ANNEX 7A EXPANSION OF THE SOUTH / SOUTHEAST ...€¦ · 1.2.1.4 Reactive compensation The reactive...

Notice of Tender to Auction No. 004/2000-ANEELANNEX 7C GROUPC Expansion of North / Northeast Interconnection

PROCURADORIAGERAL/ANEEL VISTO VOL. IV - Fl. 69 de 192

ANNEX 7A

EXPANSION OF THE SOUTH / SOUTHEASTINTERCONNECTION

BASIC TECHNICAL REQUIREMENTS

AND CHARACTERISTICS

OF THE TRANSMISSION FACILITIES



CONTENTS

1 BASIC REQUIREMENTS FOR THE FACILITIES 72

1.1 INTRODUCTION ........................................................................................................................................................... 721.1.1 General Description 721.1.2 Basic Configuration 741.1.3 System data used 751.1.4 General requirements 75

1.2 TRANSMISSION LINES.................................................................................................................................................... 761.2.1 Electrical Indicators 761.2.2 Mechanical indicators 78

1.3 SUBSTATIONS ............................................................................................................................................................... 801.3.1 General requirements 801.3.2 Equipment requirements 81

1.4 SERIES COMPENSATION ................................................................................................................................................ 841.4.1 Basic information 841.4.2 Requirements for the varistors of the reactive series compensation equipment values 84

1.5 TECHNICAL REQUIREMENTS OF THE PROTECTION SYSTEMS............................................................................ 851.5.1 General 851.5.2 Transmission line protection 851.5.3 Transformer Units Protection (500kV-345kV) 881.5.4 Reactor protection 891.5.5 Busbar Protection System 901.5.6 Circuit breaker fault protection system 901.5.7 Series Capacitor Protection 911.5.8 Special Protection Systems 91

1.6 SUPERVISION AND CONTROL SYSTEMS............................................................................................................. 921.6.1 Introduction 921.6.2 Supervision and control requirements of the facilities 921.6.3 Requisitos de supervisão pelo agente proprietário das subestações 981.6.4 ONS supervision and control requirements 1001.6.5 Quality assessment and availability requirements 105

1.7 BILLING METERING SYSTEM................................................................................................................................ 1101.7.1 Location 110

1.8 TECHNICAL REQUIREMENTS OF DIGITAL OSCILLOGRAPHY SYSTEM ........................................................ 1111.8.1 General aspects 1111.8.2 Description of features 1111.8.3 Digital Disturbance Meter trip-switch 1121.8.4 Time Synchronization 1121.8.5 Electromagnetic compatibility requirements 1121.8.6 Characteristics of input and output signals 1121.8.7 Occurrence metering capacity. 113



1.8.8 Communication requirements 1141.9 TECHNICAL REQUIREMENTS OF THE TELECOMMUNICATIONS SYSTEM TO BE IMPLEMENTED.................... 115

1.9.1 General requirements 1151.9.2 Remote protection requirements 1161.9.3 Voice channel requirements 1171.9.4 Data transmission requirements 117

1.10 BASIC REQUIREMENTS FOR THE BASIC AND ALTERNATIVE CONFIGURATIONS...................................... 1191.10.1 Operating voltage 1191.10.2 Maneuvering requirements associated with the transmission lines 1191.10.3 Opening and closing of the disconnecting and earth disconnecting devices 1211.10.4 Circuit breaker cutout requirements 1211.10.5 Transformer unit maneuvering requirements 121

2 ENGINEERING AND PLANNING STUDIES ON THE EXPANSION OF THE 500 KVSOUTH/SOUTHEAST AND 500 KV SUBSTATIONS BELONGING TO THE INTERCONNECTION122

2.1 ENGINEERING AND PLANNING STUDIES AND THE RELATED TECHNICAL DOCUMENTATION FOR THESOUTH/SOUTHEAST INTERCONNECTION................................................................................................................... 122

2.1.1 Reports 1222.1.2 Electrical System Data Studies 122

2.2 REPORTS ON THE BASIC REQUIREMENTS AND CHARACTERISTICS................................................................. 1222.3 SUBSTATION DOCUMENTS.................................................................................................................................. 123

2.3.1 BATEIAS - COPEL 1232.3.2 IBIÚNA SUBSTATION FURNAS 123

3 ENVIRONMENT AND LICENSING 125

3.1 GENERAL................................................................................................................................................................. 1253.2 DOCUMENTATION AVAILABLE............................................................................................................................. 125

4 GUIDELINES FOR DESIGN PREPARATION 126

4.1 ENGINEERING AND SYSTEM STUDIES ........................................................................................................................... 1264.2 BASIC SUBSTATION DESIGN................................................................................................................................ 1264.3 BASIC DESIGN FOR THE STRETCHES OF THE TRANSMISSION LINE........................................................... 126

4.3.1 Technical report 1264.3.2 Design standards and documentation. 127

5 TIME-SCHEDULE 128

5.1 PHYSICAL TIME-SCHEDULE FOR TRANSMISSION LINES..................................................................................... 1305.2 PHYSICAL SUBSTATION TIME SCHEDULE......................................................................................................... 131



1 BASIC REQUIREMENTS FOR THE FACILITIES

1.1 INTRODUCTION

1.1.1 General DescriptionThis Annex presents the basic technical requirements and characteristics of the transmission facilitiesconstituting the expansion of the South / Southeast Interconnection, consisting of a double-circuit500kV Transmission Line interconnecting the Bateias Substation owned by COPEL in Paraná State tothe Ibiúna Substation owned by FURNAS in São Paulo State, designed to strengthen the connectionbetween the South and the SOUTH / SOUTHEAST Center-West power systems.

Figure 1 - Interconnection Links, presents a simplified diagram of the main links in the South /Southeast Interconnection at the moment.

FIGURE 1 INTERCONNECTION LINKS

Uruguay

113388kkVV223300kkVV

CCTTEEEEPP

SSOOUUTTHH

SSOOUUTTHHEEAASSTT

CCOOPPEELL

EELLEETTRROOSSUULLIIvvaaiippoorrãã 550000kkVV

TTrraaffoo ddeeIIvvaaiippoorrãã22 xx11665500MMVVAA

IIvvaaiippoorrãã IIttaabbeerráá

TTiijjuuccooPPrreettoo

FFoozz

IIttaaiippuuFFUURRNNAASS

ENERSUL

Argentina

550000 kkVV776655 kkVV



Figure 2 Gives the electrical and geographic map of the South / Southeast system, including theprojects associated with the Expansion of the South / Southeast Interconnection.

FIGURE 2- ELECTRICAL AND GEOGRAPHICAL MAP OF THE SOUTH / SOUTHEAST SYSTEM

EXPANSION OFSOUTH /SOUTHEASTINTER



The Expansion of the South / Southeast Interconnection consists of the implementation of the projectslisted in subitem 1.1.2, basically consisting of a 500 kV double circuit running between Bateias andIbiúna.The implementation of the expansion of the South / Southeast Interconnection covered by the Auctionalso consists of the reactive compensation associated with the circuits, and the terminal equipment formaneuvering, protection, supervision and control, telecommunications and all other items of equipment,services and facilities required to render the public utility transmission service, even if not expresslylisted in this Annex 7A.

1.1.2 Basic ConfigurationThe basic configuration consists of the enterprises listed in the following Tables. The transmissionlines are listed in Table 1, while the substations are given in Table 2, not including the reserve units inthe quantities presented therein.

TABLE 1 TRANSMISSION LINES

Start Finish Voltage (kV) Circuit Length (km)Bateias Ibiúna 500 1st 328Bateias Ibiúna 500 2nd 328

Note: The study on the Preliminary Assessment of the Technical Environmental Characteristics of thePotential Corridor for the 500 kV Transmission Line between Bateias and Ibiúnas (Avaliação preliminardas caracteristícas técnicas ambientais do corredor potencial para a linha de transmissão 500 kVBateias – Ibiúnas) reduced the length of the Transmission Line to 328 kilometers from 340 kilometers inthe initial studies.

TABLE 2 SUBSTATIONS

Substation Voltage (kV) Main Projects Unit CapacityBateias 500 2 line input facilities

2 busbar interconnections6 single-phase line reactors 45.3(1)

Ibiúna 500 1 substation yard2 line input facilities3 busbar interconnections6 single-phase line reactors 22.7(1)2 transformer units 750(3)2 transformer unit connections2 series capacitor banks (2)

345 2 transformer unit connectionsNotes:

a) The Unit Capacity of the reactors in MVAr referred to 500 kV.b) The capacity of the series capacitors and the compensation level of the Transmission Line circuits

between Ibiúnas and Bateias should be defined in a manner producing the same flow distributionunder normal conditions and during emergencies, pursuant to the study given in the Report madeavailable in item 2.1, for the rated current of 2,200 A.

c) The capacity of the transformer units, in MVA is referred to 500kV voltage.d) For the position of the equipment, consult the diagrams made available.



The above-mentioned basic configuration and the technical requirements in this Annex 7A are theminimum performance standards for other solutions, which should be demonstrated throughdocumentary proof constituting technical justification.

1.1.3 System data usedThe system data used in the studies for the permanent and temporary schemes drawn up to define thebasic configuration are made available, pursuant to the documentation listed in item 2.The data on the permanent and dynamic system studies are available in the format of the ANATEMand ANAREDE Network Simulation Digital Programs from the Eletrobras R&D Center (CEPEL).The data on the temporary electromagnetic studies are available in the ATP digital program format.

1.1.4 General requirementsThe design and construction of the transmission lines and the terminal substations should comply withthe latest revisions of the Brazilian Technical Standards Association (ABNT Associação Brasileira deNormas Técnicas) standards where applicable thereto, or with the latest revisions of the IEC, ANSI orNEC Standards, in this order of preference, unless expressly indicated otherwise.All the local environmental conditions required for the preparation of the project, the constructionactivities and the operation of the facilities should be obtained by the TRANSMISSION UTILITY.The TRANSMISSION UTILITY is assigned to the responsibility and prerogative of sizing and specifyingthe equipment and transmission facilities constituting the Public Utility Transmission Service covered bythis competitive bidding process, in order to comply with this Annex 7A and good engineering practices,as well as the market reservation policy.



1.2 TRANSMISSION LINES

1.2.1 Electrical Indicators

1.2.1.1 The positive sequence longitudinal reactance should allow the distribution of bulk power flows in theSouth / Southeast Interconnection similar to the basic configuration given in the studies for the Reportsmade available in item 2.1.

1.2.1.2 Loading of the transmission linesThe circuits should be able to withstand a current of 1,500 A and 2,600 A respectively on a permanentbasis and during emergencies, with no violation of any performance criteria.

1.2.1.3 Definition of the maximum deflection of the conductors and sizing the lightning arrester cablesThe project design for locating the structures and sizing the lightning arrester cables for each stretch ofthe transmission line should adopt the following climate conditions:• Maximum average temperature for the region;• Maximum sunshine;• Wind of no more than 1 m/s.The definition of the maximum deflection of the conductor cables should comply with NBR-5422, takinginto account the maximum average temperature for the region, maximum sunshine, wind of no morethan 1 m/s, for a maximum current of 1,900 A.When sizing the lightning arrester cables, the same climate conditions should be taken intoconsideration as for the definition of the maximum deflection of the conductors, as well as the followingadditional conditions:• Short-circuit current levels of 40 kA at all substations;• Possibility that the lightning arrester cables for stretches of the line are connected to the earthing

network of the substations and earthed at all structures;• Fault elimination time corresponding to the back-up protection.

1.2.1.4 Reactive compensationThe reactive compensation deriving from the basic configuration is given in Table 2.The reactive compensation deriving from the transmission lines should be defined in a manner wherebythe group formed by the lines and their compensations meets the requirements given in item 1.10 andthe other criteria in this Annex 7A.The data, criteria and conditions needed for the analysis of the TRANSMISSION UTILITY are found inthe documents listed in item 2.

1.2.1.5 Joule loss in the lightning arrester and conductor cablesThe positive sequence resistance per length unit in the transmission lines for a rated frequency of 60Hz at a temperature of 75º C should be equal to or less than that of the basic configuration: 0.019Ω/km.The total loss of the lightning arrester cables should be no greater than that corresponding to twocontinuous galvanized steel Extra High Voltage cables with a diameter of 3/8, earthed at all structuresand in the substations earthing network.



1.2.1.6 ImbalanceThe transmission lines should have a complete transposition cycle, preferably with stretches measuring1/6, 1/3, 1/3 and 1/6 of the total length.

1.2.1.7 Insulation coordination

a) Performance in case of atmospheric dischargesNo disconnections may be caused by direct discharges due to the predominant terrain profile in thisregion.The number of disconnections caused by atmospheric discharges may not exceed one de-energization/ 100km / year.

b) Insulation at maximum operating voltageThe insulation of the transmission lines at maximum operating voltage should be sized taking thepollution characteristics of the region into account, according to the classification in Publication IEC815 Guide for the selection of insulators in respect of polluted conditions.The minimum pollution level adopted should be compatible with the minimum outflow distance of 25mm/kV , for the maximum phase-earth voltage.The insulation of the transmission lines at maximum operating voltage should be sized taking the swingof the chain of insulators into account, when blown by the wind, with a recurrence interval of at least 30years.A minimum distance should be maintained in order to avoid discharge at the maximum operatingvoltage between any line conductor and the edge of the right-of-way under the maximum deflection andswing conditions, as stipulated in NBR-5422.

c) Insulating maneuversThe maximum fault risk during energization and reconnection maneuvers should be limited to thefigures given in Table 3.

Table 3 maximum fault risk during energization and reconnection maneuversFault risk (adimensional)Maneuver Between phase and earth Between phases

Energization 10 3 10 4

Reconnection 10 2 10 3

1.2.1.8 Field effectsThe effects covered below should be checked at the maximum operating voltage of the line, namely550 kV.

a) Visual coronaThe transmission lines should not present a visual corona around the conductor cables andmetalwork for 90% of good weather conditions.

b) Radio interferenceThe signal/noise ratio at the edge of the right-of-way, indicating the level of immunity of the radiosignals (RI) should be at least equal to 24 dB based on the minimum signal level given inDENTEL standard for 50 % of the atmospheric conditions for the year.

c) Audible noise



The audible noise (RA) at the edge of the right-of-way under the maximum operating voltageunder conditions of drizzle (<0.00148 mm/min) or mist lasting 4 hours, or during the first 15minutes of rain should be equal to no more than 58 dBA.

d) Electrical fieldThe electrical field one meter away from the ground at the edge of the right-of-way should be 5kV/m. The field inside the right-of-way should not cause any adverse effects on human beings,due to the use of each stretch thereof.

e) Magnetic fieldThe magnetic field under maximum loading factor conditions and at the edge of the right-of-wayshould be less than or equal to 67 A/m, equivalent to magnetic conduction of 83 µT. The fieldinside the right-of-way should not cause any adverse effects on human beings, due to the use ofeach stretch thereof.

1.2.2 Mechanical indicators

1.2.2.1 Basic conditions for the conductor cable regulation project.

a) Basic status• For minimum temperature conditions, the axial stress should be limited to 33% of the cable failure

stress.• For wind conditions with a recurrence interval of 50 years, the axial stress should be limited to 50%

of the cable failure stress.• For extreme wind conditions, the axial stress should be limited to 70% of the tensile stress of the

cable.b) Normal stress status (EDS)

For the final positioning, at the average temperature with no wind, with the stress level complyingwith the figures given in NBR-5422 Standard (March 1985).

c) Reference statusThe minimum conductor cable clearance from the ground will not take wind pressure intoconsideration.

1.2.2.2 Mechanical design criteriaFor the mechanical design of the transmission line supports, the loading factors caused by the action ofthe wind on the physical components of the line should be established on the basis of probabilisticcharacterizations of wind-speeds in the region, treated differently by type: Extended Pressure Systems(EPS) and Thunderstorms (TS).For the wind gauging stations covered in the study, the following parameters should be defined:• Average and variation coefficient (percentage) of the maximum annual wind-speed series at a

height of 10 meters, with average integration times of 3 seconds and 10 minutes;• Maximum annual wind speed at a height of 10 meters with a recurrence interval of 250 years,

average integration times of 3 seconds and 10 minutes. If the number of years in the wind-speeddata series is low, the estimate of the annual maximum wind speed should be based on at least avariation coefficient compatible with the longest wind-speed series measured in the region;

• Gust coefficient for wind speed at a height of 10 meters referred to the average integration time of10 minutes;

• Rugged terrain coefficient for the measuring location.



The mechanical design of the transmission line should be prepared in compliance with IEC 826 International Electrotechnical Commission: Loading and Strength of Overhead Transmission Lines.In addition to the hypotheses covered in the IEC Standard, it is also mandatory to introduce loadinghypotheses that reflect Thunderstorms (TS).The electromechanical design of the transmission line should comply with the level of reliabilitycorresponding to a recurrence interval equal or greater than 250 years, referred to an intermediate levelat 2 and 3 stipulated in IEC 826.

1.2.2.3 Mechanical fatigue of the cablesThe TRANSMISSION UTILITY will be solely responsible for the development and application ofsystems to prevent vibrations and effects related to cable fatigue.Vibration and damper system studies for the purposes of controlling cable fatigue should be undertakenin order to ensure the lack of damage to the transmission-line cables, preparing a JustificatoryTechnical Report.

1.2.2.4 FoundationsThe foundations for each structure should be designed structurally and geotechnically in such a way asto ensure all stresses on each pylon are aligned to the specific conditions of its foundation.The loads on the foundations should be calculated for each structure individually under real loadingsituations, taking into account their specific application conditions: Deadweight Span Stress, Wind SpanStress, Transmission Line Connection Point and Deflection Angle, and Pylon height.The physical and mechanical properties of the foundation soil for each structure should be determinedin an accepted scientific manner, accurately portraying the geomechanical parameters of the soil, withthe following stages being implemented:• Preliminary physiographic study and analysis of the route of the transmission line with a

subsequent preparation of the geotechnical survey plan.• Reconnaissance of the subsoil with geological and geotechnical characterization, both qualitative

and quantitative, determining the geometric parameters• Expert geotechnical opinion with the preparation of technical guidelines and recommendations for

the project.When calculating the foundations, regional geomorphological aspects should be taken intoconsideration that influence the state of the foundation soil, whether in terms of sensitivity, or propensityto expand or collapse, taking seasonal factors into account.The definition of the type of foundation, as well as its structural and geotechnical sizing should beundertaken while taking into consideration the cracking and skewing limits for the soil support capacityand resistance to compression, dragging and horizontal effects, through the use of rational calculationmethods that are not open to query and generally accepted in geotechnical engineering.



1.3 SUBSTATIONS

1.3.1 General requirements

1.3.1.1 Basic informationThe TRANSMISSION UTILITY should prepare and present the studies required to define thecharacteristics and performance levels for all items of equipment, taking into account that they will beconnected to the existing system.All items of equipment should be specified in a manner that does not adversely affect or limit theoperations of the substations, nor impose operating constraints on the other facilities in theinterconnected system. Neither should equipment be used that prevents the use of apparatus based onother existing technologies or other supplies or future expansions.The new facilities should be compatible with the existing substations and other aspects of theequipment requirements. The basic requirements and criteria should be complied with for the existingequipment and facilities at the Bateias and Ibiúna substations as specified in the following documents:GTS-IBN-S/SE-001 and GTS-BTA-S/SE-001, with aspects inherent to the DC/AC converter beingcomplied with at the Ibiúna Substation.At the existing substations, the basic configuration includes equipment with basic electricalcharacteristics similar to the existing equipment, which are presented in the above-mentioneddocuments.

1.3.1.2 Yard arrangementsThe arrangement used in the existing 500 kV Bateias Substation Yard consists of the circuit breakerand a half type, as well as in the 345 kV Yard and the future 500 kV Yard at the Ibiúna Substation.Physical space should be set aside for installing the reactor maneuvering equipment at bothsubstations.Over the long term, 5 line input facilities are planned for the 500 kV yard at the Ibiúna Substation, 2(two) to Bateias; 2(two) to Campinas and 1 (one) planned for the future.

1.3.1.3 Current capacity

(a) Current on permanent basisThe sizing of the busbars and other equipment should take into account the maximum current value forthe permanent operating condition given in Table 4.

TABLE 4 MAXIMUM CURRENT VALUE ON PERMANENT BASISRated Voltage (kV) Maximum Current on

Permanent Basis (A)500 3150345 3150

(b) Short-circuit capacityThe equipment and other facilities should be able to withstand the short-circuit level in the busbars ofthe yards stipulated in Table 5.

TABLE 5 MAXIMUM SHORT-CURRENT VALUERated Voltage (kV) Maximum Short-Current Value (kA)500 40



345 63(c) Earthing SystemThe earthing system for the substations should comply with the criteria for a solidly earthed system.

1.3.1.4 Supportability

a) Voltage on permanent basisThe sizing of the busbars and the equipment should take into account the maximum voltage value of550 kV for the operating condition on a permanent basis given in Table 6.

