Total Protection Basics

8/12/2019 Total Protection Basics

1/134

1GE Consumer & Industrial

ultl n

Protection Fundamentals

ByCraig Wester, John Levine


2/134


ultl n

Outline Introductions Tools

Enervista Launchpad On Line Store

Demo Relays at ISO / Levine Discussion of future classes Protection Fundamentals ANSI number handout, Training CDs


3/134


ultl n

Introduction Speakers:

Craig Wester GE Multilin Regional Manager John Levine GE Multilin Account Manager


4/134


ultl n

Objective We are here to help make your job easier.

This is very informal and designed aroundISO Applications. Please ask question.We are not here to preach to you.

The knowledge base on GE MultilinRelays varies greatly at ISO. If you have aquestion, there is a good chance there are3 or 4 other people that have the samequestion. Please ask it.


5/134


ultl n

Tools


6/134


ultl n


7/134


ultl n


8/134


ultl n

Demo Relays with Ethernet Working with James McRoy and Dave

Curtis SR 489

SR 750 G30 MIF II Training CDs


9/134


ultl n

Demo Relays at L-3


10/134


ultl n

Future Classes GE Multilin Training will be the 2nd Friday of

every month. We will cover: March Basics, Enervista Launchpad, ANSI number

and what they represent, Uploading, downloading,Training CDs, etc. April 489 Relay May MIF II relay

June - 750 Relay July - UR relay basic including Enervista Engineer August UR F60 and F35 relays September G30 and G60 including Transformer and

Generator in same zone October Communications and security November - Neutral Grounding Resistors December Cts and PTs


11/134


ultl n



12/134


ultl n

Desirable Protection Attributes

Reliability: System operate properly Security: Dont trip when you shouldnt Dependability: Trip when you should

Selectivity: Trip the minimal amount to clear thefault or abnormal operating condition

Speed: Usually the faster the better in terms ofminimizing equipment damage and maintainingsystem integrity

Simplicity: KISS Economics: Dont break the bank


13/134


ultl n

Selection of protective relays requires compromises:

Maximum and Reliable protection at minimumequipment cost

High Sensitivity to faults and insensitivity to maximumload currents

High-speed fault clearance with correct selectivity

Selectivity in isolating small faulty area

Ability to operate correctly under all predictable powersystem conditions

Art & Science of Protection Art & Science of Protection


14/134


ultl n

Cost of protective relays should be balancedagainst risks involved if protection is notsufficient and not enough redundancy.

Primary objectives is to have faulted zones

primary protection operate first, but if there areprotective relays failures, some form ofbackup protection is provided.

Backup protection is local (if local primaryprotection fails to clear fault) and remote (ifremote protection fails to operate to clear

fault)

Art & Science of Protection Art & Science of Protection


15/134

15GE Consumer & Industrialultl n

Primary Equipment & ComponentsPrimary Equipment & Components Transformers - to step up or step down voltage level Breakers - to energize equipment and interrupt fault current

to isolate faulted equipment

Insulators - to insulate equipment from ground and otherphases

Isolators (switches) - to create a visible and permanentisolation of primary equipment for maintenance purposes

and route power flow over certain buses. Bus - to allow multiple connections (feeders) to the same

source of power (transformer).


16/134


Primary Equipment & ComponentsPrimary Equipment & Components Grounding - to operate and maintain equipment safely Arrester - to protect primary equipment of sudden

overvoltage (lightning strike). Switchgear integrated components to switch, protect,

meter and control power flow

Reactors - to limit fault current (series) or compensate forcharge current (shunt)

VT and CT - to measure primary current and voltage andsupply scaled down values to P&C, metering, SCADA, etc.

Regulators - voltage, current, VAR, phase angle, etc.


