridge National Laboratory, and Science Applications International Corp., Oak Ridge, Tennessee, November 1998.