TABLE 6 MAXIMUM EFFECTIVE VOLTAGE VALUE BETWEEN PHASES ON PERMANENT BASISRated Voltage (kV) Maximum Voltage on

Permanent Basis(kV)500 550345 362

b) Insulation under pollutionThe facilities should be insulated in order to deal with the pollution characteristics of the region undermaximum operating voltage, according to the classification given in Publication IEC 815 Guide for theSelection of Insulators in Respect of Polluted Conditions.

c) Protection against atmospheric dischargesThe protection system against atmospheric discharges for the substations should ensure perfectshielding of the facilities for currents of over 2 kA, and ensure a defect risk of less than or equal to onedischarge each 50 years.Should there be any buildings, they should comply with the requirements of Technical StandardNBR5419.

1.3.1.5 Field effects

a) Corona effectThe components of the substations, particularly the conductors and metalwork should not present acorona effect at 90 % of good weather conditions. The minimum tension for the start and end of thevisual corona should comply with the figures given in Table 7. The corona elimination voltage should belocated above the maximum operating voltage.

TABLE 7 MINIMUM VOLTAGE FOR START OF VISUAL CORONARated Voltage (kV) Msal Voltage (kVrms earth-phase)500 350345 250

b) Radio interferenceThe maximum external radio interference voltage value for the equipment should be 2,500 µV/m at1000Hz, at the phase-earth voltage 550/√3kV and 362/√3kV.

1.3.2 Equipment requirements

1.3.2.1 Transformer unitsAt least two 750 MVA transformer units should be planned for Ibiúna. Transformer unit is taken to meantransformers or autotransformers, either triple-phase or in single-phase unit banks. The units should be



fitted with an On Load Tap Changer whose requirements are defined below and with cooling stagesthat can meet the procedures for the application of the loads established in ABNT Standard NBR 5416.The existence of tertiary windings is an option of the TRANSMISSION UTILITY, which shoulddemonstrate that the lack thereof does not adversely affect system performance.

(a) SwitchingThe transformer units should be fitted with On Load Tap Changers. The TRANSMISSION UTILITY willdefine the winding where the switches will be installed, whose operation should control the voltage atthe 345 kV busbar.Provision should be made to cover the possibility of operating with at least 9 (nine) transformationratios, equally spaced between the effective minimum value between the 472.5 kV and 577.5 kVminimum and maximum phases at the 525 kV busbar or 310.5 kV and maximum of 379.5 kV at the 345kV busbar.The On Load Tap Changer should be designed, manufactured and tested in accordance withPublication IEC-214 On Load Tap Changers.

(b) TapsThe fixed taps for the primary windings should correspond to the following voltages:(525 ± 10%): 577500 / 525000 / 472500 V.

(c) Operating ConditionsThe transformer units should be appropriate for operating in parallel at the 525kV and 345kV terminals.

d) ImpedancesThe impedance values corresponding to a temperature of 75 °C should be limited to a range of 10% -12%, referred to the transformation power capacity base.

(e) LossesThe total loss values (losses in the copper plus losses in the iron) at full loads should be less than 0.3% of the power capacity of the transformer units.

(f) Connecting the windingsThe primary and secondary windings of the transformer units should be connected in a star formationwith the neutral accessible for solid earthing.

(g) OvervoltagesEach transformer unit should be able to withstand an idle overexcitation profile at 60 Hz as shown inTable 8 at any operating tap (values in pu of the tap voltage).

TABLE 8- ACCEPTABLE OVEREXCITATION LEVELS FOR TRANSFORMER UNITSDuration Voltage (pu)

12 seconds 1.3530 seconds 1.251 minutes 1.208 minutes 1.15

1.3.2.2 ReactorsThe reactor windings should be interconnected in a star formation with the neutral accessible for solidearthing by reactors or resistors.The insulation of the neutral should be sized for connection with neutral reactors in order to allowunipolar reconnection and eliminate parallel circuit resonance.



The magnetization curve should be linear up to a voltage of 750kV.The values for the total losses (losses in the copper plus losses in the iron) referred to a voltage of 550kV and the rated power capacity should be less than 0.3 % of the rated power capacity.

1.3.2.3 Circuit BreakersThe fast reconnection and operating cycle of the circuit breakers should meet the requirements in thestandards applicable thereto.The maximum downtime for the 500 kV and 345 kV circuit breakers should be 2 (two) cycles.The 500 kV and 345 kV circuit breakers should be able to undertake the maneuvering operations listedin item 1.10.4.The 500 kV and 345 kV circuit breakers should have two independent trip-switch logic circuits for polediscrepancy detection, with triple-pole and unipolar drives, as well as an operating cycle compatiblewith the use of automatic single-try triple-pole and unipolar reconnection schemes.

1.3.2.4 Disconnecting switches, earthing plates and earthing switchesThis equipment should meet the requirements in the standards applicable thereto and be able to handlethe maneuvers listed in item 1.10.3.The earthing plates and earthing switches for the transmission lines should be fitted with the inducedcurrent breaker capacity in compliance with class B of the IEC 1129 standard.

1.3.2.5 Lightning arrestersThe lightning arresters should be station-type, zinc oxide (ZnO), appropriate for outside installation andwith no spark gap. The use of lightning arresters should be planned at the interface with the existingsystem (line input facility).

1.3.2.6 Current and Potential TransformersThe characteristics of the current and potential transformers such as: number of secondaries,transformation ratios, load, accuracy, etc., should meet the needs of the protection and meteringsystems.The current transformers should have secondary windings in individual cores, and be appropriate foroutside installation.The potential transformers should be capacitative, and be appropriate for outside installation.

1.3.2.7 Indoor facilitiesAll instruments, panels and other items of equipment in the protection, command, supervision andtelecommunication systems should be sheltered and designed according to the standards applicablethereto, in order to ensure flawless performance of these systems in their protection against prematurewear and tear.In case of buildings, the TRANSMISSION UTILITY is responsible for complying with the municipalstandards applicable thereto as well as labor safety standards.



1.4 SERIES COMPENSATION

1.4.1 Basic informationThe location of the reactive series compensation equipment for the Expansion of the South / SoutheastInterconnection is given in Table 2. The basic configuration assumes that the two transmission linecircuits will be compensated at 55% of their reactance.The protection and control system for the associated equipment considers the occurrence of two typesof defects, namely:• Internal defect shown in Figure 3• External defect.

Figure 3 Internal defect

1.4.2 Requirements for the varistors of the reactive series compensation equipment valuesAll the varistors in the reactive series compensation equipment should be based on metal oxide.The energy requirements of the varistors should be defined taking into consideration all the forecastscenarios and exchanges, from the initial configuration through to the planning horizon years. Theserequirements should be defined by the TRANSMISSION UTILITY for the most critical external faultcondition, noted with the parallel line out of service.The varistor protection devices may be tripped under the following situations:Three-phase, two-phase or single-phase internal faults;External fault eliminated over more than 100 ms, three-phase, two-phase or single-phase;Three-phase external faults eliminated over 100 ms with unsuccessful reconnection of only one terminal,

resulting in higher energy for the varistor under calculation, occurring over 600 ms and the openingof this terminal at 700 ms. (Times referred to the instant of occurrence of the fault).

Internal faults = faults in the linecompensated by the bank.



1.5 TECHNICAL REQUIREMENTS OF THE PROTECTION SYSTEMS

1.5.1 GeneralAll the protection relays should use numerical digital technology.The protection systems should be integrated at the installation level allowing local and remote accessfor adjustment, recording events, size of input and other pertinent information for each of the protectionrelays or systems. The architecture and protocols used should not impose constraints on the integrationof new equipment, nor the operation of the facilities.All digital equipment and systems should be self-monitored and have self-diagnosis facilities, withautomatic blockage of operations in case of defect, with local and remote indications of any fault ordefect.All protection systems should accept a fault or defect in a component, without this resulting in thedegradation of its end-performance.The current transformers should be arranged in the facility in a way that allows overlapping protectionzones for adjacent primary items of equipment.The equipment protection should be designed in a way that does not depend on remote back-upprotection for the transmission system.The main and (alternate or back-up) protection systems should be powered by independent banks ofbatteries, rectifiers and continuous current circuits.The protection systems should be fitted with outlets for operating two circuit breakers with independenttrip-switches as well as for unipolar and/or triple-pole start-up switches.The current and voltage information for each protection system, whether main, alternate or backup,should be obtained from the current transformer cores and secondary transformers with differentcapacities.All the protection systems and associated equipment should comply with the electromagneticcompatibility standards applicable thereto at the levels of severity appropriate to installation in extra-high voltage substations.The protection systems should comply with the existing requirements in terms of sensitivity, selectivity,speed and operating reliability, in order to avoid downgrading the performance of the power systemunder operating conditions or during disturbances.

1.5.2 Transmission line protectionThe set of equipment and accessories required as being sufficient to detect and eliminate all types ofdefects and other abnormal operating conditions for the transmission lines, distinguishing betweeninternal and external faults on the protected line..

1.5.2.1 Reconnection schemesThe transmission lines should be equipped with reconnection schemes according to the philosophydefined below:

1.5.2.1.1 General requirementsThe reconnection scheme should allow the selection of the type and number of reconnection attemptswith two possibilities: triple-pole and unipolar. In the triple-pole position, any start-up order launched bythe protection system will switch off the three poles of the circuit breaker and begin triple-pole



reconnection. In the unipolar position, in case of a phase-earth defect, the disconnection and thereconnection of the two line terminals should be unipolar; for other types of short circuit, thedisconnection and the reconnection should be triple-pole. Should the reconnection cycle beunsuccessful (for instance, permanent short circuits) the disconnection will be triple-pole.In substations with a ring arrangement, double busbar with double circuit breaker or circuit breaker anda half, provision should be made for the possibility of reconnection through either of the two circuitbreakers associated with the line. The placement or removal of the service, the selection of the type ofreconnection and the circuit breaker to be reconnected should be handled through a selection switchand/or the supervision and control system for the substation.The reconnection relays should be fitted with independent timers with the possibility of adjusting thedowntime for unipolar and triple-pole reconnection.Once a specific reconnection cycle has begun, a new cycle will only be allowed after a minimumadjustable period that will start with the opening of the circuit breaker,The protection to be supplied should offer facilities for optionally undertaking automatic reconnectiononly in case of internal phase-earth short circuits.The synchronism verification scheme should supervise all triple-pole closing commands for the circuitbreakers, consisting of a synchronism checking unit and under-voltage and overvoltage units.

1.5.2.1.2 Triple-pole reconnection schemeThe automatic triple-pole reconnection schemes are for use only after elimination of faults by high-speed or instantaneous protection facilities, and should not be undertaken through manually openedcircuit breakers, during timed protection function operations, defects in busbars, defects in circuitbreakers, receipt of start-up commands directly from the remote terminal, overvoltage protection andstart-up protection due to loss of synchronism, as well as the transformer or line reactor protectionsystems.Either of the transmission line terminals may be selected as the first terminal to be switched on(LEADER) and should be reconnected after the down time. The other terminal (FOLLOWER) should beswitched on after a synchronism-checking relay. In order to select the terminal to be reconnected first,both the terminals should be fitted with reconnection systems and synchronism checking relays.The LEADER terminal should be reconnected only if there is no voltage on the line. The FOLLOWERterminal should be reconnected only after checking synchronism and with an adequate voltage level onthe transmission line side. The synchronism-checking relay should monitor the angle and flow betweenthe voltages to be synchronized.

1.5.2.1.3 Unipolar reconnection schemeThe automatic unipolar reconnection schemes are for use only after the elimination of earth-phasedefects through high-speed or instantaneous protection facilities. These automatic reconnectionschemes should not be tripped by the same functions described in the previous item.The protection facilities should be equipped with phase selection schemes appropriate for eachapplication in order to undertake unipolar opening for single-phase defects on the transmission lines.Should remote protection facilities be used, the phase selection units used should be independent ofthe start-up units and protection measures.During the open-phase operations period required by the unipolar reconnection down-time, theovercurrent directional functions should be blocked for the high-sensitivity zero and negative sequencesassociated with remote protection schemes based on overreach logic, if necessary. During this period



of time, any start-up order sent to the circuit breaker, coming from other phases, for instance, should betriple-pole and should not start up the reconnection of the line.

1.5.2.1.4 Synchronism checking relaysThe synchronism checking relays used in the triple-pole reconnection schemes should allowadjustment of the reconnection time, taken as from the opening of the circuit breaker and including thetypical downtime for the respective voltage class. Additionally, this should allow adjustments ofdifferences in voltage, angular phase shift, different frequencies and also allow the selection of thefollowing conditions for closing the circuit breaker:• Live busbar dead line,• Dead busbar live line,• Live busbar live line,• Dead busbar dead line.

1.5.2.2 Main and Alternate Protection SystemsEach line terminal should be fitted with two independent sets of protection equipment: main protectionand alternate protection, fully redundant, each providing full primary and backup protection and bothable to protect the transmission line on which they are installed, whether or not series compensation isused.The primary protection equipment used in the main and alternate protection systems should be able todetect and eliminate faults individually and independently between phases and between phase andearth for 100% of the length of the protected line, with no intentional time lags.The total elimination time for all types of faults, including the circuit breaker opening time for all the lineterminals should not exceed 100 ms.The backup protection constituting part of the main and alternate protection systems should be phasedin, consisting of remote relays or functions included in the main/alternate protection schemes fordefects between phases and earth-phase (21/21N), with at least three direction/direct protection zonesand through neutral directional overcurrent relay (67N) with instant and timed units.The main and alternate protection equipment should allow the correct selection of the defective phasesto order the disconnection of the circuit breaker on either a single- or triple-pole basis. The use ofremote units with zero sequence compensation is banned for phase selection.Should remote relay protection systems be used, they should be endowed with the following functionsand characteristics:• Metering elements to detect faults between phases and between phases and earth (21/21N), with

at least three direct zones and one reverse zone. The metering units should have a maximumtransitory overreach of 5% for solid defects with maximum exponential component.

• The remote protection systems should be supplemented through the use of neutral directionalovercurrent protection (67N).

• Allow adequate elimination of faults to take place during the energization of the transmission line,even when the power supply to the protection system comes from a line pickup.

• Allow remote unit blocking due to bulk power capacity swings (680SB).If the primary protection system works on remote relays, it should run the following basic remoteprotection schemes through the configuration of its logic:• Permittive Underreach Trip Transfer (PUTT);• Permittive Overreach Trip Transfer (POTT);



• Directional Comparison Block (DCB).• Direct Trip Transfer (DTT).• Hybrid System (POTT, weak-infeed, echo)

The remote protection systems should comply with the following requirements:

• The selection of the remote protection logic to be adopted in each case should take into accountthe effects of the variations in the source impedances, the length of the transmission line, theexistence of magnetic couplings with other transmission lines, taps on the transmission lines andwhether or not there is any series compensation.

• The neutral directional overcurrent protection system (67N) should be incorporated into the remoteprotection system used.

• For remote protection schemes based on metering units adjusted at overreach, improperoperations block logic should be used during sequential fault elimination on parallel lines.

• When necessary, the schemes should be equipped with echo and weak in-feed logic.• Should a direct Trip Transfer (DTT) scheme be used, measures should be applied allowing the

remote disconnection of the circuit breaker in case of any defect in a telecommunications channel(single-channel operation).

• Provision should be made for functional checking of all remote protection transmission andreception channels regardless of the communications media used, with no risk of accidentaldisconnection and with no need to switch off the transmission line.

For terminals connected to busbars with ring or circuit breaker and a half arrangements, logic systemsshould be provided to protect the stretch of the line that remains energized when the respectiveinsulation switch is open (line out of service), with the line circuit breaker(s) closed (stub bus).The protection system should be selected and able to detect and eliminate all types of faults along thetransmission line.The main and alternative protection systems should include a trip-switch scheme due to loss ofsynchronism (78).All transmission line terminals should be equipped with the main and alternate protection systems forovervoltages (59) with instant and timed elements allowing independent adjustments, and a range of1.1 1.6 Vnom.The instant overvoltage protection facilities should operate only for dynamic events involving the threephases, and may not operate for overvoltages during maneuvers and surges where overvoltages arenot noted simultaneously in the three phases. The timed overvoltage protection should operate forsustained overvoltages at any of the three phases.All transmission line terminals should be fitted with synchronism checking schemes to supervise thetriple-pole closing command for the circuit breakers.

1.5.3 Transformer Units Protection (500kV-345kV)This consists of a set of equipment and accessories needed and sufficient to eliminate all types ofinternal or external faults that place the integrity of the transformer units at risk.All the transformer units should be fitted with three independent protection schemes, namely:

(a) Main protection scheme;(b) Alternate protection scheme;



(c) Backup protection scheme.The total maximum time for elimination of internal faults in the transformer units for the main andalternate protection scheme should not exceed 100 ms, including the operating time for the protectionrelay, the auxiliary relays and the circuit-breaker opening time.The main protection systems should consist of:

(a) Three-phase differential protection or three single-phase units (87P) restricted to the 2nd and 5th

harmonics and adjustable instant differential unit.(b) Built-in protection consisting of a sudden pressure trip-switch (63) in the transformer units with an

expansion tank (conservator) and excessive tank pressure trip-switch through the safety valve(63V).

The alternate protection system should use the three-phase differential relay or three single-phase units(87A) restricted to the 2nd and 5th harmonics and adjustable instant differential unit.The main and alternate protection systems should work the block relays (86T).Parallel current transformers should not be used on the differential grid.The backup protection system should run on overcurrent relays with instant and timed units for thephases and earth (50/51,50/51N), each linked to one of the windings of the transformer unit.For tertiary windings hooked up in a delta arrangement and connected to a non-earthed system, theuse of a residual overvoltage relay is recommended (59G) to detect halts between the phase and theearth.All transformer units should be fitted with a overcurrent relay tripped by an overload with instant andtimed elements and an additional timer with an adjustment range of 0 - 1 minute.The built-in protection should also include the following functions:

(a) Gas build-up alarm (63) in transformer units with an expansion tank (conservative);(b) Oil thermometer with warning and urgent markings (26);(c) Winding thermometer with warning and urgent markings (49).

1.5.4 Reactor protectionIn addition to the built-in protection equipment (gas relay, trip valve, etc.) all reactors should be fittedwith two independent protection schemes:• Main protection scheme;• Backup protection scheme.The maximum total time for the elimination of internal faults in the reactor by the main protectionscheme may not exceed 100 ms, including the protection relay operation time as well as the auxiliaryrelays and the circuit breaker opening time and the Trip Transfer time to the remote terminal.The main protection system of the reactor should consist of a three-phase differential relay or 3 single-phase differential relays.The differential protection should use the CTs for each of the phases of the High Voltage terminals, andthe CTs for each of the phases of the reactor neutral terminals, providing protection for faults betweenphases and between phases and the earth.The backup protection for the faults between phases should be handled by three overcurrent relayswith instant and timed elements (50/51) connected to the secondaries of the CTs installed at the HighVoltage terminals of the reactor and the fault protection between phase and earth should be handled by



the overcurrent relay with instant and timed element (50N/51N) connected to the secondary of the CTinstalled in the reactor neutral terminal.For reactors installed directly on the transmission line, all their protection equipment should work on thecircuit breakers of the next terminal on the associated transmission line, and should forward the directstart-up transfer to the remote terminal, blocking the closing of the local and remote circuit breakers.

1.5.5 Busbar Protection System

1.5.5.1 Protection of the 500kV busbars at the 500kV Ibiúna SubstationThis consists of the set of equipment and accessories needed and sufficient to detect and eliminate alltypes of faults in the substation busbars.The total elimination time for all types of defects in the busbars should not be greater than 100 msincluding the busbar protection relay operation time, the auxiliary relays and the circuit breaker openingtime.Each busbar on the facility should be fitted with a protection system consisting of busbar protection(87B) fed by secondaries independent of the current transformers.The busbar protection system should be stable (not operate) for faults outside the busbars, even incase of saturation of the current transformers.The busbar protection system should not operate improperly should the secondary current transformercircuit be opened.

1.5.5.2 Busbar protection systems for the Bateias 500kV Substation and the Ibiúna 345kV SubstationProvision should be made for equipment and associated schemes required to integrate the new lineinput facilities with the differential protection schemes for the existing busbars or the replacementthereof at the Ibiúna and Bateias Substations.Independent current transformer cores should be used, dedicated to each differential protectionsystem.Where there are busbar protection schemes with high-impedance relays, the magnetic characteristicsof the current transformers to be added should be identical to that of the existing current transformers.In case of replacement of the existing schemes, the same requirements described in item 1.5.5.1should be complied with.