17/134


Types of ProtectionOvercurrent Uses current to determine magnitude of fault

Simple May employ definite time or inverse time curves May be slow

Selectivity at the cost of speed (coordination stacks) Inexpensive May use various polarizing voltages or ground current

for directionality Communication aided schemes make more selective


18/134


Instantaneous Overcurrent Protection (IOC) &Definite Time Overcurrent

t

I

CTI

50+2

50+2

CTI Relay closest to fault operatesfirst

Relays closer to sourceoperate slower

Time between operating forsame current is called CTI(Clearing Time Interval)

DistributionSubstation


19/134


(TOC) Coordination

t

I

CTI

Relay closest to fault operatesfirst

Relays closer to source

operate slower Time between operating for

same current is called CTI

DistributionSubstation


20/134


Selection of the curvesuses what is termed as a

time multiplier ortime dial to effectivelyshift the curve up ordown on the time axis

Operate region liesabove selected curve,while no-operate region

lies below it Inverse curves can

approximate fuse curveshapes

Time Overcurrent Protection (TOC)


21/134


Multiples of pick-up

Time Overcurrent Protection(51, 51N, 51G)


22/134


Classic Directional Overcurrent

Scheme for Looped SystemProtection

1 5

2 4

3

A

B

E

D

C

c

e

d

a

b

L L

L L

Bus X Bus Y

E D C B A

a b c d et

I


23/134


Types of ProtectionDifferential

current in = current out Simple Very fast Very defined clearing area Expensive Practical distance limitations

Line differential systems overcome this usingdigital communications


24/134


25/134


26/134


Types of ProtectionVoltage Uses voltage to infer fault or abnormal

condition May employ definite time or inverse time

curves

May also be used for undervoltage loadshedding Simple

May be slow Selectivity at the cost of speed (coordinationstacks)

Inexpensive


27/134


Types of ProtectionFrequency Uses frequency of voltage to detect power

balance condition May employ definite time or inverse time

curves

Used for load shedding & machineryunder/overspeed protection Simple

May be slow Selectivity at the cost of speed can be expensive


28/134


Types of ProtectionPower

Uses voltage and current to determinepower flow magnitude and direction Typically definite time

Complex May be slow Accuracy important for many applications

Can be expensive


29/134


Types of ProtectionDistance (Impedance)

Uses voltage and current to determine impedance of

fault Set on impedance [R-X] plane Uses definite time Impedance related to distance from relay Complicated Fast Somewhat defined clearing area with reasonable

accuracy Expensive Communication aided schemes make more selective


30/134


Impedance Relay in Zone 1 operates f irst Time between Zones is called

CTI

Source

A B

21 21

T1

T2Z A

ZB

R

X ZL


31/134


Impedance: POTT Scheme

POTT will trip only faulted line section RO elements are 21; 21G or 67N


32/134


Power vs. Protection Engineer:Views of the World

180 Opposites!

MVA = KV 2

Z( R

c )

Rv

+Q

+P

-Q

-P

M o r e P o w e

r

M o r e P o w e

r

SS

SS


33/134

Generation-typically at 4-20kV

Transmission-typically at 230-765kV

Subtransmission-typically at 69-161kV

Receives power from transmission system andtransforms into subtransmission level

Receives power from subtransmission systemand transforms into primary feeder voltage

Distribution network-typically 2.4-69kV

Low voltage (service)-typically 120-600V

TypicalBulk

PowerSystem

TypicalBulk

PowerSystem



34/134


1. Generator or Generator-Transformer Units

2. Transformers3. Buses

4. Lines (transmission and distribution)

5. Utilization equipment (motors, static loads, etc.)6. Capacitor or reactor (when separately protected)

Unit Generator-Tx zoneBus zone

Line zone

Bus zone

Transformer zoneTransformer zone

Bus zone

Generator

~

XFMR Bus Line Bus XFMR Bus Motor

Motor zone

Protection ZonesProtection Zones


35/134


1. Overlap is accomplished by the locations of CTs, the key source forprotective relays.

2. In some cases a fault might involve a CT or a circuit breaker itself, whichmeans i t can not be cleared until adjacent breakers (local or remote) areopened.

Zone A Zone B

Relay Zone A

Relay Zone B

CTs are located at both sides of CB-fault between CTs is cleared from both remotesides

Zone A Zone B

Relay Zone A

Relay Zone B

CTs are located at one side of CB-fault between CTs is sensed by both relays,remote righ t side operate only.