1.5.6 Circuit breaker fault protection systemAll the circuit breakers in the substation should be protected by a circuit breaker fault protectionscheme.The total time for the elimination of faults by the protection scheme for defective circuit breakers shouldnot exceed 250 ms, including the operation times for the relays, the auxiliary relays and the opening ofthe circuit breakers.The fault protection for the system for the circuit breakers should control the opening of the smallestnumber of circuit breakers adjacent to the faulty circuit breaker sufficient to eliminate the fault, whennecessary transferring the direct start-up to the circuit breaker of the remote terminal.At the existing substations, the circuit breaker defect protection system should be dedicated, allowingintegration with the existing circuit breaker fault protection schemes. The overcurrent sensors should beadjustable in a range of (0.1 2.0) x I n, with the timer in the range of 0 0.5s.



1.5.7 Series Capacitor ProtectionThe series capacitor banks should be protected as recommended by the manufacturers, with at leastthe following protection devices:• Protection against subharmonics;• Protection against voltage imbalance in the capacitor units;• Heat Protection for the varistors;• Protection against discharge on the platform.

1.5.8 Special Protection Systems

1.5.8.1 Emergency Control Scheme (ECE)The TRANSMISSION UTILITY should make provision for additional status sectioning keys and circuitbreakers, with a view to the possibility of installing Emergency Control Schemes.

1.5.8.2 Safety Control Schemes (ECS)The Bateias and Ibiúna Substations will be integrated with the Safety Control Scheme (ECS - Esquemade Controle e Segurança) for the Power System in South / Southeast / Center-West Brazil.The following data should be available for connecting the CLP to the system:• Analog input:

- Flow of active bulk power on all transmission lines, generators and transformers;- Voltage at all busbar sections.

• Digital entry points:- Status indication with two circuit breaker contact points, disconnecting switches, generator

cut-off selection switches (for power plants);- Indication of protection scheme status;

• Control outlet points:- Two contact points for circuit breaker opening commands.



1.6 SUPERVISION AND CONTROL SYSTEMS

1.6.1 IntroductionThis item describes the supervision and control requirements that shall be provided in order to ensurethat the supervision and control of the new equipment is fully integrated with the supervision of theexisting equipment, thereby ensuring a high-quality secure operation of the interconnected powersystem. It is, therefore, the responsibility of the TRANSMISSION UTILITY to acquire and install everyitem of equipment, software and services required to meet the requirements specified herein anddeploy the telecommunications resources whose requirements are described in a separate item.The supervision and control requirements were divided as follows:• Supervision and control requirements of the facilities, described in detail under:

- General requirements;- Listed information to be supervised.

• Supervision requirements by the utility that owns the existing substations• ONS supervision and control requirements, divided in:

- Basic supervision requirements, normally met by a SSCL (local supervision and controlsystem) or conventional UTR (Remote Terminal Unit):

- Requirements that may require dedicated systems:º Automatic Generation Control Information (CAG - Controle Automático de

Geração);º High Uptake Rate Information to detect disturbances.

• Architecture of the interconnection with ONS;• Requirements for equipment registration.

1.6.2 Supervision and control requirements of the facilities

1.6.2.1 General requirementsThe expansion of the South / Southeast Interconnection involves the installation of a set of equipmentincluding line input facilities and transformer units, among others at the existing Bateias (COPEL) andIbiúna (FURNAS) Substations.Consequently, all the equipment to be installed by the TRANSMISSION UTILITY should be supervisedat the local level, in step with the philosophy adopted by the companies owning these substations, withthe supervision being properly integrated with the existing Digital Supervision and Control Systems(SDSC - Sistemas Digitais de Supervisão e Controle).The detailed description of the Digital Supervision and Control Systems (SDSC) at the substations(facilities) involved is defined in the documents entitled Basic Requirements and Characteristics of theFacilities (Características e Requisitos Básicos das Facilities), covering the Bateias and IbiúnaSubstations.In addition to local supervision, the electrical equipment should allow remote supervision by thefollowing Operating Centers:• Center run by the Agent owning the Bateias Substation

- COPEL System Operating Center (COS-COPEL), Curitiba, Paraná State• Center run by the Agent owning the Ibiúna Substation

- São Paulo Regional Operating Center (CTRS-FURNAS), Campinas, São Paulo State



• ONS Centers:- Southeast Regional Operating Center (COSR-SE), Rio de Janeiro, Rio de Janeiro State- Paraná System Operating Center (COS-PR), Curitiba, Paraná State

Important Note:The operating functions of the part of the Paraná State electrical system were assigned toCOPEL under a contract with the National Electricity System Operator (ONS - OperadorNacional do Sistema Elétrico). Physically, this Center is the same as the COPEL SystemOperating Center. Consequently, the supervision requirements listed below for the COS-PRare met by the same requirements specified for the COS-COPEL. These requirements aregiven here in order to offer a full overview of the supervision structure set up by the NationalPower System Operator (ONS). An exception to this fact is the transfer of information to theCAG should interconnection facilities be installed at Ibiúna (see item entitled Architecture ofthe Interconnection with the ONS).

- South Regional Operating Center (COSR-S), Florianópolis, Santa Catarina State

Therefore, to meet the supervision and control requirements, the supervision systems will require to beinstalled in the facilities in order to:• Acquire the information needed for local control and supervision of the equipment to be installed;• At the existing substation, integration with the Digital Supervision and Control Systems (SDSC)

already installed, in order to exchange information;• Interconnection between the Centers and the National Power System Operator (ONS) as

established in the item entitled ONS Control and Supervision Requirements (Requisitos deSupervisão e Controle pelo ONS), noting that:- Southeast Regional Operating Center (COSR-SE):

º In order to meet the basic supervision requirements: interconnection using the IEC870-5-101 protocol;

º In order to service the CAG: dedicated interconnection through a data link totransfer signals with FSK modulation.

- Paraná System Operating Center: See interconnection with COS-COPEL below;- South Regional Operating Center: using the IEC 870-5-101 or DNP 3.0 protocol.

• Interconnection between COS-COPEL and the FURNAS CTRS, as stipulated in the item headedInterconnection Architecture with the Agents Owning the Substations (Arquitetura da Interconexãocom os Agentes Proprietários das Subestações). These interconnections should be undertakenusing the protocol already implemented at these centers.

The protocols adopted for communicating with the operating centers (ONS, COPEL and FURNAS)must be configured in mutual agreement with said utilities.Moreover, this configuration must permit that said centers identify the operating status of theTRANSMISSION UTILITY supervision systems installed in the substations. This data will be modeledas status indications in the databases of those operating centers;

Important Note:Should an operating center be introduced in the Notice of Tender herein known as a dataconcentrator, in the communication highway with any of the COPEL, FURNAS or ONS operatingcenters, the configuration of the protocol must permit that said centers identify the operatingstatus of the data concentrator and, moreover, the data concentrator must be able to identify the



operating status of all systems hierarchically subordinate thereto and transfer such data to thecorresponding centers, as applicable.

The TRANSMISSION UTILITY should bear the costs of modifying the metalwork and software as wellas the other services required for the existing Digital Supervision and Control Systems (SDSC) at thesubstations in order to permit full supervision of the electrical equipment through the existing man-machine interfaces (IHM) in the local control rooms at the substations. The quantity and types of pointssupervised shall be similar to those of the existing systems.The TRANSMISSION UTILITY is also required to be responsible for installing and starting up theoperation of all equipment and systems required to facilitate the connection with the aforementionedoperating centers. As the interface between the TRANSMISSION UTILITY equipment and theaforementioned operating centers is required to be the digital input point of their communicationscomputers, this includes the installation of communication systems, modems and/or routers at all dataconnection terminals.As an alternative to installing new supervision and control resources, the TRANSMISSION UTILITYmay, by prior agreement with the companies that own the existing facilities, choose to expand theavailable supervision and control resources, provided all the requirements stipulated in the itemcaptioned Supervision and Control Systems (Sistemas de Supervisão e Controle) and TechnicalRequirements for the Telecommunications System to be Deployed (Requisitos Técnicos do Sistema deTelecomunicações a ser Implantado) are met.

1.6.2.2 List of information to be supervisedAs a general supervision and control requirement, all TRANSMISSION UTILITY equipment to beinstalled in the Tucuruí Disconnecting Station and Vila do Conde substations shall be supervised. Thedata collected at said substations shall be transferred to the operating centers mentioned in the Noticeof Tender herein as specified below:(a) Telemetering

• All metering should be undertaken on an individual basis and transferred periodically to theoperating centers;

• The transfer period must be able to be parameterized for each center, and the systems bedesigned to support periods of at least 4 seconds;

• The following measurements shall be collected and transferred to the operating centers:- Phase-phase voltage module in kV for all line input facilities;- Phase-phase voltage module in kV for all connection points between the Transmission

Line and the series compensation, whenever applicable;- Active three-phase bulk power in MW and reactive in MVAr at all line input facilities,

metered between the line and the line reactor;- Three-phase active bulk power in MW and reactive in MVAr for all terminals of all bulk

power transformers installed and with equipment connected thereto (not operating idle);- Tap position for all transformers fitted with load switches;- Temperature in ºC for the winding and oil in all transformers;- Phase current in Amperes for all transformer and Transmission Line terminals;- If applicable, three-phase reactive bulk power in MVAr for all variable compensation

reactive equipment such as controllable synchronous compensators and reactive staticcompensators;

- Temperature in ºC for the oil and coils for each line reactor (by phase);



- Frequency in Hz of a phase at all busbars involved;- Active and reactive energy at the interconnection points between control areas.

• All voltage measurements must have a minimum accuracy of 1% and the rest 1.5%. This accuracymust cover the whole chain of items of equipment used, such as: current and voltage transformers,transducers, analog/digital converters, etc.

(b) Status indication

• All status indicators shall be collected with time stamps accurate to 1 ms, reported back byexception to the operating centers;

• The time stamp to be transmitted to the operating centers listed herein shall be that set onacquisition of the data by the Acquisition and Control Unit (UAC - Unidade de Aquisição eControle), no later alteration thereto being acceptable.

• The facility supervision and control systems must be able to respond to integrity sweepsundertaken by the centers connected thereto (ONS, FURNAS and COPEL) which may be cyclical,adjusting the period by parameters, typically every five minutes, or by event, such as rebooting thesupervision and control resources at the centers, or on request;

• The facility supervision and control systems must be able to identify and store the time stamp forthe status indicators with a resolution of at least one millisecond between events;

• The interleaving relays should be compatible with the resolution specified above;• The following status indicators shall be collected and transferred to the operating centers:

- Position of all switches and circuit breakers used to connect all equipment, includingearthing and bypass switches;

- General indicator of operated protection, informed per item of equipment, such astransmission lines, transformers, reactors, series capacitors, etc.;

- Block relays;- Winding temperature alarm (per phase) of the line reactors;- Oil temperature alarms (per phase) of the line reactors.

(c) Each acquisition and control unit (UAC) shall be fitted with an internal clock and calendar to informthe day, month, year, hour, minute, second and millisecond of each status variation meteringoperation. These inner clocks must be fitted with synchro circuits based on a signal with anabsolute date obtained from a GPS system to ensure that the supervision and control of thevarious facilities is undertaken on the same time basis. The system shall be designed to achievebetter accuracy than one millisecond.

(d) All telemetering and status indicators shall have data quality indicators for the data collection andthe local supervision conditions (data invalid at point of origin, not updated during the last remotesweep, etc.).

(e) All control and supervision system information transferred to the operating centers of the utilitiesmentioned herein shall be raw data, as collected from the transducers or interleaving relays, that is,with no prior processing except when explicitly agreed on a case-by-case basis with one of saidutilities. In these cases, the quality indicators shall include at least the following:

• Indicator from manual input by the facility operator or operating center of the TRANSMISSIONUTILITY, as appropriate;



• Indication of a shut-down point by the facility operator or operating center of the TRANSMISSIONUTILITY, as appropriate.

• (f) Information for sequencing events:

• ResolutionThe facilities supervision and control systems must be able to store information forsequencing events with a resolution between events better than 1 millisecond. The accuracyof the time stamp associated with each event shall also be better than one millisecond. Alltypes of operation must be defined during the execution of the final design

• Set of InformationThe information listed below and stored by the facilities supervision and control system should betransferred, depending on the facility, to COSR-SE, COSR-S, CTRS and COS-COPEL, giving theinstant when the event took place; additional points may be included during the implementation of theexecutive project designs:

- Transformers/Autotransformers:º Overcurrent at an on load changer;º 2nd stage oil overheating;º 2nd stage winding overheating;º 2nd stage gas protection;º Zero sequence overvoltage protection for tertiary winding in delta connection;º Forced ventilation system fault;º Tap position discrepancy (in parallel operations);º Tap changer block;º Pressure blow valve;º Changer gas protection;º Differential phase protection;º Phase and neutral overcurrent coil protection;º Block relay on-switch.

- Reactor:º 2nd stage oil overheating;º 2nd stage winding overheating;º 2nd stage gas protection;º Pressure blow valve;º Differential protection per phase;º Phase and neutral overcurrent coil protection;º Block relay operation.º

- Transmission Line:º Main phase protection start-up by phase;º Main phase protection trip-switch;º Supplemental phase protection start-up per phase;º Supplemental phase protection trip-switch;º Main earth protection start-up per phase;º Main earth protection trip-switch;



º Supplemental earth protection start-up per phase;º Supplemental earth protection trip-switch;º Automatic reconnection start;º Circuit breaker fault scheme switch;º Overvoltage trip-switch;º Bulk power oscillation blocking;º Bulk power oscillation trip-switch;º Remote protection, block/release or permittive signal transmission;º Remote protection, trip transfer transmission;º Remote protection, receipt of block/release or remote permittive signal

transmission;º Remote protection, transfer trip transfer receipt;º Faulty cutout blocking;º Switch-on time 2nd zone;º Switch-on time 3rd zone;º Switch-on time 4th zone;º Faulty cutout blocking;º Timed directional overcurrent;º Instant directional overcurrent;º Block relay switch-on.

- Busbarº Differential protection per phase;º Underfrequency protection;º Overvoltage protection;º Undervoltage protection;º Block relay switch-on.

- Circuit breakerº Position indicator;º Power feed fault in opening and closing circuits;º Pole-discordance protection on-switch;º Closing blocked;º Opening blocked;º Automatic closing due to minimum insulation system pressure;º Low pressure arc elimination system (1st 3rd stage);º Low pressure start-up system (1st 3rd stage);º Insufficient air recharge;º Circuit breaker failure;º Central circuit breaker overload;º Block relay switch-on.

- Digital Disturbance Metersº Start-up and failureº

(g) Data age



• Maximum data age is understood to be the maximum time between the instant of the event of itsvalue in the facility (process) and its receipt at the ONS, COPEL and FURNAS operating centers.

• The time required for data to reach any of these centers includes the data uptake time at thefacility, size processing and its transmission through the communications links.

• The maximum age for data collected periodically (by scanning) must be less than the sum of itsscanning time plus:- 2 seconds average;- 5 seconds maximum.

• The maximum age of status indicator data must be less than four seconds. This requirement doesnot apply when there is a change in status and local supervision system is under an integrity cycle.

• These requirements are not applicable to the transmission of event sequence information.

(h) Dead BandDepending on the communications protocol adopted, the analog information may be reportedback on an exception basis to the operating centers mentioned herein. In these cases the valueadopted for the dead band used in the screening process must be agreed mutually between theutility that owns the center (ONS, FURNAS and COPEL) and the TRANSMISSION UTILITY. Ifno agreement is reached, the dead band value shall be 0 (zero).

1.6.3 Requisitos de supervisão pelo agente proprietário das subestaçõesThe TRANSMISSION UTILITY must provide the Operating Centers the utility that owns the existingsubstations with facilities for remote supervision of the equipment to be installed, pursuant to therequirements presented in the subitem entitled List of Information to be Supervised, applied inaccordance with the following criteria:• Supervision by the COPEL Operating Center (COS-COPEL):

- Bateias SubstationThe requirements should be applied to all items of equipment to be installed by theTRANSMISSION UTILITY;- Ibiúna SubstationThe requirements should be applied only to the 500 kV busbar and all terminals of equipmentconnected thereto, including the series capacitors and the transmission lines.• Supervision by the São Paulo Regional Operating Center (CTRS), FURNAS, Campinas,

São Paulo State:- Ibiúna SubstationThe requirements should be applied to all items of equipment to be installed by theTRANSMISSION UTILITY;- Bateias Substation:The requirements should be applied only to the 500 kV busbar and all terminals of equipment tobe connected thereto, including the series capacitors and the transmission lines.


PROCURADORIAGERAL/ANEEL VISTO

The figure below offers a simplified overview of the supervision requirements for the substations(facilities) covered herein, through COPEL and FURNAS Operating centers. This is included merely asan illustration to offer a graphic overview of the requirements specified in the wording of the Notice ofTender herein.

Alternatively, the TRANSMISSIOthe substations (facilities) throuprovided the requirements descrNotice of Tender herein, this cenof centers shown in the precedhierarchical level between the fThe figure below illustrates a pos

COSCOPEL1

Key:1) Operating Centers used by Agents owning the substations:a) COS – COPEL System Operating Centerb) CTRS – FURNAS, São Paulo Regional Operating Center2) Expansions of supervision and control in existing substations:a) PRBTA – Supervision and control resources in the Bateiassubstationb) SPSTIN – Supervision nd control resources in the Ibiúnasubstation3) Existing supervision and contro dFURNAS substations.4) Total supervision5) Supervision of the 500 kV busb

PRBTA2 SPSTIN2

CTRSFURNAS1

5

PRBTA3

l resources in COPEL anResources to be installed

a4

N UTILITY may decide to connect thegh one of the TRANSMISSION UTILibed under Supervision and Control Ster is generally called a data concentraing figure would be changed by insertacilities of COPEL and FURNAS centsible configuration.

ar onlySPST

3Existing resources

4

VOL. IV - Fl. 99 de 192

Centers of the utility that ownsITYs own operating center,

ystems herein are met. In thetor. In said case, the structureing the data concentrator at aers, therefore, included herein.

IN


PROCURADGERAL/ANE VISTO

1.6.4

1.6.4.1

1.6.4.2 R

1.6.4.2.1

was us1)and co

COSCOPEL

Key:In addition to the acronyms in the previous figure, the following

ed:CD – Data concentrator (DC), generic name given to a supervision

ntrol system located between COPEL and FURNAS facilities and

CTRSFURNAS

ORIAEL

VOL. IV - Fl. 100 de 192

ONS supervision and control requirements

Basic requirements for equipment supervisionThe basic resources for supervising equipment that must be provided to ONS are described in the itemListed Information to be Supervised and cover:• Telemetering with 4 second scanning, which can be parameterized;• Status indicators reported by exception and with an integrity cycle, that can also be parameterized;• Sequence of events (SOE).

equirements that may require dedicated systems

Information for the Automatic Generation Control (CAG)• The information for the Automatic Generation Control (CAG) consists of measuring the active bulk

power capacity in MW at each line input facility at the Bateias Substation or the Ibiúna Substationas described in the item entitled Architecture of the Interconnection with the ONS (Arquitetura daInterconexão com o ONS), below. This information should be transferred to the ONS Center withthe following sweep periods, with parameters available for adjustments:- To the COSR-SE:

º Minimum period of 200 milliseconds (ms);

PRBTASPSTIN

Resources to be installed

Existing resources

SPSTINPRBTA

CD1



- For the other ONS Centers:º Minimum Period of 2 seconds (s).

1.6.4.2.2 High acquisition rate information for detecting disturbancesThe measurements from the phase-phase voltage module in kV should be sent to the COS-PR andCOSR-S for the 500 kV line input facilities at the Bateias Substation and the measurements for thephase-phase voltage module in kV should be sent to the COSR-SE for the Ibiúna line input facilities(500 kV) both collected and transferred with an interval of 200 ms (one measurement per substation).Note the high transfer rate of this information, which differs from the rate normally used for theacquisition of regular data, which is typically 4 seconds.

1.6.4.3 Architecture of the Interconnection with the ONSSupervision and control are among the basis of real-time operations for the power systems, and in theBateias and Ibiúna region are today structured into a hierarchical system with supervision and controlsystems in full at four ONS Operating Centers, namely:• Southeast Regional Operating Center COSR-SE;• Paraná Operating Center COS-PR;• Note that this Center is currently responsible for operating the Bateias substation and uses the

same supervision and control system as COS-COPEL, as this Center is contracted by the ONS.• South Regional Operating Center COSR-S;• National Electrical System Operating Center - CNOS.



This structure is presented in a simplified manner in the following Figure, solely for the purposes ofillustration, with the TRANSMISSION UTILITY responsible for providing the data connections with theONS Operating Centers (except the CNOS) as well as each of the substation supervision systemsinvolved.

Note in the Figure above that the interconnections with the ONS Centers are handled through thefollowing data connections:• To meet the supervision requirements of the equipment installed at the Bateias substation:

- Interconnection with the Paraná Operating Center COSR-PR

CNOS1

COSR-SE1

Key:1) Operating Centers used by ONS:

CNOS – National Electric Power System Operating Center;COSR-SE – Regional Southeast Operating Center;COS-PR – Paraná Operating Center;COSR-S – Regional South Operating Center.