Zone OverlapZone Overlap

l i l h i l


36/134

Electrical Mechanical

Parameter Comparisons


El i l M h i l


37/134

Electrical Mechanical

Parameter Comparisons

ff f C i i & d i d


38/134

Effects of Capacitive & Inductive Loads

on Current


39/134


Motor Model and Starting Curves


40/134


1. One-line diagram of the system or area involved

2. Impedances and connections of power equipment, systemfrequency, voltage level and phase sequence

3. Existing schemes

4. Operating procedures and practices affecting protection

5. Importance of protection required and maximum allowedclearance times

6. System fault studies

7. Maximum load and system swing limits

8. CTs and VTs locations, connections and ratios

9. Future expansion expectance

10. Any special considerations for application.

What Info is Required to Apply ProtectionWhat Info is Required to Apply Protection


41/134

C37.2:Device

Numbers

Partial listing



42/134


One Line Diagram Non-dimensioned diagram showing how

pieces of electrical equipment areconnected

Simplification of actual system Equipment is shown as boxes, circles and

other simple graphic symbols

Symbols should follow ANSI or IECconventions


43/134


ultl n

1-Line Symbols [1]


44/134


ultl n

1-Line Symbols [2]


45/134


ultl n

1-Line Symbols [3]


46/134


ultl n

1-Line Symbols [4]


47/134


ultl n

1-Line [1]


48/134

1-Line [2]


49/134


ultl n

3-Line


50/134


ultl n

Diagram Comparison


51/134


ultl n

C37.2: Standard Reference Position 1) These may be speed, voltage, current ,

load, or similar adjusting devicescomprising rheostats, springs, levers, orother components for the purpose.

2) These electr ically operated devices areof the nonlatched-in type, whose contactposition is dependent only upon thedegree of energization of the operating,restraining, or holding coil or coils thatmay or may not be suitable forcont inuous energization . The de-energized posi tion of the device is that

with all coils de-energized 3) The energizing influences for thesedevices are considered to be,respectively, rising temperature, risinglevel, incr easing flow, rising speed,increasing vibration, and increasingpressure.

4.5.3) In the case of latched-in or hand-reset relays, which operate fromprotective devices to perform theshutdown of a piece of equipment andhold it out of service, the contacts shouldpreferably be shown in the normal,nonlockout position


52/134


ultl n

CB Trip Circuit (Simplified)

Showing Contacts NOT in


53/134


ultl n

Showing Contacts NOT inStandard Reference Condition

Some people show the contact

state changed like this

Showing Contacts NOT in


54/134


ultl n

Showing Contacts NOT inStandard Reference Condition

Better practice, do not change the

contact style, but rather usemarks like these to indicate non-standard reference position


55/134


ultl n

Lock Out Relay

86b

PR

86b

Shown in RESET position

86TC 86a

CB Coil Circuit Monitoring:


56/134


ultl n


T with CB Closed; C with CB Opened

Coil Monitor Input

Trip/Close Contact

+

T/CCoil

-

52/aor

52/b

Breaker

Relay

52/a for trip circuit52/b for close circuit



57/134


ultl n


Both T&C Regardless of CB state

Breaker

Relay

Breaker

Relay

Current Transformers


58/134


ultl n

Current transformers are used to step primary system currentsto values usable by relays, meters, SCADA, transducers, etc.

CT ratios are expressed as primary to secondary; 2000:5, 1200:5,600:5, 300:5

A 2000:5 CT has a CTR of 400

Standard IEEE CT Relay


59/134


ultl n

IEEE relay class is defined in terms of the voltage a CTcan deliver at 20 times the nominal current ratingwithout exceeding a 10% composite ratio error.

For example, a relay class of C100 on a 1200:5 CT means thatthe CT can develop 100 volts at 24,000 primary amps(1200*20) without exceeding a 10% ratio error. Maximumburden = 1 ohm.

100 V = 20 * 5 * (1ohm)200 V = 20 * 5 * (2 ohms)400 V = 20 * 5 * (4 ohms)800 V = 20 * 5 * (8 ohms)

Standard IEEE CT Relay Accuracy

Excitation Curve


60/134


ultl n

Excitation Curve

Standard IEEE CT Burdens (5 Amp)


61/134


ultl n

Application BurdenDesignation

Impedance(Ohms)

VA @5 amps

PowerFactor

Metering B0.1 0.1 2.5 0.9B0.2 0.2 5 0.9B0.5 0.5 12.5 0.9B0.9 0.9 22.5 0.9B1.8 1.8 45 0.9

Relaying B1 1 25 0.5B2 2 50 0.5

B4 4 100 0.5B8 8 200 0.5

Standard IEEE CT Burdens (5 Amp)(Per IEEE Std. C57.13-1993)