2) Expansion of supervision and control in existing substationss:PRBTA – Supervision and control resources in the Bateias

substation;SPSTIN – Supervision and control resources in the Ibiúna

substation.3) CAG: Dedicated interconnection with COSR-SE for transmissionof information regarding automatic generation control.4) Resource previously contemplated upon specification of therequirement for interconnection with COS-COPEL.5) Supervision and control resources in existing substations.

PRBTA2


COS-PR

CAG3

COSR-S1

4

PRBTA SPSTIN

Existing resources

SPSTIN2



Note that this interconnection is the same as that servicing the COS-COPEL, and consequently doesnot need to be replicated.

- Interconnection with the South Regional Operating Center COSR-S.• To meet the Requirements of the Automatic Generation Control system − CAG:

- The information for the Automatic Generation Control system (CAG) should be collected atthe Bateias substation as the transmission system covered by this Notice of Tenderinterconnects the electrical area controlled by the Southeast Regional Operating Center(COSR-SE), Ibiúna substation, with an area that is currently controlled by the ParanáOperating Center (COS-PR) and that in future may be controlled by the South RegionalOperating Center (COSR-S), Bateias substation. Consequently, this information should besubmitted simultaneously to:º COSR-SEº Note the special characteristics of this link, which may require dedicated data

channels as transfer rates of 200 ms are used with FSK modulation;º COS-PR, through the same data link handling real-time supervision requirements.º COSR-S, through the same data link handling real-time supervision requirements.

Note: It is assumed that the transmission system will be in the COSR-SE control area, andconsequently the interconnection substation is Bateias. Bids should assume that this situationmay be reversed, with the Ibiúnas Substation being the interconnection substation. In this case,provision should be made for links at Ibiúna transferring the exchange information to the CAG asspecified in the item entitled Requirements for Automatic Generation Control (Requisitos para oControle Automático de Geração) to:

• COSR-SENote the special characteristics of this link, which may require dedicated data channels, as ituses transfer rates of 200 ms with FSK modulation;

• COS-PRNote that this interconnection may be the same as that servicing the COS-COPEL, andconsequently does not need to be replicated, but should merely be sized to handle the transfer ofexchange information as specified;

• COSR-S- In order to meet the supervision and control requirements of the equipment at the Ibiúnas

substation:º Interconnection with the Southeast Regional Operating Center COSR-SE.

Alternatively, at the discretion of the TRANSMISSION UTILITY, the interconnection with the ONSCenters may be handled through an Operating Center owned by the TRANSMISSION UTILITY, oroutsourced, provided that the requirements described in this item entitled Control and SupervisionSystems (Sistemas de Supervisão e Controle) and "Technical Requirements of theTelecommunications systems to be Implemented" (Requisitos Técnicos do Sistema deTelecomunicações a ser Implantado) are complied with. In this Notice of Tender, this Center isgenerically called a data concentrator. In this case the Centers structure in the previous Figure will bealtered through the introduction of the data concentrator at a hierarchical level located between theONS Centers and facilities, and is consequently included in the purpose of this Competitive BiddingProcess. The following Figure illustrates the possible configuration, stressing that it is necessary tomaintain the data channel in order to transmit the Automatic Generation Control (CAG) systemmeasurements to the COSR-SE, due its specific characteristics.



1.6.4.4 ETfoin•

•

CD1

CNOS

SPSTIN

COS-PR

Key:1) In addition to the acronyms in the previous figure, the followingwas used:CD – Data concentrator (DC), generic name given to a supervision andcontrol system located between ONS facilities and centers.


COSR-SE

CAG

COSR-S

PRBTA SPSTIN

PRBTA

Existing resources

VOL. IV - Fl. 104 de 192

quipment registration requirementshe registration information for all items of equipment that will be operated by the ONS should berwarded thereto at least 3 (three) months prior to the start-up of operations. This information shouldclude: Descriptive parameters of the TRANSMISSION LINES, including their series impedance and

susceptance according to the π model, as well as the maximum current in Amperes, the maximumbulk power capacity in MVA, the latitude and longitude of each facility and the line pylons;

For each of the windings (primary, secondary and tertiary) of each transformer:- Rated current;- Rated voltage in kV;- Rated apparent bulk power capacity in MVA;- Inductive reactance in percentage (primary secondary, primary tertiary and secondary

tertiary);- Base voltage (kV) and base bulk power capacity (MVA) used to calculate the inductive

reactances by percentage as specified above;- Additionally, the side of the transformer where the switch under load is installed should be

notified for each transformer, if used, as well as the respective Tap Table, stated in kV and



percentages. Whenever the position of the fixed tap is altered, a listing should be suppliedof the new variable positions of the transformer;

• Rated capacity in Mvar and rated voltage in kV for all static reactive support equipment to be used,such as capacitors, reactors, etc.,

• Series impedance of series capacitors;• Supply of operational diagrams identifying all items of equipment for each facility;• Supply of diagrams showing the exact location of all metering points, remote signaling and controls

for each facility;• All the diagrams should be supplied on paper and on magnetic media, following an import / export

standard to be agreed in advance between the Agent and the ONS;• Listing of the metering, remote signaling control and SOE points transmitted over the

interconnection (or interconnections) with the supervision and control system(s) of the NationalElectricity System Operator (ONS), and compatible with the supervision and control requirementsstipulated herein, in the format compatible with the protocol adopted for the interconnection,organized by SSCL/UTR and the data concentrators, if used;

• In the case of direct data interconnections with UTRs, and if applicable, parameters allowing theconversion to engineering values of the data received / forwarded by the Center;

• Whenever applicable, upper and lower scale limits for all analog points under supervision.

1.6.5 Quality assessment and availability requirements

1.6.5.1 GeneralThe availability and quality of the supervision and control resources provided by the TRANSMISSIONUTILITY in order to meet the requirements presented in this Notice of Tender should be measuredaccording to the concepts and criteria established below.The assessment of these resources will be undertaken through metering or control points, based on theavailability and quality as checked by the Centers mentioned in this Notice of Tender. Consequently,not only the data uptake equipment at the facilities will be assessed, but also all systems operatingbetween these items of equipment and the computer systems of the above-mentioned Centers,including the communications system and interface equipment with the communications computers(modems, for instance).Supervision and control resource assessment will allow observation of both telemetering and statusindications in terms of the operating status of the remote terminal unit, local supervision and controlsystems, and data concentrators, as the operating status of the such equipment will be notified to theCenters as status indications.Additionally, aggregate indices will be calculated that will offer an overview of the availability and thequality of the supervision and control resources of the TRANSMISSION UTILITY

1.6.5.2 Non-availability concepts for the supervision and control resourcesAny item of information of any type specified in this Notice of Tender is rated as non-available for any ofthe Centers whenever:• The quality indicator received together with the information indicates any anomaly, such as, for

instance:- Information switched off at origin (facility);- Information invalid at origin;- Information not updated;



Notes:1) This case will not be considered if the electrical equipment associated with the pointsis undergoing maintenance or is out of operation due to operating requirements and theTRANSMISSION UTILITY is using one of these indicators, typically switched off at origin toindicate this fact.2) The Manual quality indicator does not rate information as non-available but rather aslow quality, as described in the item entitled Quality Concept for Supervision and ControlResources (Conceito de Qualidade dos Resources de Supervisão e Controle).

• Analog information violating one of its respective scale limits.• Inconsistent status signal information.

All the SOE points of a supervision and control system or a remote terminal unit are rated as non-available whenever an event occurs that should trip the sequential record and does not do so.An SOE point is rated as non-available whenever it is not reported.All points subordinate to a supervision and control system of a facility are declared non-availablewhenever there is no response from such system to the request from the Center(s) or a dataconcentrator, if used. Additionally, should data concentrators be used, all points subordinate to theconcentrator will be declared non-available when they fail to respond to the request of any one of theOperating Centers mentioned in this Notice of Tender.Any point is rated as non-available whenever it is undergoing maintenance.

1.6.5.3 Quality concept for the supervision and control recoursesAny item of information of any of the type specified in this Notice of Tender is rated as violating thequality criteria when:• The quality indicator provides information on manual input by the TRANSMISSION UTILITY

operator (if any);• It violates the data age requirements;• In case of analog information, when violating accuracy requirements;• In the case of time-stamped information, when violating accuracy requirements.

1.6.5.4 Indicators

1.6.5.4.1 Availability per supervision and control resource [Di]Description:• Abbreviation: Di

• Purpose: To assess in percentage the time when a given supervision and control resource i,provided by the TRANSMISSION UTILITY and release for the operation, is available for theoperating centers, during the study period.

• Period of study: Monthly• Unit of measurement: Percentage• Nature: Supervision and Control Systems• Aggregation: Monthly, by supervision and control resource for each operating center• Availability guideline:

- For resources associated with telemetering, status markers and event sequence: Theminimum acceptable value is 97.5%, on a monthly basis;



- For remote terminals, supervision and local control systems and data concentrators: theminimum acceptable value is 99.8%, on a monthly basis.

• Data required: as in equation• Equation:

Di = ( ( T - TIi ) / T ) X 100Where:

Di : Availability rate of resource i;T: Total time in minutes for the study period;TIi: Sum of the periods when point i was unavailable during the total time T;

1.6.5.4.2 Availability of supervision and control resources of the TRANSMISSION UTILITY [DRSj]Description:• Abbreviation: DRSj

• Purpose: to assess in percentage the availability of the supervision and control resources providedby the TRANSMISSION UTILITY for the operation of a given operating center j, for the studyperiod

• Study period: Monthly• Unit of measurement: Percentage• Nature: Supervision and Control Systems• Aggregation: Monthly and per operating center• Availability guideline: The acceptable minimum value is 98.5%, on a monthly basis• Data required: as in equation• Equation:

ΣTij

DRSj = X 100T X NPRSj

Where:• T: Total time in minutes for calculation period;• Tij: Sum of the periods where the resource i was available during the total time T for a certain

center j;Note: Tij = (T – TIij)

Where:a) TIij: Sum of the periods when point i was unavailable during the whole time, seen by center jb) NPRSj: Total number of the TRANSMISSION UTILITYs supervision and control resources in the

supervision network under center j responsibility.1.6.5.4.3 Quality per supervision and control resource [Qi]

Description:• Abbreviation: Qi

• Purpose: To assess in percentage the time when a given supervision and control resource i,provided by the TRANSMISSION UTILITY does not meet the quality concept during the studyperiod.

• Study period: Monthly



• Unit of measurement: Percentage• Nature: Supervision and Control Systems• Aggregation: Monthly, per supervision and control resources and per operating center• Quality guideline: The acceptable minimum value is 97.5%, on a monthly basis;• Data required: As in equation• Equation:

Qi = ( ( Tq - Tnqi ) / Tq ) X 100Where:- Qi : Quality rate of resource i;- Tq: Total time in minutes for the study period;- Tnqi: Sum of the periods when point i does not comply with the concept of quality the

whole time Tq.

1.6.5.4.4 Quality of the TRANSMISSION UTILITYs supervision and control resources [QRSj]Description:• Abbreviation: QRSj

• Purpose: To assess in percentage the quality of the supervision and control resources provided bythe TRANSMISSION UTILITY for the operation of a given operating center j, during the studyperiod

• Study period: Monthly• Unit of measurement: Percentage• Nature: Supervision and Control Systems• Aggregation: Monthly and per operating center• Quality guideline: The acceptable minimum value is 98.5%, on a monthly basis• Data required: As in equation• Equation:

ΣTqij QRSj = X 100

Tq X NPRSqjWhere:

- - Tq: Total time in minutes of the calculation period;- - Tqij: Sum of the periods when the resource i complied with the quality concept

during the total time Tq, when seen by center j;Note: Tqij = (Tq Tnqij)where:- - Tnqij: Sum of the periods when point i does not comply with the quality concept during

the total time, when seen by center j;- - NPRSqj: Total number of the TRANSMISSION UTILITYs supervision and control

resources in the supervision network under responsibility of center j and may beassessed for quality.

The following figure shows a graph of these indices, where the individual rate per resource (Di or Qi)must be more than the minimum requirement and the aggregate rate (DRS or QRS) represents theaverage availability/quality of all TRANSMISSION UTILITY resources..



1.6.5.5 Analytical and assessment reports for the availabilityThe operating centers that will receive the TRANand quality of the supervision and control resourcsituations:• Any of the indicators specified is less in the m• There is a loss of more than 30% of the

TRANSMISSION UTILITY for a period of mor• During a major disturbance in the Basic Grid,

the TRANSMISSION UTILITY are out of concentrator of the TRANSMISSION UTILITY

Based on the aforementioned, there will be two typ• Availability and Quality Assessment Repor

guideline is not met.• Occurrence Report: Issued in all other cases.

1.6.5.6 Publishing the TRANSMISSION UTILITY availabilityThe final reports must be issued based on the recenters and after equating with the TRArecommendations for correction of any anomaly.Wherever the guidelines specified herein are notsend the reports to ANEEL for the appropriate meacontracts with the TRANSMISSION UTILITY.

Resource “k”

Availability/Quality

TC

100%

98.5

97.5

Resource “l” Resoruce “m”

Average availability/Quality –DRS/QRS

Minimum availability “D”/Quality“Q”

VOL. IV - Fl. 109 de 192

of the supervision and control resourcesSMISSION UTILITY data will assess the availabilityes, issuing non-conformity reports in the following

onth than the corresponding guideline set herein;supervision and control resources provided by thee than or equal to one hour; one or more supervision and local control systems oforder or loses the communication with some data, if used.

es of reports:t: issued whenever some availability and/or quality

, quality and action reportsports written by the utilities who own the operatingNSMISSION UTILITY, including, if applicable,

met, the Utility that owns the operating center willsures to be taken, based on the prevailing laws and

ransmission resources seen byenter “j”



1.7 BILLING METERING SYSTEMA billing metering system should be installed that meets the accounting and settlement requirements ofthe Wholesale Energy Market (MAE) and which complies with the technical metering specifications forbilling established by the ASMAE/ONS.The scheme connecting the transformers to the instruments and the meters should use three elementsand four wires.The meters should have two RS232 type communication outlets, and at least one I/O input forinterconnection with a remote terminal unit or local supervision system. These meters should allow timesynchronism through commands by the Data Acquisition Center, or by GPS.Provisions to be made for direct extension dial telephone extension for data uptake by remote readingand a communication channels solely for metering purposes in order to transmit the reading on a full-time basis. Alternative solutions allowing access to the meters by the ASMAE data acquisitionexchange over a data network may be accepted, should at least the same performance ratings beassured as those stipulated for the dedicated communication system.

1.7.1 LocationThe billing metering system should be located at the arrival point of the Bateias / Ibiúna line at Bateias.



1.8 TECHNICAL REQUIREMENTS OF DIGITAL OSCILLOGRAPHY SYSTEM

1.8.1 General aspectsThe digital disturbance metering (RDP) must be the stand alone type, alone from the rest of theprotection and supervision/local control systems in the facility, even it they are able to provideoscillographic metering. The following features must be considered:a. Data collection and storage relating to currents and voltages (analog channels);b. Digital signal collection and storage (digital channels);c. Pinpointing failures in transmission lines (TLs);d. Independent communication for remote access to data.

Should there be a failure in the power system, the above features must permit analysis of behavior, intime, of the power ranges, protection performance, in addition to indicating the distance at which thefailure occurred.Provision must be made for digital disturbance logs with analog input channel configuration (currentand voltage) and enough digital inputs and output to permit the complete monitoring of the occurrencesand disturbances.The TRANSMISSION UTILITY must integrate the functions of all equipment and software, and providethe communication software, configuration and adjustment, for conversation to the standardCOMTRADE (IEEE C37.111-1999). The functional integration must include the time synchro devicesvia GPS.

1.8.2 Description of featuresThe bulk power ranges (voltage and current) and digital signals must be shown at regular intervals tocarry out the roles of disturbance metering, to meet the frequency response requirements as specified,converted to digital and stored in the memory.In a normal situation, the RDP must continue to monitor on an ongoing basis the analog and digitalranges. The older samples must be successively replaced by more recent samples (buffer circular),and always maintaining a complete situation of data covering an interval equal to the adjusted pre-failure time.In the event of the RDP trip, the basic data relating to the disturbance are automatically filed in thememory of the log itself. During storage of the failure data, the metering must continue to supervise theanalog and digital ranges, in order not to lose any event, however short a time it may be.This process must continue until the situation returns to normal, when the samplings performed mustthen be considered as post-failure data, until the adjusted post-failure time has passed. The post-failuretime-out configures the end of the data collection relating to that event.Disturbance-related data must be stored in its own memory, and it must be able to be transmitted forremote analysis, on request, through either the manual or automatic communication link.Calculations required to locate failures may be made on site or remotely.The disturbance data existing in the RDP memory must be automatically transferred to a non-volatilememory, and the communication program must include management, access and deletion of thesedata.



Software must be provided for the data transfer, compaction/decompaction, conversion to standardformat COMTRADE (IEEE C37.111-1999) and remote communication interface, as well as software foradjusting and gauging the RDP.The RDP must contain self-monitoring and ongoing self-diagnosis routines.The internal time of the RDP must be synchronized using a synchro device via satellite signal (GPS).

1.8.3 Digital Disturbance Meter trip-switchThe memory of the digital disturbance metering (RDP) should be tripped to measure in any of theconditions listed below, or a combination thereof, and must be freely (programmable) by the user:

Tripped by variation in the protection status;Tripped by violation of the operating limits;Tripped by digital logic;Tripped manually, either local or remote.

The digital disturbance meter (RDP) must be tripped through its own sensors or software, outsidecontacts, or a combination thereof.The starting mode shall be configurable locally and remotely.

1.8.4 Time SynchronizationEach digital disturbance meter (RDP) must be fitted with an internal calendar and clock to provide theday, month, year, hour, time, minute, second and millisecond for each metering? operation.The digital disturbance meter (RDP) must permit synchronization of the internal time base through anoutside clock in order to ensure accuracy in terms of the time of the Global Positioning Satellite System(GPS), with an error of no more than 1 ms.

1.8.5 Electromagnetic compatibility requirementsThe TRANSMISSION UTILITY must take the necessary steps to protect the input and output points ofthe digital disturbance meter (RDP) from electromagnetic emissions.The digital disturbance meter (RDP) shall adopt the electromagnetic compatibility standards applicablethereto, in terms of the levels of severity appropriate for Extra High Voltage facilities.

1.8.6 Characteristics of input and output signalsDigital input must have a maximum time error between any input signal and its metering of less than2ms.The analog input must have the following characteristics:

be configurable for current and voltage;have a delay time between any channels of less than 1 electrical level referring to 60 Hz;



The voltage input points must have the following characteristics:

CHARACTERISTICS RANGESRated voltage (Vn) 115 and 115/ 3 VMetering range 0 – 2.0VnPermanent overvoltage 2.0 VnFrequency response range with total asymmetry at + 1dB 1 at 1000 HzPhase angle error ≤ 1.0 millisec.Metering scope accuracy ≤ 2.0%Input consumption ≤ 2.0 VAData resolution less than or equal to 1% at 60 Hz

Note: The accuracy and the phase errors mentioned above refer to the ratio between the input signaland/or its registration on a hard copy or display terminal.

The current input points must have the following characteristics:

CHARACTERISTICS RANGESRated current (In) 1 or 5 A rmsMetering range 0 - 20 InDetection of direct current through to saturation:At 1 InAt 20 In

1.5 s50 ms

Overcurrent:Permanent1 second

2 In20 In

Phase shift angle error registration ≤ 1.0 msAmplitude accuracy: 0 – 1 In ≤ 1%Frequency response range with total asymmetry at + 1dB 1 - 1000 HzIndividual consumption ≤ 2.0 VA


The digital outlets must be voltage-free contact type in order to indicate the following events:a) Fault in the system;b) Meter tripped;c) Failure in remote communication;d) 75% of its storage capacity filled;e) Indication of normal operating status;

1.8.7 Occurrence metering capacity.The digital disturbance meter (RDP) must have sufficient memory to store the data covering at least 30(thirty) disturbances lasting 5 (five) seconds each, should several consecutive defects trip the meter.



The digital disturbance meter must be able to measure at least 160 ms of pre-failure data for eachfailure or disturbance and the post-failure time must be adjustable between 100 and 5000 ms.Metering a failure or disturbance must only be interrupted where the start-up sensors are non-operative, and after completion of the adjusted post-failure time.Should the sensor remain operative, the disturbance metering must continue until the sensor becomesnon-operative, including the meter for the post-failure time.Should a fresh disturbance occur prior to the completion of the metering time for an earlier disturbance,the meter must start a new metering period, not taking into account the time already passed for theprevious disturbance.

1.8.8 Communication requirementsThe digital disturbance meter (RDP) must be fitted with a standard RS-232C serial communicationsport for local and remote communication functions.At places of more than one RDP, they shall be interconnected through a network. A micro-concentratorconnected to this network will handle communication at the top hierarchical level. In places where thereis an oscillograph network, the new equipment shall be integrated therein.Remote data transfer may occur on request or automatically, so that during transfer measures must betaken to check data integrity. Discarding data stored in the internal memory shall only take place onrequest.The communication protocol must be open to the user and formally described so that the digitaldisturbance meter (RDP) can be connected, if necessary, to other digital systems already existing or tobe developed. It must preferably comply with the ISO standard.



1.9 TECHNICAL REQUIREMENTS OF THE TELECOMMUNICATIONS SYSTEM TO BE IMPLEMENTED

1.9.1 General requirementsThe telecommunications for the expansion of the South/Southeast Interconnection should service theoperations and administration voice communications systems, as well as remote protection, electricalsupervision and control, telecommunications supervision, emergency control, metering, billing andmaintenance of the power transmission line between the substations involved, and between thesesubstations and the Operating Centers of the power system involved.The voice and data communications media should comply with the following requirements:• Availability equal to or greater than 99.7% measured for each period of 30 (thirty) days;• Provision should be made for digital circuits complying with the G.821 recommendations issued by

the International Telecommunication Union (ITU);• Analog equipment will be accepted only in cases where it is impossible to locate new equipment

compatible with the existing infrastructure. In these cases, the following recommendations shouldbe followed: CCIR 391, 392, 394, 395, 396 and 397, as well as the pertinent IEC recommendation;

• The requirements in IEC standards 834-1, 870-5 and 870-6 should be followed for the remoteprotection system as well, where applicable.

The energy system for all telecommunications equipment supplied should have the followingcharacteristics:• Supervision unit and at least two rectification units;• Two banks of batteries meeting full power requirements for at least 12 hours sized to handle the

total load all installed telecommunications equipment;• Should lead-acid batteries be used, the banks of batteries should be placed in a special location,

separate from the other facilities and fitted with a gases exhaust system;• The rectification unit should have the capacity to simultaneously feed the bank of batteries being

charged and all telecommunications equipment with a sizing margin of 30%.The telecommunications equipment should be supervised at both the local and remote levels, andshould sound alarms in the facilities in case of any anomaly in the main telecommunications equipment,including the power supply equipment.The equipment should be fitted with remote supervision facilities, and allow remote management, withself-diagnosis and configuration.The TRANSMISSION UTILITY will be responsible for the full operationalization of the communicationslinks, with all infrastructure required to implement the telecommunications system, on the basis of theprovisions in item 5 of documents GTS-BTA-S/SE-001 and GTS-IBN-S/SE-001, such as: buildings, 48Vcc direct current power supply for the telecommunications equipment, able to provide power for atleast 12 hours, should the Alternating Current System fail, as well as any other infrastructure ranked asnecessary to ensure the full functioning of the telecommunications system.The TRANSMISSION UTILITY will be responsible for monitoring the voice and data channels thatinterconnect with the National Electricity System Operator (ONS), FURNAS and COPEL, whenever sorequested thereby. The purpose of these monitoring facilities is to measure performance indicators inorder to check that the channels are operating in accordance with the minimum acceptablerequirements. If any discrepancies are noted in the measurements obtained compared to therecommended values, the TRANSMISSION UTILITY will agree to undertake corrective maintenancemeasures as required within the deadline stipulated under common agreement with the ONS, FURNASand COPEL.



Should it be necessary to schedule downtime for any data or voice channels of interest to the ONS,FURNAS and COPEL, the TRANSMISSION UTILITY should enter into understandings with theOperating Center of the ONS, FURNAS and COPEL with which it is connected, in order to obtainapproval for the service requested, at a convenient date and time.Finally, when submitting the executive project, the TRANSMISSION UTILITY should demonstrate thatthe communications architecture (configuration, number and capacity of the links, etc.) adoptedcomplies with the requirements stipulated in this Notice of Tender, through a Calculation Memorandum.

1.9.2 Remote protection requirementsThe telecommunication equipment dedicated to remote protection functions should be appropriate foruse in bulk power system facilities in order to recognize the presence of signals and/or frequencies thatidentify a command to the protection systems.The equipment should be fitted with test switches that allow intervention therein, without having to de-energize the transmission line.The remote protection facilities should maintain the operating, reliability, safety and security underadverse signal/noise ratio conditions, as well as in case of breakage of the transmission line conductors(use of the unblocking logic).Independent, redundant telecommunication equipment should be used for Main and AlternateProtection Systems, preferably using independent physical transmission facilities so that the non-availability of one set of telecommunications facilities does not adversely affect the availability of theother. Each item of communications equipment should be fitted with at least two communicationschannels. Consequently, the transmission line protection system will have at least four remoteprotection channels each way, two associated with the primary protection system and two associatedwith the alternate protection system.The direct trip-switch transfer schemes for each protection system should be implemented through theuse of two communications channel for each of them, combined in series. The outlet points for the trip-switch transfer receivers should be connected in series, so that both units should receive the signalbefore activating the trip-switch command. The logic should be designed in a way that allows thesystem to be tripped, even if contact is lost with one of the communications channels.The direct trip transfer channels will remain continuously operative when the block relays arefunctioning (occurrence fault in the circuit breakers, faults in the line reactors, and overvoltageprotection system operative) and will function temporarily, when tripped by the line protection scheme.The reception logic should be equipped with the means to identify trip transfer signals, distinguishingthose for which automatic reconnection should be permitted from those where reconnection should notbe permitted.For the remote protection schemes based on permittive overreach logic, one of the channels in eachprotection scheme should be brought into action by the line protection over reach metering units. Forremote protection schemes based on block signal directional comparison logic schemes, the channelsshould be brought into action by the line protection reverse metering units. For remote protectionschemes based on permittive underreach logic, these channels will be brought into action by the lineprotection underreach metering unit.The telecommunications channels should be specific to the protection schemes, and should not beshared with any other applications, ensuring that the time between sending a signal from a terminal andits receipt at the opposite terminal is less than 15 ms.



Provision should be made to record the sending and reception of signals associated with bringing theremote protection system into action, in the sequence of events registration system of the facility, inorder to ensure faster analysis of post-disturbance occurrences.

1.9.3 Voice channel requirementsThe TRANSMISSION UTILITY should provide a communication system with two voice channels, withat least one of them being direct; the other may be operated through a switched telephone system,both full duplex, with sound and visual signaling facilities for operational communications of the powersystem between the:• Substations involved: Bateias and Ibiúna;• Should the TRANSMISSION UTILITY decide to use the local Operating Center, either its own or

outsourced, channels should be provided between this Center and the:- Bateias Substation;- Ibiúna Substation;- Southeast Regional Operating Center COSR-SE, (ONS);- South Regional Operating Center COSR-S, (ONS);- COPEL Operating Center - COS-COPEL, which is the Center contracted by the ONS to

handle the functions of the Paraná Operating Center (COS-PR);- São Paulo Regional Operating Center CTRS (FURNAS) (Campinas-SP).

• Should the TRANSMISSION UTILITY decide not to use a Local Operating Center, whether in-house or outsourced, the substations should have channels available connecting them to throughthe ONS, FURNAS and COPEL Centers as follows:- Ibiúna Substation:

º Channels linking them to Southeast Regional Operating Center - COSR-SE (ONS);º Channels linking them to São Paulo Regional Operating Center CTRS (FURNAS)

(Campinas SP).- Bateias Substation:

º Channels linking them to the South Regional Operating Center COSR-S;º Channels linking them to the COPEL Operating Center COPEL - COS-COPEL,

which is the Center contracted by the ONS to handle the functions of the ParanáOperating Center (COS-PR);

Additionally, a mobile communications system should be supplied to cover the entire length of thetransmission lines and the substations involved, providing support for the electrical andtelecommunications maintenance staff.

1.9.4 Data transmission requirementsThe data links specified below should be sized (number of channels, speed, use of alternative routes,etc.) in order to support the loads required to transfer the information and the specific controls (noteitems 1.5, 1.6, 1.7 and 1.8) with the availability and quality ratings as described in this Notice of Tender.

1.9.4.1 Supervision and control linksFor supervision and control by the ONS, FURNAS and COPEL, the following redundant data linksshould be supplied, preferably through alternative routes.• Should the TRANSMISSION UTILITY decide to use the Local Operating Center, either in-house or

outsourced:



- Links with the Local Operating Center:º Bateias substation;º Ibiúna substation;º Southeast Regional Operating Center, COSR-SE (ONS);º South Regional Operating Center, COSR-S (ONS);º COPEL Operating Center - COS-COPEL, which is the Center contracted by the

ONS to handle the functions of the Paraná Operating Center (COS-PR);º São Paulo Regional Operating Center - CTRS ( FURNAS) (Campinas, SP).

- Links with Bateias Substation for Automatic Generation Control (CAG) purposes:º Southeast Regional Operating Center, COSR-SE (ONS).

Note the specific characteristics of this link described in the item entitled Supervision andControl Requirements by the ONS (Requisitos de Supervisão e Controle pelo ONS).

• Should the TRANSMISSION UTILITY decide to use a Local Operating Center, either in-house oroutsourced:- Link with the Southeast Regional Operating Center - COSR-SE:

º Ibiúna Substation.- Link with the South Regional Operating Center, COSR-S (ONS):

º Bateias Substation.- Link with the COPEL Operating Center - COS-COPEL, which is the Center contracted by

the ONS to handle the functions of the Paraná Operating Center (COS-PR);º Bateias Substation;º Ibiúna substation .

- Link with the São Paulo Regional Operating Center, CTRS (FURNAS):º Ibiúna Substation .º Bateias Substation .

- Link with the Bateias Substation for Automatic Generation Control (CAG) purposes:º Southeast Regional Operating Center, COSR SE (ONS).

Note the specific characteristics of this link described in the item entitled Supervision andControl Requirements by the ONS (Requisitos de Supervision e Control pelo ONS).

These links should be independent of any other data link.

1.9.4.2 Other data linksFor billing metering purposes, provision should be for two data links, one dedicated, direct, permanentand in continuous use by ASMAE in São Paulo and the other based on direct extension dialing (DDR)for access by authorized agents or alternative access by the ASMAE.In order to handle the disturbance records data uptake, two direct extension dialing (telephoneextensions should be provided).Alternative solutions allowing access through a data network may be accepted, provided that at leastthe same performance ratings are guaranteed as those assigned to the links specified above.



1.10 BASIC REQUIREMENTS FOR THE BASIC AND ALTERNATIVE CONFIGURATIONS

As indicated above the TRANSMISSION UTILITIES are not free to modify:• The locations of the Ibiúna and Bateias Substations;• The voltage levels (only alternating current);• System flow distribution (effective impedance).

On the other hand, as also indicated above, the TRANSMISSION UTILITIES are free to suggestalternative configurations, including:• Reactive values for the line reactors and series capacitors;• The parameters of the Transmission Line, provided that the requirements in the Annex 7A herein

are met.• Pylon configurations.

Regardless of the proposed configuration, the TRANSMISSION UTILITIES shall perform at least thefollowing studies:• Bulk power flow, load rejection and energization at the basic frequency;• Temporary studies for reconnection, load rejection and energization.

These studies shall demonstrate compliance with the provisions in the Electricity Systems planningGroup (GCPS Grupo Coordenador do Planejamento dos Sistemas Elétricos) criteria document andthe study reports listed in item 2.1.1 as well as the following criteria and requirements.

1.10.1 Operating voltageThe effective operating voltage between the phases of all the busbars in the interconnected systemunder all exchange situations and scenarios assessed in the basic configuration shall fall within therange of values listed in Table 9. Table 9 refers to the normal operating condition (permanent basis)and the emergency operating condition (simple contingencies in the studies that set the basicconfiguration).

Table 9 Acceptable effective voltage between phases (kV)

Emergency operating condition(*)Rated Normal operating condition

Busbars with load Other busbars500 500 - 550 475 - 550 475 - 600345 345 - 362 328 - 362 328 - 362

(*) 1-hour duration

1.10.2 Maneuvering requirements associated with the transmission lines

1.10.2.1 Acceptable overvoltageThe maximum voltage for permanent and dynamic systems at the ends of the TRANSMISSION LINESafter maneuvering (energization, three-pole reconnection and load rejection) should be compatible withthe supportability of the terminal substations equipment.



The dynamic voltage effective voltage between the phases at the instant immediately after operatingthe circuit breakers and the sustained voltage effective voltage between the phases in thesubsequent instants shall lie within the range of values given in Table 10.Table 10 Effective voltage between phases acceptable at the end of the transmission lines aftermaneuver (kV)

Rated voltage Dynamic voltage Sustained voltage500 500 a 700 500 a 600

It is acceptable for the overvoltage caused by transmission line energization maneuvering and loadrejection to last for one hour.

1.10.2.2 Energization of transmission linesThe energization of the transmission lines shall be feasible in all situations assessed in the basicconfiguration, complying with the voltage criterion under normal operating conditions as defined in thetable 9.Specifically, provision shall be made for possible two-way energization, should the system reach thelevel of degradation at which this is feasible in the basic configuration.

1.10.2.3 Three-pole reconnection of transmission linesProvisions shall be made for a possibility of three-pole reconnection of all transmission lines.

1.10.2.4 Unipolar reconnectionThe system shall plan for unipolar reconnection with downtime of 500 ms. In order to assess thesuccess of eliminating the secondary arc, the curve in Figure 4 shall be considered at the end of the500 ms downtime, showing the possible arc elimination area, relating the effective value of the arccurrent before elimination to the first voltage peak after re-establishment.

FIGURE 4 CRITERION FOR ASSESSING THE SUCCESS OF SINGLE-PHASE RECONNECTION

0 5 10 15 20 25 30 35 40 4550 55Arc current (Arms)

0

50

100

150

200

Reconnection Voltage (kVp)



1.10.2.5 Load RejectionThe load rejection situation assessed for the basic configuration shall be met without detriment to theperformance criteria.

1.10.3 Opening and closing of the disconnecting and earth disconnecting devicesThis equipment shall meet the requirements of the applicable standards.The opening and closing of the disconnecting and earth disconnecting devices shall take intoconsideration the induced resonant voltages of transmission lines in parallel, operating under normalconditions with maximum load or with single-phase defect. Any possible resonance induction caused bythe transmission lines that affect other existing parallel transmission lines shall also be checked andcorrected.

1.10.4 Circuit breaker cutout requirementsThe 500 kV circuit breakers shall be able to handle the following operations:• Idle line opening: considering the longest line, with effective inter-phase voltage of 770 kV at a

frequency of 66 Hz, without relighting the arc. A frequency of less than 66 Hz will be acceptableprovided that this is confirmed by system studies.

• Opening the system through opposing phases.• Opening of three-phase fault not involving earth, in the busbar or line outlet.• Opening of lengthy defect;• Opening of short circuit current with the highest X/R ratio in the system.

The circuit breakers used in reactor handling shall also be able to open small inductive currents.The circuit breakers shall also be able to handle energization and reconnection of the transmissionlines, as well as the energization and opening of the grid-connected transformers, abiding by theovervoltage supportable limit of the associated equipment and the power absorption capacity of thelightning arresters involved.

1.10.5 Transformer unit maneuvering requirementsProvision should be made to energize both the primary and secondary transformer units. Based on pre-energized voltage of 550 or 362 kV, these maneuvers should not cause any reduction in the useful lifeof the unit, nor should they cause any overvoltages above the support limits of the substationequipment for the system configurations assessed in the reference study.



2 ENGINEERING AND PLANNING STUDIES ON THE EXPANSION OF THE 500 KVSOUTH/SOUTHEAST AND 500 KV SUBSTATIONS BELONGING TO THE INTERCONNECTIONThe Engineering and Planning studies and the documents prepared by CCPE, FURNAS and COPELfor the 500 kV TRANSMISSION LINE and the 500 kV substations belonging to the South/Southeastinterconnection are listed below, and may be used partially or in full at the discretion of theTRANSMISSION UTILITY, and for the sole liability thereof.

2.1 ENGINEERING AND PLANNING STUDIES AND THE RELATED TECHNICAL DOCUMENTATIONFOR THE SOUTH/SOUTHEAST INTERCONNECTION

2.1.1 Reports

ANEEL Nº COMPANY DOCUMENT510 CCPE Project Ibiúna Bateias System Study, CCPE July 2000511 CCPE Project Ibiúna Bateias Transitory Equipment and Conductors Selection

Studies, CCPE July 2000

2.1.2 Electrical System Data Studies

ANEELNo. COMPANY DOCUMENT

512 CCPE Data Base used in the Bulk Power Flow and Stability Simulations, in theANATEM and ANAREDE program formats, CEPEL

513 CCPE Data Base used in the transitory electromagnetic equipment studies inthe ATP digital program format

2.2 REPORTS ON THE BASIC REQUIREMENTS AND CHARACTERISTICSThese Reports form an integral part of ANNEX 7A, and the recommendations should be adopted by theTRANSMISSION UTILITY when developing its projects and designs for the implementation of thefacilities.

ANEEL No COMPANY No . DOCUMENT

514 GTS-BTA-S/SE-001 Basic Requirements and Characteristics of the Bateias SubstationFacilities

515 GTS-IBN-S/SE-001 Basic Requirement and Characteristics of the Ibiúna substationfacilities



2.3 SUBSTATION DOCUMENTS

2.3.1 BATEIAS - COPEL

ANEEL No No COPEL DESCRIPTION

01 BTA-EL-001 GENERAL 525kV SECTOR SCHEME02 BTA-EL-002 SCHEME METERING AND PROTECTION03 BTA-EL-003 COMMAND HOUSE PLAN04 BTA-EL-004 SCHEME AUXILIARY SERVICE, AC05 BTA-EL-005 SCHEME AUXILIARY SERVICE, DC06 BTA-EM-001 BUSBARS AND EQUIPMENT PLAN - 525 kV SECTOR07 BTA-EM-002 BUSBARS AND EQUIPMENT - CUTS A and B - 525kV SECTOR08 BTA-EM-003 GENERAL PLAN EARTH NETWORK AND INNER FENCE 138-230-

525kV SECTORS09 BTA-EM-004 525kV SECTOR AND AUTO-TRANSFORMERS LIGHTNING AND

POWER ARRANGEMENT PART I10 BTA-EM-005 525kV SECTOR AND AUTO-TRANSFORMERS LIGHTNING AND

POWER ARRANGEMENT PART 211 BTA-CV-001 DRAINAGE: SUPPLEMENTARY DRAINAGE SYSTEM PLAN 525kV

SECTOR12 BTA-CV-002 URBANIZATION: LANDSCAPING PLAN AND LOCATION13 BTA-CV-003 DRAINAGE: DETAILS OF SUPPLEMENTARY DRAINAGE SYSTEM

525kV SECTOR14 BTA-CV-004 : CPs DRAINAGE TABLE15 BTA-CV-005 COMMAND HOUSE: PLAN16 BTA-CV-006 CABLE CONDUIT SHAPES (PART 1)17 BTA-CV-007 CABLE CONDUIT SHAPE (PART 2)18 BTA-CV-008 525kV BASES LOCATION PLAN (PART I)19 BTA-CV-009 525kV BASES LOCATION PLAN (PART 2)

2.3.2 IBIÚNA SUBSTATION FURNAS

ANEEL No FURNAS No DESCRIPTION1 3698700A1 South/Southeast Interconnection 345 kV Sector Indicative Facility

Design Simplified Diagram2 3698726A1 South/Southeast Interconnection Facility Areas indicative drawing3 3700283A2 Maneuvering Yard 500 kV Sector Circuit-breaker and half

arrangement Standard line input facility4 194222D R14 General Arrangement5 199427D R2 Location Plan6 201924D R4 Simplified Diagram General Auxiliary AC Services7 267173D R0 Simplified Diagram AC/DC Tertiary Area and Auxiliary Services8 194220D R6 Maneuvering Yard Electrical Equipment 345 kV Sector AC

Ground Plan9 267871D R4 Maneuvering Yard Electrical Equipment 500 kV Sector Plan



ANEEL No FURNAS No DESCRIPTION

10 271566D R4 Maneuvering Yard Electrical Equipment Transition between 345and 500 kV Yards

11 267873D R2 Maneuvering Yard Electrical Equipment 500 kV Circuit Breaker Plan and View

12 270928D R3 Maneuvering Yard Electrical Equipment 500 kV SectorTransformer Group Plant

13 270929D R3 Maneuvering Yard Electrical Equipment 500 kV Sector Transformer Group Cross Sections

14 267875D R2 Maneuvering Yard Electrical Equipment 500 kV SectorInterconnection Plant and View

15 267876D R2 Maneuvering Yard Electrical Equipment 500 kV Sector LineOutlet Facility Plan and View

16 267877D R2 Maneuvering Yard Electrical Equipment 500 kV Sector Interconnection Plant and View

17 209707C R4 Maneuvering Yard Electrical Equipment DE 345 Kvca AC Sector Bay 5 Outlet to 500 kV Transformer

18 220637D R3 Maneuvering Yard Pipelines and Conduits General Plan19 272112D R2 Maneuvering Yard 500 kV Sector Pipelines, Conduits and

Auxiliary Services General Plan20 221164E R7 Maneuvering Yard Earthing Network General Plan21 229019D R5 Maneuvering Yard Earthing Network Sectoral Plan 345 kVCA22 275738D R3 Maneuvering Yard 500 kV Sector Earthing Network Sectoral Plan23 198056D R10 Station Control House Equipment Layout First Floor Plan24 198055D R18 Station Control House Equipment Layout Second Floor Plan25 199085E R11 Earth-Leveling Plan General Arrangement26 272930D R6 Maneuvering Yard 500 kV Sector General Arrangement of the

Foundations



3 ENVIRONMENT AND LICENSING

3.1 GENERAL

The TRANSMISSION UTILITY should implement the GROUP A TRANSMISSION FACILITIES incompliance with Brazilian Law and the environmental requirements applicable thereto.