Current into the Dot, Out of the DotC f h d i h d


62/134


ultl n

Current out of the dot, in to the dotForward Power

IP

IS

IR

Relayor Meter

Forward Power

IP

IS

IR

Relayor Meter

Voltage Transformers


63/134


ultl n

VP

VSRelay

Voltage (potential) transformers are used to isolate and stepdown and accurately reproduce the scaled voltage for theprotective device or relay

VT ratios are typically expressed as pr imary to secondary;14400:120, 7200:120

A 4160:120 VT has a VTR of 34.66

Typical CT/VT Circuits


64/134


ultl n

Typical CT/VT Circuits

Courtesy of Blackburn, Protective Relay: Principles and Applications

CT/VT Circuit vs. Casing Ground


65/134


ultl n

g

Case ground made at IT location Secondary circuit ground made at first point of

use

Case

Secondary Circuit

Equipment Grounding


66/134


Equipment Grounding

Prevents shock exposure of personnel

Provides current carrying capability for theground-fault current Grounding includes design and construction of

substation ground mat and CT and VT safetygrounding

System Grounding


67/134


System Grounding

Limits overvoltages Limits difference in electric potential through local

area conducting objects Several methods

Ungrounded Reactance Coil Grounded High Z Grounded Low Z Grounded Solidly Grounded

System Grounding


68/134


1. Ungrounded: There is no intentionalground applied to the system-however its grounded throughnatural capacitance. Found in 2.4-15kV systems.

2. Reactance Grounded: Total systemcapacitance is cancelled by equalinductance. This decreases the

current at the fault and limits voltageacross the arc at the fault to decreasedamage.

X0


69/134


3. High Resistance Grounded: Limitsground fault current to 10A-20A.

Used to limit transient overvoltagesdue to arcing ground faults.

R0 = 2X 0

System Grounding

System Grounding


70/134


5. Solidly Grounded: There is aconnection of transformer orgenerator neutral directly to stationground.Effectively Grounded: R 0


71/134


Grounding Differences.Why?

Solidly Grounded Much ground current (damage) No neutral voltage shift

Line-ground insulation

Limits step potential issues Faulted area will clear Inexpensive relaying


72/134



Somewhat Grounded Manage ground current (manage damage) Some neutral voltage shift Faulted area will clear More expensive than solid, less expensive then

ungrounded


73/134



Ungrounded Very little ground current (less damage) Big neutral voltage shift

Must insulate line-to-line voltage

May run system while trying to find ground fault Relay more difficult/costly to detect and locate ground

faults

If you get a second ground fault on adjacent phase,watch out!

System Grounding Influences


74/134


Ground Fault Detection MethodsSource

50

51

50N

51N

50

51

50N

51N

50

51

50N

51N

Low/No Z

System Grounding Influences


75/134


Ground Fault Detection MethodsSource

50

51

50G

51G

50

51

50G

51G

50

51

50G

51G

Med/High Z

Basic Current Connections:


76/134


How System is GroundedDetermines How Ground Fault is Detected

Medium/HighResistance

Ground

Low/NoResistance

Ground


77/134


Substation TypesSubstation Types Single Supply

Multiple Supply

Mobile Substations for emergencies

Types are defined by number of

transformers, buses, breakers to provide

adequate service for application

Industrial Substation Arrangements(Typical)


78/134


(Typical)

Industrial Substation Arrangements(Typical)


79/134


( yp )

Utility Substation ArrangementsUtility Substation Arrangements(Typical)


80/134


Single Bus, 1 Tx, Dual supply Single Bus, 2 Tx, DualSupply

2-sections Bus with HS Tie-Breaker,2 Tx, Dual Supply

(Typical)



81/134


ultl n

Breaker-and-a-half allows reduction ofequipment cost by using 3 breakers foreach 2 circuits. For load transfer andoperation is simple, but relaying iscomplex as middle breaker is responsibleto both circuits

Bus1

Bus 2

Ring bus advantage that onebreaker per circuit. Also eachoutgoing circuit (Tx) has 2 sourcesof supply. Any breaker can be takenfrom service without disruptingothers.

(Typical)



82/134


ultl n

Double Bus: Upper Main andTransfer, bottom Double Main bus

Main bus

Aux. bus

Bus 1

Bus 2 T i e

b r e a

k e r

Main

Reserve

Transfer

Main-Reserved and TransferBus: A llows maintenance of anybus and any breaker

(Typical)

Switchgear Defined


83/134


ultl n

Assemblies containing electrical switching,protection, metering and management devices

Used in three-phase, high-power industrial,

commercial and utility applications Covers a variety of actual uses, including motor

control, distribution panels and outdoorswitchyards

The term "switchgear" is plural, even whenreferring to a single switchgear assembly (neversay, "switchgears")

May be a described in terms of use: "the generator switchgear" "the stamping line switchgear"

Switchgear Examples


84/134

Switchgear:MetalClad vs. Metal-Enclosed


85/134


ultl n

Metal-clad switchgear (C37.20.2) Breakers or switches must be draw-out design Breakers must be electrically operated, with anti-

pump feature All bus must be insulated Completely enclosed on all side and top with

grounded metal

Breaker, bus and cable compartments isolated bymetal barriers, with no intentional openings Automatic shutters over primary breaker stabs.

Metal-enclosed switchgear Bus not insulated Breakers or switches not required to be draw-out No compartment barriering required

Switchgear Basics [1]


86/134


ultl n

All Switchgear has a metalenclosure

Metalclad constructionrequires 11 gauge steel

between sections and maincompartments Prevents contact with live

circuits and propagation ofionized gases in the unlikelyevent of an internal fault.

Enclosures are also rated asweather-tight for outdoor use

Metalclad gear will includeshutters to ensure thatpowered buses are covered atall times, even when a circuitbreaker is removed.



87/134


ultl n

Devices such as circuit breakers or fused switchesprovide protection against short circuits and groundfaults

Interrupting devices (other than fuses) are non-automatic. They require control signals instructingthem to open or close.

Monitoring and control circuitry work together withthe switching and interrupting devices to turncircuits on and off, and guard circuits fromdegradation or fluctuations in power supply thatcould affect or damage equipment

Routine metering functions include operatingamperes and voltage, watts, kilowatt hours,frequency, power factor.



88/134


ultl n

Power to switchgear isconnected via Cables or BusDuct

The main internal bus carriespower between elements withinthe switchgear

Power within the switchgearmoves from compartment to

compartment on horizontal bus,and within compartments onvertical bus

Instrument Transformers (CTs& PTs) are used to step downcurrent and voltage from theprimary circuits or use in lower-energy monitoring and controlcircuitry.

Air Magnetic Breakers


89/134


ultl n


90/134

A Good Day in System


91/134


ultl n

Protection CTs and VTs bring electrical info to relays Relays sense current and voltage and declare

fault Relays send signals through control circuits to

circuit breakers Circuit breaker(s) correctly trip

What Could Go Wrong Here????


92/134

P i P f S i i


93/134


ultl n

Protection Performance Statistics

Correct and desired: 92.2% Correct but undesired: 5.3%

Incorrect: 2.1% Fail to trip: 0.4%

Contribution to Faults


94/134


ultl n

Fault Types (Shunt)


95/134


ultl n

Short Circuit CalculationFault Types Single Phase to Ground


96/134


ultl n

X

X

Z

Z

Z

G

BC

A

Fault Types Single Phase to Ground

Short Circ it Calc lations


97/134


ultl n

X

X

Z

Z

Z

G

BC

A

Short Circuit CalculationsFault Types Line to Line

Short Circuit CalculationsF l T Th Ph


98/134


ultl n

Fault Types Three Phase

Z

Z

Z

G

BC

AX

X

X

AC & DC Current Components

of Fault Current


99/134


ultl n

of Fault Current

Variation of current with timeduring a fault


100/134


ultl n

during a fault

Variation of generator reactanceduring a fault


101/134


ultl n

during a fault

Useful Conversions


102/134


ultl n

Per Unit System


103/134


ultl n

Per Unit System

Establish two base quantities:

Standard practice is to define

Base power 3 phase Base voltage line to lineOther quantities derived with basic powerequations