3.2 DOCUMENTATION AVAILABLE

ANEEL No COMPANY No DESCRIPTION

516 No number Preliminary assessment of the technical and environmentalcharacteristics of the potential corridor for the 525 kVtransmission line between Bateias and Ibiúna



4 GUIDELINES FOR DESIGN PREPARATION

As prescribed in the Notice of Tender, item 4.8 and for the purposes of checking compliance with thetechnical requirements, the TRANSMISSION UTILITY shall submit the Basic Design of the facilities toANEEL for the go-ahead, and in compliance with the report entitled Guidelines for the TransmissionSystem Basic Design (Diretrizes para Projeto Básico de Sistemas de Transmissão) - DNAEE-ELETROBRAS, as itemized below:

4.1 ENGINEERING AND SYSTEM STUDIESThe TRANSMISSION UTILITY shall submit the reports on the studies listed in item 1.10.Whenever requested, the TRANSMISSION UTILITY shall prove in a study that the solutions adopted inthe specifications and designs of the transmission facilities herein are adequate.

4.2 BASIC SUBSTATION DESIGNThe basic design documents for the substation shall include:• List of official technical standards adopted.• Design criteria for the civil works, electromechanical design, the protection, command, supervision

and telecommunication systems, armoring and earthing facilities, including premises adopted.• Drawing of location of facilities.• Unifilar diagram.• Architectural drawing of constructions: plans, profiles and facades.• General bay layout: plan and typical profiles.• Layout of armoring and earthing systems.• Technical characteristics of main items of equipment, as indicated in 4.3, and materials.• Description of planned systems for protection, control, supervision and telecommunications,

including schematic diagrams.• Description of the ancillary systems, including schematic diagrams and a technical datasheet for

the main items of equipment and materials.

4.3 BASIC DESIGN FOR THE STRETCHES OF THE TRANSMISSION LINEThe basic design documents for the stretches of the transmission line shall provide:

4.3.1 Technical reportTechnical report with complete schedule and detailed description of treatment, and the hypothesesadopted for wind data, dynamic pressures and the resulting loads, as well as the loading schemes andhypotheses, and the respective calculation entries with a complete sizing of the supports, including:• Maps (isótacas)• Wind gauging stations used• Annual maximum wind velocity at a height of 10m for an average 3 seconds, 250 year recurrence

interval and also with an average of 10 minutes.• Annual Average Maximum wind velocity at a height of 10m for an average of 3 seconds, 250 year

recurrence interval and also with an average of 10 minutes.• Variation coefficient of Annual Maximum Velocity at a height of 10m (percentage).• Coefficients of gusts at a height of 10m for an average of 10 minutes.



4.3.2 Design standards and documentation.The following documents and standards shall be submitted:• List of the official technical standards used.• Calculation records for the supports.• Drawing of the selected guideline and its any future interference.• Drawing of the passage way, clearances and security gaps.• Mechanical rules for cables: physical characteristics, basic status and pressure resulting from wind

pressures.- Support (metal or reinforced concrete structure, and/or special structures);- Types, application characteristics and load test reports for pre-existing support;- Drawings of the profiles with main properties;- Security coefficients;- Active wind pressures (cables and stay poles), drag coefficients, resulting forces and

application points;- Loading schemes and active loads;- Resulting loads on the foundations.

• Prototype loading test (for the most frequently used single stay poles):• Preliminary loading test program to be undertaken, indicating the expected date, load hypotheses

and determination (Kgf) and respective testing sites.• Types of foundations: sizing criteria and dimensional drawings.• Conductor cables: characteristics• Lightning arresters: characteristics• Insulator chains: electro-mechanical coordination, drawings and other characteristics.• Counter weight: characteristics, material, method and sizing criteria.• Metalwork, spacers and accessories.

- Description, type trials, physical characteristics and manufacture drawing.• Wind vibrations:

- Reports on wind vibration studies and damper systems for cable fatigue control.- Damper system design for cable fatigue control, to ensure no damage to cables:



5 TIME-SCHEDULE

The TRANSMISSION UTILITY shall submit the deployment schedule for the TRANSMISSIONFACILITIES belonging to its concession, pursuant to models given in Table A and B of Annex 7A,indicating the intermediate benchmarks, for the following activities: environmental licensing, basicdesign, topography, work site, foundations, pylon erection, conductor cable laying and installation ofequipment, civil construction works and erection of transmission and substation facilities, andcommissioning, permitting monthly check on the progress of the works, to ensure the COMMERCIALOPERATION START-UP within no more than 22 (twenty two) months.



5.1 PHYSICAL TIME-SCHEDULE FOR TRANSMISSION LINES

COMPANY NAMEDATE

MONTHSNo DESCRIPTION OF

INSTALLATION STAGES 1 2 3 20 21 22

1 DESIGN1.1 BASIC DESIGN1.2 TOPOGRAPHY

etc.2 ENVIRONMENTAL

LICENSING

3 CIVIL WORKS ANDERECTION

3.1 WORK SITE FACILITIES3.2 FOUNDATIONS3.3 PYLON ERECTION3.4 CABLE LAYING

Etc.4 COMMISSIONING and

ENERGIZATION5 COMMERCIAL OPERATION

START-UPCOMMENTS: STARTING DATE

COMPLETION DATEDURATION

SIGNATURE CREA No

ENGINEER REGION



5.2 PHYSICAL SUBSTATION TIME SCHEDULE

COMPANY NAME SUBSTATION

DATE

MONTHSNo.

DESCRIPTION OFWORKS STAGES 1 2 3 4 20 21 22

1 DESIGNS2 PROCUREMENT2.12.22.32.43 CIVIL WORKS AND

ERECTIONS3.1 Mobilization3.23.33.43.53.6 Commissioning4 ENERGIZATION4.1STARTING DATE COMMENTS:

COMPLETION DATE DURATION OF WORKSCREA NoENGINEER

SIGNATURE REGION

Notice of Tender to Auction No. 004/2000-ANEELANNEX 7B - GROUP B Tucuruí Vila do Conde Transmission Line 2nd circuit


ANNEX 7B

TUCURUÍ- VILA DO CONDETRANSMISSION LINE – 2ND CIRCUIT

CHARACTERISTICSAND

BASIC TECHNICAL REQUIREMENTSOF

TRANSMISSION FACILITIES



CONTENTS

1 BASIC REQUIREMENTS OF FACILITIES 74

1.1 INTRODUCTION ............................................................................................................................................................. 741.1.1 General description 741.1.2 Basic configuration 741.1.3 System data used 751.1.4 General requirements 75

1.2 TRANSMISSION LINE..................................................................................................................................................... 771.2.1 Electric power indicators 771.2.2 Mechanical indicators 79

1.3 SUBSTATIONS............................................................................................................................................................. 811.3.1 General requirements 811.3.2 Equipment requirements 82

1.4 PROTECTION SYSTEM TECHNICAL REQUIREMENTS ....................................................................................... 841.4.1 General 841.4.2 Transmission Line Protection 841.4.3 Reactor protection 871.4.4 Busbar protection system for the Tucuruí Disconnecting SS and Vila do Conde SS 881.4.5 Circuit breaker failure protection system 881.4.6 Special Protection Systems 88

1.5 SUPERVISION AND CONTROL SYSTEMS............................................................................................................. 911.5.1 Introduction 911.5.2 Supervision and control requirements of the facilities 91

(A) TELEMETERING 93

(B) STATUS INDICATION 93

(C) EACH ACQUISITION AND CONTROL UNIT (UAC) SHALL BE FITTED WITH AN INTERNALCLOCK AND CALENDAR TO INFORM THE DAY, MONTH, YEAR, HOUR, MINUTE, SECONDAND MILLISECOND OF EACH STATUS VARIATION METERING OPERATION. THESE INNERCLOCKS MUST BE FITTED WITH SYNCHRO CIRCUITS BASED ON A SIGNAL WITH ANABSOLUTE DATE OBTAINED FROM A GPS SYSTEM TO ENSURE THAT THE SUPERVISIONAND CONTROL OF THE VARIOUS FACILITIES IS UNDERTAKEN ON THE SAME TIME BASIS.THE SYSTEM SHALL BE DESIGNED TO ACHIEVE BETTER ACCURACY THAN ONEMILLISECOND. 93

(D) ALL TELEMETERING AND STATUS INDICATORS SHALL HAVE DATA QUALITY INDICATORSFOR THE DATA COLLECTION AND THE LOCAL SUPERVISION CONDITIONS (DATA INVALIDAT POINT OF ORIGIN, NOT UPDATED DURING THE LAST REMOTE SWEEP, ETC.). 94

(E) LL CONTROL AND SUPERVISION SYSTEM INFORMATION TRANSFERRED TO THEOPERATING CENTERS OF THE UTILITIES MENTIONED HEREIN SHALL BE RAW DATA, AS



COLLECTED FROM THE TRANSDUCERS OR INTERLEAVING RELAYS, THAT IS, WITH NOPRIOR PROCESSING EXCEPT WHEN EXPLICITLY AGREED ON A CASE-BY-CASE BASISWITH ONE OF SAID UTILITIES. IN THESE CASES, THE QUALITY INDICATORS SHALLINCLUDE AT LEAST THE FOLLOWING: 94

(F) INFORMATION FOR SEQUENCING EVENTS: 94

(G) DATA AGE 95

(H) DEAD BAND 961.5.3 Requisitos de supervisão pelo agente proprietário das subestações 961.5.4 ONS supervision and control requirements 981.5.5 Availability and quality assessment requirements 101

A) QI : QUALITY RATE OF RESOURCE “I”; 103

B) TQ: TOTAL TIME IN MINUTES FOR THE STUDY PERIOD; 103

C) TNQI: SUM OF THE PERIODS WHEN POINT “I” DOES NOT COMPLY WITH THE CONCEPT OFQUALITY THE WHOLE TIME “TQ”. 104

1.6 1061.7 TECHNICAL REQUIREMENTS OF DIGITAL OSCILLOGRAPHY SYSTEM ........................................................ 106

1.7.1 General aspects 1061.7.2 Description of features 1061.7.3 Digital Disturbance Meter trip-switch 1071.7.4 Time Synchronization 1071.7.5 Electromagnetic compatibility requirements 1071.7.6 Characteristics of input and output signals 1071.7.7 Occurrence metering capacity. 1081.7.8 Communication requirements 109

1.8 TECHNICAL REQUIREMENTS OF THE TELECOMMUNICATIONS SYSTEM TO BE DEPLOYED .......................... 1101.8.1 General requirements 1101.8.2 Remote protection requirements 1111.8.3 Voice channel requirements 1121.8.4 Data transmission requirements 112

1.9 BASIC REQUIREMENTS FOR THE BASIC AND ALTERNATIVE CONFIGURATIONS...................................... 1141.9.1 Operating voltage 1141.9.2 Handling requirements associated with the transmission lines 1141.9.3 Opening and closing of the disconnecting and earth disconnecting devices 1161.9.4 Circuit breaker cutout requirements 116

2 ENGINEERING AND PLANNING STUDIES FOR THE TUCURUÍ-VILA DO CONDETRANSMISSION LINE 2ND CIRCUIT AND TERMINAL SUBSTATIONS. 117

2.1 ENGINEERING AND PLANNING STUDIES AND THE RELATED TECHNICAL DOCUMENTATION................ 1172.1.1 Report 117

2.2 SUBSTATION DOCUMENTS.................................................................................................................................. 1182.2.1 VILA do CONDE SUBSTATION 1182.2.2 TUCURUÍ DISCONNECTING SUBSTATION 119

2.3 TRANSMISSION LINE DOCUMENTS .................................................................................................................... 120



2.4 REPORTS.................................................................................................................................................................... 120


3.1 GENERAL................................................................................................................................................................. 1213.2 AVAILABLE DOCUMENTS...................................................................................................................................... 121




5 TIME-SCHEDULE 125




1 BASIC REQUIREMENTS OF FACILITIES

1.1 INTRODUCTION

1.1.1 General descriptionThis annex presents the basic technical requirements and characteristics of the second 500 kWTucuruí Vila do Conde transmission line and related facilities, as part of the Tucuruí HEPTransmission System, which will interconnect the Tucuruí disconnecting and Vila do CondeSubstations, both in the State of Par, Brazil, and owned by ELETRONORTE, as a reinforcement to theservice to Belém and surroundings, for further reliability.Figure 2 shows the electrogeographic map of the Brazilian power system, including the saidTransmission Line.The project comprises the deployment of the facilities listed in subitem 1.1.2, consisting basically of thesecond 500 kV TucuruíVila do Conde circuit.The installation of the 2nd circuit of the 500 kV Tucuruí Vila do Conde Transmission Line, in theAuction, also includes the reactive compensation associated to this circuit, the terminal equipment forhandling, protection, supervision and control, telecommunications, and all other equipment, servicesand facilities required for providing the PUBLIC UTILITY TRANSMISSION SERVICE even if notexpressly indicated in ANNEX 7.

1.1.2 Basic configurationThe basic configuration consists of the projects listed in the following Tables. The transmission linesare listed in Table 1, while the substations are in Table 2. The reserve units are not included in thequantities presented therein.

Table 1 – 500 kV Transmission Lines

Origin Destination Circuito KmTucuruí Vila do Conde 2° 323

Table 2 500 kV Substations

Substation Voltage(kV) Main projects Unit capacity

Tucuruí 500 1 line input

Vila do Conde 500 1 line input3 single-phase line reactors 54.3(1)

Notes:(1) The unit capacity of the reactors in Mvar refers to the 500 kV voltage.(2) For positioning equipment, consult the diagrams provided.



The aforementioned basic configuration and technical requirements herein are the minimumperformance standards for other solutions, which shall be demonstrated in the technical track record.

Figure 1 shows the North-Northeast interconnection configuration and Tucuruí Vila do Condeinterconnections.

FIGURE 1 CONFIGURATION OF SYSTEM

1.1.3 System data usedThe system data used in the permanent, dynamic and transitory studies are available to determine thebasic configuration, pursuant to the documentation listed in item 2.The data on the permanent and dynamic studies are available in the format of the ANATEM andANAREDE grid simulation digital programs of the Eletrobras R&D Center (CEPEL)Data relating to the temporary electromagnetic studies are available in the ATP digital program format

1.1.4 General requirementsThe design and construction of the transmission line and terminal substations shall comply with thelatest revisions of the Brazilian Technical Standards Association (ABNT Associação Brasileira deNormas Técnicas) standards, wherever applicable, and, in their absence, with the latest revisions of theIEC, ANSI or NEC standards, in that order of preference, unless especially indicated otherwise.All local environmental conditions required for preparing the design, construction work and operation ofthe facilities shall be obtained by the TRANSMISSION UTILITY.The TRANSMISSION UTILITY is and entitled to and liable for sizing and specifying the equipment andtransmission facilities comprising the Public Utility Transmission Service herein, to comply with Annex 7herein and good engineering practices as well as the [market] reserve policy.



FIGURE 2 ELECTROGEOGRAPHIC MAP OF THE BRAZILIAN POWER SYSTEM

DIRETORIA DE PLANEJAMENTO E ENGENHARIADEPARTAMENTO DE TRANSMISSÃO

BR-9807

1

2

3

4

5

COARACY NUNES

SANTANA

SANTARÉM

RURÓPOLISITAITUBA

ALTAMIRA

TUCURUÍ

V. CONDE

S.MARIA

SÃO LUÍS

UTINGA

MIRAMAR

TERESINA

B.ESPERANÇA

S.J.PIAUÍ

FORTALEZA

MOSSORÓ

AÇU NATAL

J.PESSOA

RECIFE

MACEIÓ

ARACAJU

SALVADOR

XINGÓIRECÊ

B.J.LAPA

EUNÁPOLIS

FUNIL

BARREIRAS

VITÓRIA

CAMPOS

RIO DE JANEIROC.PAULISTA

MASCARENHAS

SOBRADINHO

P.DUTRA

SERRA DA MESA

RONDONÓPOLIS

C.NOVOSP.FUNDO

IVAIPORÃ

70 MW

50 MW

5

4

31

2

S.QUEBRADA

MANAUS

BALBINA

RIO BRANCO ARIQUEMES

SAMUEL

JIPARANÁ

PORTO VELHO

ABUNÃ

P.BUENO

VILHENA

SINOPGURUPI

MIRACEMA

COLINAS

SORRISO

NOVA MUTUM

MANSOCUIABÁ

BARRA DO PEIXE

RIO VERDE

CORUMBÁ

C.GRANDE

GOIANIA MONTES CLAROS

T.MARIAS

J. FORA

CURITIBA

BLUMENAU

PORTO ALEGRE

ITÁ

F.AREIAITAIPUS.OSÓRIO/S.CAXIAS

S.SANTIAGOXANXERÊ

S.ROSA

DOURADOS

SÃO PAULO

MARABÁ

XINGUARA

REDENÇÃO

CANDIOTA

GARABISÃO BORJA

ALEGRETEURUGUAIANA

LIVRAMENTO

BRASÍLIA

BOA VISTA

STA ELENA

BELOHORIZONTE

GOV.MANG.

IMPERATRIZ

AÇAILÂNDIA

Eletrobrás

Principais Linhas de TransmissãoConfiguração 2007

+-

COMPLEXO RIO PARANÁ

COMPLEXO RIO PARANAPANEMA

COMPLEXO RIO GRANDE

COMPLEXO RIO PARANAÍBA

COMPLEXO PAULO AFONSO



1.2 TRANSMISSION LINE

1.2.1 Electric power indicators

1.2.1.1 Electrical parameters for Transmission LineThe lines positive sequence longitudinal reactance shall enable the distribution of capacity flow alongthis line, similar to those in the alternative under reference mentioned in the studies.

1.2.1.2 Loading of transmission lineThe transmission line shall be able to withstand 2300 A and 2800 A, on a permanent basis, and in anemergency, without violating any performance criterion.

1.2.1.3 Setting the maximum deflection of lightning conductors and properties of lightning arrestersThe following climate conditions shall be considered In the site design of the structures and propertiesof the lines lightning arresters:• Average maximum temperature of the region;• Maximum sunlight;• Wind speed of no more than 1 m/s; maximum average temperature in the region;

The maximum conducting cable deflection shall be set as prescribed in NBR-5422, considering theaverage maximum temperature for the region, maximum sunlight, wind velocities of no more than 1m/s, for a maximum current of 2800 A.The same climatic conditions used to determine the maximum conductor deflections shall beconsidered to assess the properties of the lightning arresters, as well as the additional conditionsbelow:• 40 kA short-circuit current levels in all substations, except the Tucuruí Disconnecting Substation,

which is 50 kA• Possibility that the lightning arresters in the stretches of the line are connected to the earthing grid

of the substations and earthed in all structures;• Fault elimination time corresponding to the backup protection.

1.2.1.4 Reactive compensationReactive tapping compensation of the basic configuration is given in Table 2.The transmission line reactive tapping compensation shall be set so that the set of lines and theircompensations meets the requirements in item 1.8 and the other criteria herein.Data, guidelines and conditions for analyzing the TRANSMISSION UTILITY are to be found in thedocuments given in item 2.

1.2.1.5 Joule loss in the lightning conductors and arrestersThe positive sequence resistance per length unit of the transmission line for rated 60 Hz frequency andtemperature of 75º C, must be equal to or less than that of the basic configuration: 0.019 Ω/km.



Total loss in the lightning arresters shall be no more than that corresponding to two continuousgalvanized steel Extra High Voltage (EAT) cables with a 3/8 diameter, earthed in all structures and inthe substation earthing network.

1.2.1.6 ImbalanceThe transmission lines shall have a full transposition cycle, preferably with 1/6, 1/3, 1/3 and 1/6stretches of the total length.


(a) Performance in atmospheric dischargesNo disconnection may be made through direct discharges due to the regions predominant land relief.The number of disconnections due to atmospheric discharges may be no more than onedisconnection/100km/year.

(b) Insulation at a maximum operating voltageInsulation of the transmission line at the maximum operating voltage shall be sized on the basis of thepollution characteristics of the region, as classified in the publication IEC 815 Guide for the selectionof insulators in respect of polluted conditions.The minimum level of pollution adopted shall be compatible with the minimum flow distance of 25mm/kV, referring to the maximum phase-earth voltageThe insulation of the transmission line at the maximum operating voltage shall be sized considering theswing of the insulator chain in the wind, with a recurrence interval of, at least, 30 years.A minimum distance shall be kept to avoid a discharge at the maximum operating voltage between anyconductor in the line and the limit of the right-of-way under maximum deflection and swing conditions,as prescribed in NBR-5422.

(c) insulation by hand controlThe maximum fault risk during energization and reconnection operations shall be limited to the valuesin Table 3

TABLE 3 Maximum Full Risk of Manual Control during Energization and Reconnection

Fault risk (non-dimensional)Hand control Between phase and earth Between

phases

Energization 10-3 10-4

Reconnection 10-2 10-3




(a) Visual coronaThe transmission lines should not present a visual corona around the conductor cables and metalworkfor 90% of good weather conditions.

(b) Radio interferenceThe signal/noise ratio at the edge of the right-of-way, indicating the level of immunity of the radiosignals (RI) should be at least equal to 24 dB based on the minimum signal level given in DENTELstandard for 50 % of the atmospheric conditions for the year.

(c) Audible noiseThe audible noise (RA) at the edge of the right-of-way under the maximum operating voltage underconditions of drizzle (<0.00148 mm/min) or mist lasting 4 hours, or during the first 15 minutes of rainshould be equal to no more than 58 dBA.

(d) Electrical fieldThe electrical field one meter away from the ground at the edge of the right-of-way should be 5 kV/m.The field inside the right-of-way should not cause any adverse effects on human beings, due to the useof each stretch thereof.

(e) Magnetic fieldThe magnetic field under maximum loading factor conditions and at the edge of the right-of-way shouldbe less than or equal to 67 A/m, equivalent to magnetic conduction of 83 µT. The field inside the right-of-way should not cause any adverse effects on human beings, due to the use of each stretch thereof.


1.2.2.1 Basic conditions for the conductor cables regulation project.

(a) Basic statusFor minimum temperature conditions, the axial stress should be limited to 33% of the cable failure stress.For wind conditions with a recurrence interval of 50 years, the axial stress should be limited to 50% of the

cable failure stress. For extreme wind conditions, the axial stress should be limited to 70% of the tensile strength of the cable.(b) Normal stress status (EDS)For the final positioning, at the average temperature with no wind, with the stress level complying with the

figures given in NBR-5422 Standard (March 1985).(c) Reference statusThe minimum conductor cable clearance from the ground will not take wind pressure into consideration.

1.2.2.2 Mechanical design criteriaFor the mechanical design of the Transmission Line supports, the loading factors caused by the actionof the wind on the physical components of the line should be established on the basis of probabilisticcharacterizations of wind speeds in the region, treated differently by type: Extended Pressure Systems(EPS) and Thunderstorms (TS).For the wind gauging stations covered in the study, the following parameters should be defined:• Average and variation coefficient (percentage) of the maximum annual wind speed series at a




average integration times of 3 seconds and 10 minutes. If the number of years in the wind speeddata series is low, the estimate of the annual maximum wind speed should be based on at least avariation coefficient compatible with the longest wind speed series measured in the region;



The mechanical design of the Transmission Line should be prepared in compliance with IEC 826 International Electrotechnical Commission: Loading and Strength of Overhead transmission lines.In addition to the hypotheses covered in the IEC Standard, it is also mandatory to introduce loadinghypotheses that reflect Thunderstorms (TS).The electromechanical design of the Transmission Line should comply with the level of reliabilitycorresponding to a recurrence interval equal or greater than 250 years, referred to an intermediate levelat 2 and 3 stipulated in IEC 826.


1.2.3 FoundationsThe foundations for each structure should be designed structurally and geotechnically in a manner thatensures all stresses on each pylon are aligned to the specific conditions of its foundation.The loads on the foundations should be calculated for each structure individually under real loadingsituations, taking into account their specific application conditions: Deadweight Span Stress, Wind SpanStress, Transmission Line Connection Point and Deflection Angle, and Pylon height.The physical and mechanical properties of the foundation soil for each structure should be determinedin an accepted scientific manner, accurately portraying the geomechanical parameters of the soil, withthe following stages being implemented:• Preliminary physiographic study and analysis of the route of the Transmission Line with a



the project.When calculating the foundations, regional geomorphological aspects should be taken intoconsideration that influence the state of the foundation soil, whether in terms of sensitivity, or propensityto expand or collapse, taking seasonal factors into account.The definition of the type of foundation, as well as its structural and geotechnical sizing should beundertaken while taking into consideration the cracking and skewing limits for the soil support capacityand resistance to compression, dragging and horizontal effects, through the use of rational calculationmethods that are not open to query and generally accepted in geotechnical engineering.



1.3 SUBSTATIONS


1.3.1.1 Basic informationThe TRANSMISSION UTILITY shall prepare and present the studies required to determine thecharacteristics and performance levels of all equipment, considering that they will be connected to theexisting system.All equipment shall be specified so as not to adversely affect or limit the substation operation, norimpose operating constraints on the other facilities in the interconnected system. Nor shall equipmentbe used that does not permit the use of equipment belonging to other technologies existing or to beprovided in future expansions.The new facilities shall be compatible with the existing facilities and other aspects of the equipmentrequirements. The guidelines and basic requirements of the existing substation facilities shall befulfilled, as specified in the documents GTS-TUC-TUC/VDC II 001 and GTS VDV TUC/VDC 001.ELETRONORTE will keep the Vila do Conde 2 transmission line span completely free, in the TucuruíDisconnecting Substation, for no more than 120 days after the Tucuruí - Vila do Conde 2nd circuittransmission line concession contract is signed, so that the new CONCESSIONAIRE can install theequipment for operating the Tucuruí-Vila do Conde 2nd circuit transmission line.ELETRONORTE is responsible for making the necessary modifications in the Tucuruí DisconnectingSubstation, to continue with the reliability of the current layout of the span that today operates parallelto that of circuit 1, considering the provision for the new CONCESSIONAIRE.In the existing substations, the basic configuration includes equipment with basic powercharacteristics similar to those existing, which are given in the documents listed above.

1.3.1.2 Yard layoutThe layout of the 500kV yard of the current substations is the one-and-a-half circuit breaker type. Thereshould be enough physical space to install reactor handling equipment.

1.3.1.3 Current capacitya) Voltage on permanent basisThe properties of the busbars and other equipment shall consider a maximum current for the operatingcondition in a permanent circuit of 3150 A.

b) Short-circuit capacityEquipment and other facilities shall be suitable to withstand a 40 kA short-circuit level in the busbars ofthe yards in 500 kV, except for the Tucuruí Disconnecting Substation, which is 50 kA.

c) Earthing systemThe design of the substations shall adopt the criterion of a solidly earthed system.

1.3.1.4 Supportabilitya) Permanent voltageThe properties of the busbars and equipment shall consider a maximum voltage of 550 kV for operatingon a permanent basis.



b) Insulation under pollutionThe facilities shall be insulated in order to handle the regional pollution characteristics, under amaximum operating voltage, as classified in the IEC 815 Guide for the Selection of Insulators inRespect of Polluted Conditions.c) Protection against atmospheric dischargesThe protection system against atmospheric discharges for the substations shall ensure perfectarmoring of the facilities, for currents over 2 kA, and ensure a fault risk of less than or equal to adischarge with 50 year recurrence.Should there be any buildings, they shall meet the prescriptions in the Technical Standard NBR5419.

1.3.1.5 Field effectsa) Corona effectThe components of the substations, especially conductors and metalwork, shall not present a coronaeffect in 90% of good weather conditions. The minimum voltage for the start and finish of the visualcorona shall be 350 kV, for bays in 500 kV. The voltage for eliminating a corona shall be above themaximum operating`.

b) Radio interferenceThe voltage value of a maximum outside radio interference for the equipment shall be 2500 µV/m to1000Hz, in the phase-earth voltage 550/√3kV..


1.3.2.1 ReactorsThe values of total losses (copper losses plus iron losses) referring to the 550 kV voltage and ratedpower shall be less than 0.3% of the normal capacityThe reactor windings shall be in a star network, with the neutral accessible to solid earthing throughreactors or resistors.The insulation of the neutral shall be sized to connect neutral reactors to permit unipolar reconnectionand eliminate parallel circuit resonance.The magnetization curve must be linear until 750 kV voltage.

1.3.2.2 Circuit breakersThe fast reconnection and operating cycle of the circuit breakers shall meet the requirements of thestandards applicable thereto.The maximum downtime for the 500 kV circuit breakers must be two cycles.The 500kV circuit breakers shall be able to perform the handling operations in item 1.8.4.The 500 kV circuit breakers shall have two independent trip-switch logic circuits for detecting polediscrepancy, unipolar and three-pole starting, and an operating cycle compatible with the use ofautomatic single or three-pole schemes for a single-try reconnection.

1.3.2.3 Disconnecting switches, earth plates and earth switchesThis equipment shall meet the requirements of the applicable standards and be able to perform theoperations listed in item 1.8.3.



The earth plates and transmission earth switches must have an induced current-breaking capacity asprescribed in class B of the IEC 1129 standard

1.3.2.4 Lightning arrestersLightning arresters shall be the zinc oxide (ZnO) station type, with no spark gaps, suitable for outsideinstallation. The use of lightning arresters shall be planned at the interface with the existing system(line input facility).

1.3.2.5 Current and bulk power transformersThe characteristics of the current and power transformers, such as the number of secondary windings,transformation ratios, loading, accuracy, etc., shall meet the requirements of the protection andmetering systems.The current transformers shall have secondary windings in individual cores and be designed for outsideinstallation.Power transformers shall be of the capacity type and designed for outside installation.

1.3.2.6 Indoor facilitiesAll instruments, panels and other equipment belonging to the protection, command, supervision andtelecommunication systems shall be sheltered and designed according to the standards applicablethereto, in order to ensure perfect performance of said systems and their protection against prematurewear and tear.In case of buildings, the TRANSMISSION UTILITY is liable for adopting the applicable municipalordinances and occupational safety rules..



1.4 PROTECTION SYSTEM TECHNICAL REQUIREMENTS

1.4.1 General

All protection relays shall use numerical digital technology.The protection systems shall be integrated at the installation level, permitting local and remote accessfor adjustment, event metering, input amounts and other relevant information for each of the protectionrelays or systems. The architecture and protocols used must not impose constraints on the integrationof new equipment nor on the facilitys operation.All digital equipment and systems must have self-monitoring and self-diagnosis facilities, with automaticblocking of defective operations, and local and remote signals for a fault or defect.All protection systems must accept the fault or defect in a component without detriment to its endperformance.Current transformers shall be set out in the facility to permit the overlapping of protection zones foradjacent primary equipment.The protection of equipment must be designed so as not to depend on remote backup protection in thetransmission system.The main protections and (alternate or backup) shall be powered by independent banks of batteries,rectifiers and independent direct current circuits.Protection systems shall be fitted with outlets to start circuit breakers with two independent trip switchesand for a unipolar and/or three-pole start.Information on current and voltage for each main and (alternate or backup) protection system shall beobtained from cores of current transformer cores and secondary transformers with different capacities.All protection systems and related equipment shall follow the applicable rules of electromagneticcompatibility, to the levels of severity suitable for installation in Extra High Voltage substations.The protection systems must meet the existing requirements in terms of sensitivity, selectivity, speedand operating reliability, so that the performance of the power system does not deteriorate underprevailing conditions or during disturbances..

1.4.2 Transmission Line ProtectionThis consists of the set of equipment and accessories required and sufficient for detecting andeliminating all types of defects and other abnormal operating conditions in the Transmission Lines,distinguishing between internal faults and those outside the protected line

1.4.2.1 Reconnection schemesThe transmission lines must be fitted with a reconnection scheme as determined below:

1.4.2.1.1 General requirementsThe reconnection scheme shall enable the selection of the type and number of reconnection attempts,with two possibilities: single and three-pole. In the three-pole position any trip command by theprotection system will disconnect the three circuit breaker poles and start the three-pole reconnection.In the unipolar position, should there be a phase-earth fault, the disconnection and reconnection of thetwo line terminals shall be unipolar; in other types of short-circuit, the cut-out and reconnection shall be



three-pole. Should the reconnection cycle fail (for example, permanent short-circuit) the cut-out will bethree-pole.For substations in a ring layout, a double busbar with a double circuit breaker or one and a half circuitbreakers, there is the possibility of reconnection in either of the line-related circuit breakers. Theplacement or removal from operation, selection of reconnection type and the circuit breaker to bereconnection shall be performed using a selection switch and/or supervision and control system of thesubstation.The reconnection relays shall be fitted with independent timers with possible downtime adjustment, forsingle and three-pole reconnection.Once a certain reconnection cycle is started, a new cycle will only be permissible after an adjustableminimum time has passed, which will begin when the circuit breaker is opened.The protection to be provided shall be able to, as an option, only automatically reconnect when phase-earth internal short circuits occur.The synchro checking scheme must supervise the whole three-pole circuit breakers closing command,and consists of a synchro checking unit and by undervoltage and overvoltage units.

1.4.2.1.2 Three-pole reconnection schemeThe automatic three-pole reconnection schemes are exclusively for use after eliminating faults throughhigh-speed or instant protection facilities, and shall not be started when the circuit breakers are openedmanually, during operations with timed protection functions, faults in busbars and circuit breakers, whenreceiving a direct trip command from the remote terminal, overvoltage protection and trip protection dueto loss of synchronism and, whenever the case, protection systems for line reactors or transformers.Any of the transmission line terminals may be selected to be the first terminal to reconnection(LEADER), and shall be reconnection after downtime. The other terminal (FOLLOWER) shall bereconnection through a synchro checking relay. In order to select the terminal to be reconnection first,both terminals shall be equipped with reconnection schemes and synchro checking relays.The LEADER terminal shall only reconnection if there is no voltage on the line. The FOLLOWERterminal shall reconnection only after checking the synchro and there is a suitable voltage level on theside of the transmission line. The synchro checking relay shall monitor the angle and slip between thevoltages to be synchronized

1.4.2.1.3 Unipolar reconnection schemeThe automatic unipolar reconnection schemes are for use solely after eliminating phase-earth failuresthrough high-speed or instant protections.The said automatic reconnection schemes shall not be started by the same functions described in thepreceding item.The protection facilities shall be equipped with phase selection schemes suitable for each application inorder to provide unipolar opening for single-phase defects in the transmission line. When using remoteprotection facilities, the phase selection units used shall be independent from the start-up units andprotection measures.During the open-phase operating period imposed by the single-phase reconnection downtime, theovercurrent directional functions shall be blocked from the highly sensitive zero and negativesequences associated with remote protection schemes based on overreach logic, if required. Duringthis time, any trip command to the circuit breaker, as, for example, coming from the other phases, shallbe three-pole and not start the line reconnection.



1.4.2.1.4 Synchro checking relaysThe synchro checking relays used in the three-pole reconnection scheme shall permit the adjustment ofthe reconnection time, considering the time counted from opening the circuit breaker and including thetypical downtime for the relevant voltage class. Moreover, they shall enable adjustments of differencesin voltage, phase angle, difference in frequency and also permit the selection of the following conditionsto close the circuit breaker:• live busbar dead line;• dead busbar live line;• live busbar live line;• dead busbar dead line..

1.4.2.2 Main and Alternate Protection SystemsEach line terminal must be equipped with two independent sets of protection equipment: main andalternate protection, fully redundant, each providing full primary and backup protection, and bothadapted to protect the transmission line wherever it is installed, considering the use of a seriescompensation or otherwise.The primary protection equipment used in the main and alternate protection systems, must be able todetect and eliminate faults individually and independently, between phases and between a phase andearth for 100% of the length of the protected line, with no intentional time lags.The total time to eliminate all kinds of faults, including the opening time of the circuit breakers of allterminals in the line must be less than 100ms.The backup protection, which is part of the main and alternate protection systems, must be gradual,consisting of remote relays or functions included in the main/alternate protection against defectsbetween phases and earth-phase (21/21N), with at least three direction/direct protection zones and byneutral directional overcurrent relay (67N) with instant and timed units.The main and alternate protection equipment must permit the correct selection of the defective phasesin order to order the cut-off of the circuit breaker on a single or three-pole basis. It is forbidden to use aremote unit with zero sequence compensation to select phases.Should a remote relay protection system be used, it must have the following features andcharacteristics:• Metering elements to detect faults between phases and between phases and earth (21/21N), with

at last three direct zones and one reverse zone. The metering units shall have a maximumtemporary overreach of 5% for solid defects with a maximum exponential component.

• Remote protection must be complemented by using a neutral directional overcurrent protection(67N).

• Permit suitable elimination faults occurring during the energization of the transmission line, evenwhen the power supply to the protection system comes from a line pickup.

• Permit the blocking of remote units due to bulk power swings (68OSB).If the primary protection works on remote relays, it must be adapted to the following basic remoteprotection schemes by configuring its logic:• Permittive Underreach Trip Transfer (PUTT);• Permittive Overreach Trip Transfer (POTT);• Directional Comparison Block (DCB);• Direct Trip Transfer (DTT);



• Hybrid System (POTT, weak-infeed, echo ).

The remote protection systems shall meet the following requirements:• The selection of the remote protection logic to be adopted in each case should consider the effects

of the variations in the source impedances, length of the transmission line, existence of magneticcouplings with other transmission lines, taps on transmission lines and whether or not there is anyseries compensation.

• The neutral directional overcurrent protection system (67N) shall be included in the remoteprotection system used.

• For remote protection systems based on metering units adjusted in overreach, blocking logicshould be used in an incorrect operation during sequential fault elimination on parallel lines.

• Whenever necessary, the schemes should be equipped with echo and weak infeed logic.• Should a Direct Trip Transfer (DTT) scheme be used, measures should be adopted to permit the

remote cut-off of the circuit breaker in the event of any defect in a telecommunications channel(single-channel operation).

• Provision should be made for functional checking of all remote protection transmission andreception channels, regardless of the communications media used, with no risk of accidental cut-offnor need to switch off the transmission line.

For terminals connected to busbars in a ring or one-and-a-half circuit breaker layouts, logic systemsshould be provided to protect the stretch of the line that remains energized when the respectiveinsulation switch is open (line out of order), with the line circuit breaker(s) closed (stub bus).The protection system should be selected and able to detect and eliminate all kinds of faults along thetransmission line.The main and alternative protection systems should include a trip-switch scheme due to loss ofsynchronism (78).All transmission line terminals must be equipped with main and alternate protection systems forovervoltage (59) with instant and timed elements and independent adjustments, in a range of 1,1 1,6Vnom.The instant overvoltage protection facilities must operate only in dynamic events involving the threephases, and may not operate for operating overvoltages and surges where overvoltages are not foundsimultaneously in the three phases. The timed overvoltage protection must operate for sustainedovervoltages in any of the three phases.All transmission line terminals must have a synchro checking scheme to oversee the three-pole closingcommand for the circuit breakers.

1.4.3 Reactor protectionAll reactors shall be fitted with two independent protection schemes as well as the built-in protectionequipment (gas relay, trip valve, etc.):• Main protection scheme;• Backup protection scheme.

The total maximum time for eliminating internal faults in the reactor using the main protection schememust not exceed 100 ms, including the operating time of the protection relay, ancillary relays, the circuitbreaker opening time and the trip transfer time to the remote terminal.



The main protection system of the reactor must consist of a three-phase differential relay or 3 single-phase differential relays.It is recommended that differential protection use the TCs for each of the phases of the AT terminals,and the TCs for each of the phases of the neutral reactor terminals, providing protection against failuresbetween phases and between phases and earth.The backup protection against faults between phases must be performed by three overcurrent relayswith instant and timed elements (50/51) connected to the secondary windings of the TCs installed in theHigh Voltage terminals of the reactor and the fault protection between phase and earth should beperformed by the overcurrent relay with instant and timed elements (50N/51N) connected to thesecondary winding of the TC installed in the neutral reactor terminal.For reactors installed directly on the transmission line, all their protection equipment must work on thecircuit breakers of the terminal near the associated transmission line, and forward a direct trip transferto the remote terminal, blocking the closing of the local and remote circuit breakers.