Per Unit Basics


104/134


ultl n

Short Circuit Calculations

Per Unit System


105/134


ultl n

Per Unit SystemPer Unit Value = Actual Quantity

Base Quantity Vpu = V actual

Vbase

Ipu = I actualIbase

Zpu = Z actualZbase

Short Circuit CalculationsPer Unit System


106/134


ultl n

Per Unit System

3 x kV L-L base I base =

x 1000MVA base

Z base =kV2L-L base MVA base

Short Circuit Calculations

Per Unit System Base Conversion


107/134


ultl n

Per Unit System Base Conversion

Zpu = Z actualZbase Zbase =

kV 2baseMVA base

Zpu1 = MVA base1kV 2base1X Zactual Zpu2 =

MVA base2kV 2base2

X Zactual

Zpu2

= Zpu1 x

kV 2base1 x

MVA base2kV 2base2 MVA base1


108/134


109/134


ultl n

Utility Information


110/134


ultl n

kV

MVA short circuit Voltage and voltage variation

Harmonic and flicker requirements

Generator Information


111/134


ultl n

Rated kV

Rate MVA, MW Xs; synchronous reactance

Xd; transient reactance Xd; subtransient reactance

Motor Drive


112/134


ultl n

kV Rated HP or KW Type

Sync or Induction

Subtransient orlocked rotor current

Is it regenerative Harmonic spectrum

Transformers Rated primary and secondary kV


113/134


ultl n

Rated MVA (OA, FA, FOA)

Winding connections (Wye, Delta) Impedance and MVA base of impedance

Reactors Rated kV

Ohms

Cables and Transmission Lines


114/134


ultl n

For rough calculations, some can be neglected Length of conductor Impedance at given length Size of conductor Spacing of overhead conductors Rated voltage Type of conduit Number of conductors or number per phase

ANSI 1-Line


115/134


ultl n

IEC 1-Line


116/134


ultl n

Short Circuit Study [1]


117/134


ultl n

Short Circuit Study [2]


118/134


ultl n


119/134

A Study of a Fault.


120/134


ultl n

Fault Interruption and Arcing


121/134


ultl n

Arc Flash Hazard


122/134


ultl n

Arc Flash Mitigation:Problem Description

An electric arc flash can occur if a conductive object gets


123/134


ultl n

An electric arc flash can occur if a conductive object getstoo close to a high-amp current source or by equipment

failure (ex., while opening or closing disconnects, rackingout) The arc can heat the air to temperatures as high as 35,000 F, and

vaporize metal in equipment

The arc flash can cause severe skin burns by direct heat exposureand by igniting clothing The heating of the air and vaporization of metal creates a pressure

wave (arc blast) that can damage hearing and cause memory loss(from concussion) and other injuries.

Flying metal parts are also a hazard.

Methods to Reduce

Arc Flash Hazard Arc flash energy may be expressed in I2t terms


124/134


ultl n

Arc flash energy may be expressed in I t terms,so you can decrease the I or decrease the t tolessen the energy

Protective relays can help lessen the t byoptimizing sensitivity and decreasing clearing time Protective Relay Techniques

Other means can lessen the I by limiting faultcurrent Non-Protective Relay Techniques

Non-Protective Relaying Methods

of Reducing Arc Flash Hazard System design Electronic current limiters (thesed i t d


125/134


ultl n

modifications increasepower transformerimpedance Addition of phase reactors Faster operating breakers

Splitting of buses Current limiting fuses

(provides partial protectiononly for a limited current

range)

devices sense overcurrent andinterrupt very high currents with

replaceable conductor links(explosive charge) Arc-resistant switchgear (this

really doesn't reduce arc flashenergy; it deflects the energyaway from personnel)

Optical arc flash protection viafiber sensors

Optical arc flash protection vialens sensors

Protective Relaying Methodsof Reducing Arc Flash Hazard

Bus differential protection (thisreduces the arc flash energy by

FlexCurve for improvedcoordination opportunities


126/134


ultl n

reduces the arc flash energy byreducing the clearing time

Zone interlock schemes wherebus relay selectively is allowedto trip or block depending onlocation of faults as identifiedfrom feeder relays

Temporary setting changes toreduce clearing time duringmaintenance

Sacrifices coordination

coordination opportunities Employ 51VC/VR on feeders

fed from small generation toimprove sensitivity andcoordination

Employ UV light detectors with

current disturbance detectorsfor selective gear tripping

Fuses vs. Relayed Breakers


127/134


ultl n

Arc Flash Hazards


128/134


ultl n

Arc Pressure Wave


129/134


ultl n

Arc Flash Warning Example [1]


130/134


ultl n



131/134


ultl n



132/134


ultl n

Copy of this presentation are at:

www L-3 com\private\Levine


133/134


ultl n

www.L 3.com\private\Levine



134/134


ultl n

QUESTIONS?

Documents

Total Protection Basics