1.4.4 Busbar protection system for the Tucuruí Disconnecting SS and Vila do Conde SSThe equipment and associated schemes required to integrate the new line input facilities shall beincluded in the differential busbar protection scheme existing in the Tucuruí Disconnecting Station andVila do Conde substations.Independent and dedicated current transformer cores shall be used for each differential protection. It isforbidden to use auxiliary TCs.Where there are busbar protection schemes with high-impedance relays, the magnetic characteristicsof the current transformers to be added must be identical to the that of the existing TCs

1.4.5 Circuit breaker failure protection systemAll the circuit breakers in the substation shall be protected by a circuit breaker fault protection scheme.The total time to eliminate faults using the protection scheme for circuit breaker failure must not exceed250 ms, including the operating times of the relays, auxiliary relays and opening of the circuit breakers.The circuit breaker failure protection system must control the opening of as few circuit breakers aspossible adjacent to the faulty circuit breaker and as many as possible to eliminate the fault, whennecessary transferring the direct trip to the circuit breaker of the remote terminal.At the existing substations, the circuit breaker failure protection system shall be dedicated and enableintegration with the existing circuit breaker failure protection schemes. The overcurrent sensors must beadjustable in the range of (0.1 2.0) x I n, with the timer in the 0 0.5s range..

1.4.6 Special Protection Systems

1.4.6.1 Emergency Control Scheme (ECS)The ECS shall be installed in the Emergency Control Units (ECU). The Emergency Control Units arespecific Digital Control Units (DCU) for processing the Emergency Control Scheme (ECS) of theELETRONORTE 500 kV grid.An ECS shall be allocated to each substation with 500 kV transmission lines. To install the ECS, theTRANSMISSION UTILITY shall use as many ECUs as necessary.The characteristics described below are specific to the ECS and shall be closely followed by theTRANSMISSION UTILITY:



• The ECUs shall be operating independently from the other units in the Supervision, Protection andControl System (SPCS) with regard to the performance of its operations. These units shall beconnected to the data highway (VDD) only for sending and receiving information that shall bedisplayed in the Supervision and Operation Units (SOU) of the substations and Operating centers;

• The ECS of the different substations shall be directly connected to each other and to the ECScurrently in the ELETRONORTE system. Each ECS shall be equipped with a minimum of five RS-232C standard serial gateways with an IEC-870-5-101 Communication Protocol encapsulated inTCP-IP;

• This connection shall be dedicated to the ECS feature and shall meet the following response timerequirements:- The maximum (total) time estimated to make a decision for an ECS of a given substation

due to the change in digital input and/or breaking the limits set for the supervised functionsoccurring in another substation, including the communication times, shall be less than orequal to 100 ms;

- The operating time in the same ECS (same substation) shall be less than or equal to 20ms;

• If the DCU proposed for the ECS is unable to perform the functions specified below, theTRANSMISSION UTILITY shall install as many as possible and the type required for protectionrelays to fulfill these functions. As mentioned herein above, these relays shall also be used solelyfor the ECS function and may not be shared with the SPCS

The following features shall be adopted by the ECUs:• Capacity directional feature:

- Three-phase or by phase operation;- Characteristic inverse time curve;- Possibility of inverting the directionality;- Easy setting for the operating point in terms of capacity (W) or current (A);- Fitted with independent outlets for alarm and cut-off with local and remote reconnection;- Interface with fiber optics.

• Undervoltage and Overvoltage feature (for busbars):- Operation per phase;- Defined time characteristics;- Continuous setting of function 27 in the 0.3-0.8 band of rated voltage and function 59 in

the 1.1-1.5 rated voltage band;- Accuracy better than 2%;- Pickup/drop out ratio higher than 0.98;- Interface with fiber optics.

• Underfrequency and overfrequency feature- Has four independent frequency stages;- Minimum setting band for each operating stage: from 50 to 70 Hz, adjustable at 0.01 Hz

intervals;- Accuracy of +/- 0.005 Hz of the adjusted value;- The units operation shall be blocked by an adjustable sub-voltage of 40% to 80% of the

rated voltage;- Each unit shall be provided with alarm and disconnection features;- This unit may only be operated after an assessment period of no less than 3 cycles, to



eliminate possible wrong operations due to the aperiodic component or other transitoryevents in the voltage wave;

- Maximum rearming time of this unit shall be 50 milliseconds;- Maximum error admissible for each timer will be +/- 5%;- Independent metering circuits and outlet for operating stages.-

1.4.6.2 Security Control Scheme (SCS)Tucuruí Disconnecting SS and Vila do Conde substation may be included in the Security ControlScheme (SCS) for the Power System of the South/Southeast/Mid-West/North/Northeast regions ofBrazil.The following data to connect the system to the CLP shall be provided:• Analog input:

- Flow of active power in all transmission lines, generators and transformers;- Voltage in all busbar sections.

• Digital input:- Status indication with two circuit breaker contact points, disconnecting switches, generator

cut-off selection switches (for power plants);- Indication of protection operations;









- Requirements that may require dedicated systems: High uptake rate information to detect isolation High uptake rate information to detect disturbances.



1.5.2.1 General requirementsThe Tucuruí-Vila do Conde 500kV transmission line, 2nd circuit, involves the installation of a set of itemsof equipment including line input facilities, among other items, in existing substations belonging toELETRONORTEConsequently, all equipment to be installed by the TRANSMISSION UTILITY must be supervisedlocally in line with the philosophy adopted by the company that owns the said substations. Thissupervision must be duly integrated in the Supervision and Control Digital Systems (SDSCs) to beinstalled by ELETRONORTE.The architecture and basic requirements of these Supervision and Control Digital Systems (SDSCs) areprescribed in the documents Characteristics and Basic Requirements of Facilities, referring to the Vilado Conde SS and Tucuruí Disconnecting SS.If the TRANSMISSION UTILITY system were to start up before the SDSCs of ELETRONORTE areinstalled, it shall be designed to operate independently with a plan for later integration in the SDSCs.In addition to local supervision, the power equipment must permit remote supervision by the followingOperation Centers:• Center of the utility that owns the Vila do Conde SS and Tucuruí Disconnecting SS

- Belém- COL-Belém Local Operating Center



• ONS Center:- North Regional Operation Center, COSR-N, in Brasilia-DF

Therefore, to meet the supervision and control requirements, the supervision systems will require to beinstalled in the facilities in order to:• Obtain information to enable the supervision and local control of the equipment to be installed;• Integrate, in the existing substations, with the Supervision and Control Digital Systems (SDSCs) to

be deployed by ELETRONORTE, for exchange of information;• Interconnect to the ONS Center, as stated in the item Requirements for Supervision and Control

by ONS and using the protocol IEC 870-5-104 or DNP 3.0.• Interconnect to COL-Belém, as mentioned in item Requirements for supervision by utility that

owns the substations. These interconnections must be made using the protocol already deployedtherein.

The protocols adopted for communicating with the operating centers (ONS and ELETRONORTE) mustbe configured in mutual agreement with said utilities.Moreover, this configuration must permit that said centers identify the operating status of theTRANSMISSION UTILITY supervision systems installed in the substations. This data will be modeledas status indications in the databases of those operating centers;Important Note:Should an operating center be introduced in the Notice of Tender herein known as a data concentrator,in the communication highway with any of the ELETRONORTE or ONS operating centers, theconfiguration of the protocol must permit that said centers identify the operating status of the dataconcentrator and, moreover, the data concentrator must be able to identify the operating status of allsystems hierarchically subordinate thereto and transfer such data to the corresponding centers, asapplicable.The TRANSMISSION UTILITY should bear the costs of modifying the metalwork and software as wellas the other services required for the existing Digital Supervision and Control Systems (SDSC) to einstalled by ELETRONORTE at the substations in order to permit full supervision of the electricalequipment through the existing man-machine interfaces (IHM) in the local control rooms at thesubstations. The quantity and types of points supervised shall be similar to those of the existingsystems.The TRANSMISSION UTILITY is also required to be responsible for installing and starting up theoperation of all equipment and systems required to facilitate the connection with the aforementionedoperating centers. As the interface between the TRANSMISSION UTILITY equipment and theaforementioned operating centers is required to be the digital input point of their communicationscomputers, this includes the installation of communication systems, modems and/or routers at all dataconnection terminals.As an alternative to installing new supervision and control resources, the TRANSMISSION UTILITYmay, by prior agreement with the companies that own the existing facilities, choose to expand theavailable supervision and control resources, provided all the requirements stipulated in the itemcaptioned Supervision and Control Systems (Sistemas de Supervisão e Controle) and TechnicalRequirements for the Telecommunications System to be Deployed (Requisitos Técnicos do Sistema deTelecomunicações a ser Implantado) are met.

1.5.2.2 List of information to be supervisedAs a general supervision and control requirement, all TRANSMISSION UTILITY equipment to beinstalled in the Tucuruí Disconnecting Station and Vila do Conde substations shall be supervised. The



data collected at said substations shall be transferred to the operating centers mentioned in the Noticeof Tender herein as specified below:(a) Telemetering



• The following measurements shall be collected and transferred to the operating centers:- Phase-phase voltage bay in kV in all line input facilities;- Active three-phase power in MW and reactive in MC/Ar in all line input facilities, measured

between the line and line reactor;- Phase current in amperes in all transmission line terminals;- Temperature of the windings and oil of each line reactor (per phase) in ºC;- Frequency in Hz of a phase on all busbars involved;


(b) Status indication



• The facility supervision and control systems must be able to respond to integrity sweepsundertaken by the centers connected thereto (ONS and ELETRONORTE) which may be cyclical,adjusting the period by parameters, typically every five minutes, or by event, such as rebooting thesupervision and control resources at the centers, or on request;






(c) Each acquisition and control unit (UAC) shall be fitted with an internal clock and calendar to informthe day, month, year, hour, minute, second and millisecond of each status variation meteringoperation. These inner clocks must be fitted with synchro circuits based on a signal with anabsolute date obtained from a GPS system to ensure that the supervision and control of the



various facilities is undertaken on the same time basis. The system shall be designed to achievebetter accuracy than one millisecond.


(e) ll control and supervision system information transferred to the operating centers of the utilitiesmentioned herein shall be raw data, as collected from the transducers or interleaving relays, that is,with no prior processing except when explicitly agreed on a case-by-case basis with one of saidutilities. In these cases, the quality indicators shall include at least the following:



(f) Information for sequencing events:


• Set of InformationThe information provided below and stored by the facilities supervision and control systemshall be transferred to COSR-N and COL-Belém, containing the instant when the event tookplace; while additional points may be included during the development of the final design

- Reactor:º 2nd stage oil overheating;º 2nd stage winding overheating;º 2nd stage gas protection;º Pressure blow valve;º Differential protection per phase;º Phase and neutral overcurrent coil protection;º Block relay operation.

- Transmission Line:º Main phase protection start-up by phase;º Main phase protection trip-switch;º Supplemental phase protection start-up per phase;º Supplemental phase protection trip-switch;º Main earth protection start-up per phase;º Main earth protection trip-switch;º Supplemental earth protection start-up per phase;º Supplemental earth protection trip-switch;



º Automatic reconnection start;º Circuit breaker fault scheme switch;º Overvoltage trip-switch;º Bulk power oscillation blocking;º Bulk power oscillation trip-switch;º Remote protection, block/release or permittive signal transmission;º Remote protection, trip transfer transmission;º Remote protection, receipt of block/release or remote permittive signal transmission;º Remote protection, transfer trip transfer receipt;º Faulty cutout blocking;º Switch-on time 2nd zone;º Switch-on time 3rd zone;º Switch-on time 4th zone;º Faulty cutout blocking;º Timed directional overcurrent;º Instant directional overcurrent;º Block relay switch-on.



- Digital Disturbance Metersº Start-up and failure

(g) Data age

• Maximum data age is understood to be the maximum time between the instant of the event of itsvalue in the facility (process) and its receipt at the ONS and ELETRONORTE operating centers.







(h) Dead BandDepending on the communications protocol adopted, the analog information may be reportedback on an exception basis to the operating centers mentioned herein. In these cases the valueadopted for the dead band used in the screening process must be agreed mutually between theutility that owns the center (ONS and ELETRONORTE) and the TRANSMISSION UTILITY. If noagreement is reached, the dead band value shall be 0 (zero).

1.5.3 Requisitos de supervisão pelo agente proprietário das subestaçõesThe TRANSMISSION UTILITY must provide the Operating Centers the utility that owns the existingsubstations with facilities for remote supervision of the equipment to be installed, pursuant to therequirements presented in the subitem entitled List of Information to be Supervised, applied inaccordance with the following criteria::• Supervision by the Local Belém Operating Center COL-Belém:

- Tucuruí Disconnecting Substation;- Vila do Conde Substation

The figure below offers a simplified overview of the supervision requirements for the substations(facilities) covered herein, through ELETRONORTE Operating centers. This is included merely as anillustration to offer a graphic overview of the requirements specified in the wording of the Notice ofTender herein.



Alternatively, the TRANSMISSION UTILITY may decide to connect the Centers of the utility that ownsthe substations (facilities) through one of the TRANSMISSION UTILITYs own operating center,provided the requirements described under Supervision and Control Systems herein are met. In theNotice of Tender herein, this center is generally called a data concentrator. In said case, the structureof centers shown in the preceding figure would be changed by inserting the data concentrator at ahierarchical level between the facilities and ELETRONORTE centers, therefore, included herein. Thefigure below illustrates a possible configuration.

COL Belém1

Key:1) Operating Centers used by the utilities that own substations:

COL Belém Belém local operating center

2) Supervision and control expansions in existing substations:PATC Supervision and control resources in the Tucuruí Disconnecting

substationPAVC Supervision and control resources in Vila do Conde substation

3) Supervision and control resources in ELETRONORTE substations.

PATC2 PAVC2

PAVC3


Existing resourcesPATC3



1.5.4 ONS supervision and control requirements

1.5.4.1 Basic requirements for equipment supervisionThe basic resources for supervising equipment that must be provided to ONS are described in the itemListed Information to be Supervised and cover:• Telemetering with 4 second scanning, which can be parameterized;• Status indicators reported by exception and with an integrity cycle, that can also be parameterized;• Sequence of events (SOE).

1.5.4.2 Requirements that may require dedicated systems

1.5.4.2.1 Information with a high acquisition rate for detecting confinementThe frequency measurements must be sent to COSR-N in Hz for each busbar relating to the line inputfacilities herein, acquired and transferred within a 200 ms period (a measurement for each substationinvolved).

1.5.4.2.2 High Uptake Rated Data for Disturbance DetectionThe kV measurement of the phase-phase bay of the 500 kV line of the Tucuruí Disconnecting Station

PATC PAVC


Existing resources

PAVC

COL Belém

Key:The following is used in addition to the acronyms in the precedingfigure:

CD Data concentrator, common name given to a supervision andcontrol system that is inserted between the facilities andELETRONORTE Centers.

PATC

CD1



and Vila do Conde substations must be sent to the COSR-N. Please note the high transfer rate of saiddata, which differs from the rate normally used for normal data uptake, which is typically four seconds.

1.5.4.3 Architecture of Interconnection with ONSSupervision and control is one of the mainstays of the real-time operation of the power system, andtoday in the Tucuruí and Vila do Conde region, is structured on a hierarchical system with supervisionand control systems installed in the following ONS operating centers:• North Regional Operating Center COSR-N;• National Power System Operation Center - CNOS.This structure is in a simplified form in the following figure just for illustration. The TRANSMISSIONUTILITY shall provide the data interconnections between the ONS operating center (except for CNOS)and each of the supervision systems of the substations involved.

Note in the above figure that the ONS between COSR-N, Tucuruí disconnecting

CNOS1

1) Operating centers used by ONSCNOS National Power SyCOSR-N North Regional O

2) Supervision and control expansa) PATC Supervisio

disconnecting substab) PAVC Supervision

substation.3) Supervision and control resourc

)

PATC2


COSR-N1

PATC³ PAVC³

Existing resources

PAVC2

Key::stem Operating Center;perating Center.

ion in existing substations:n and control resources in the Tucuruítion; and control resources in the Vila do Conde

es in existing substations

VOL. IV - Fl. 99 de 192

Centers figure are linked up through data interconnectionsand Vila do Conde substations.



Alternatively, the TRANSMISSION UTILITY may decide to interconnect the ONS COSR-N through oneof the TRANSMISSION UTILITYs own or outsourced operating center, provided the requirementsdescribed herein, in Supervision and Control Systems and Technical Requirements of theTelecommunication System to be Deployed are met.. In the Notice of Tender herein, this center isgenerally called a data concentrator. In said case, the structure of centers shown in the precedingfigure would be changed by inserting the data concentrator at a hierarchical level between the COSR-Nand ONS centers, therefore, included herein. The figure below illustrates a possible configuration

1.5.4.4 Equipment registration requirementsThe metering of all equipment to be opthe start-up. This data must include:• Descriptive parameters of Trans

pursuant to model π, and the malongitude of each facility and pylo

• Rated capacity in MVAr and ratebe used, such as capacitors, rea

• Provision of diagrams of operatio• Provision of the diagrams with th

each facility;

CNOS

The following is used in addition to thCD Data concentrator, name commbetween the facilities and the ONS ce


PATC

Existing resources

PATC

COSR-N

VOL. IV - Fl. 100 de 192

erated by ONS shall be sent thereto at least three months before

mission Lines, including series impedance and its susceptance,ximum current in amps, maximum power in MVA and latitude andns;d voltage in kV, of all static reactive support equipment that may

ctors, etc.,ns with the name of all equipment in each facility;e exact site of all metering points, remote signaling and control of

CD1

PAVC

Key:e acronyms of the preceding figure:only given to a supervision and control systemnters

PAVC



• All diagrams shall be issued on hard and soft copies, to an import and export standard to beagreed in advance between the TRANSMISSION UTILITY and ONS;

• A list, compatible with the supervision and control requirements herein of the metering, remotesignaling, control and SOE points that will travel through the interconnection (or interconnections)as the ONS supervision and control system, in a format compatible with the protocol adopted forthe interconnection and organized by SSCL/UTR and data concentrators, if used;

• In the event of direct data interconnections with UTRs, and if applicable, parameters that permit theconversion of the data sent to the Center to engineering values;

• Whenever applicable, top and bottom scale constraints for all supervised analog points.

1.5.5 Availability and quality assessment requirements

1.5.5.1 GeneralThe supervision and control resources provided by the TRANSMISSION UTILITY to meet therequirements herein shall have their availability and quality measured according to the concepts andguidelines established below.These resources will be assessed for each metering or control point, based on their availability/qualityseen by the centers mentioned herein. Thus, not only will the data collection equipment in the facilitiesbe assessed, but also all systems that are inserted between such equipment and the computer systemof the aforementioned centers, including the communication system and interfacing equipment with thecommunication computers (for example, modems).Assessment by a supervision and control resource will help observe not only telemetering and statusindicators but also the operating status of remote terminals, supervision and local control systems anddata concentrators, since the operating status of said equipment will be received by the Centers asstatus indicators.Moreover, aggregate indices will be calculated to give an overview of the availability and quality of thesupervision and control resources of the TRANSMISSION UTILITY.

1.5.5.2 Concept of Supervision and Control Resources AvailabilityAn item of information of any of the types specified herein is said to be unavailable for any of thecenters whenever:• The quality indicator received together with the information shows any abnormality, for example:

- Information deactivated at origin (facility);- Information invalid at origin;- Information not updated;

Notes:1) This case will be considered if the power equipment associated with the point is in repairor out of order due to operating requirements and the TRANSMISSION UTILITY uses one ofthese points, typically deactivated at origin to mark the fact.2) The manual quality points does not characterize an item of information as unavailable butrather of poor quality, as described in the item Concept of Quality of the Supervision andControl Resources.

• Analog information violates one of its respective scale restraints;• An item on status marker information is inconsistent.



All SOE points of a supervision and control system or remote terminal are said to be unavailable whenan event occurs that must trip the sequential meter and this is not done.A SOE point is said to be unavailable whenever it is not reported.All points subordinate to a supervision and control system of a facility will be said to be unavailablewhenever there is no response from said system to requests from the center(s) or data concentrator, ifused. Moreover, when using data concentrators, all points subordinate to the concentrator will be saidto be unavailable when it does not respond to the requests from any of the operating centers mentionedherein.Any point is said to be unavailable whenever it is under maintenance.

1.5.5.3 Quality concept of supervision and control resourcesAny information of any type specified herein is said to be violating the quality guidelines when:• The quality indicator marks information entered manually by the TRANSMISSION UTILITY

operator (if any);• It does not meet the data age requirement.• In the case of analog data, it does not meet the accuracy requirement;• In the case of time stamp data, it does not meet the accuracy requirement.

1.5.5.4 Indicators







Di = ( ( T - TIi ) / T ) X 100Where:







ΣTij





supervision network under center j responsibility.

1.5.5.4.3 Quality per supervision and control resource [Qi]Description:• Abbreviation: Qi


• Study period: Monthly• Unit of measurement: Percentage• Nature: Supervision and Control Systems• Aggregation: Monthly, per supervision and control resources and per operating center• Quality guideline: The acceptable minimum value is 97.5%, on a monthly basis;• Data required: As in equation• Equation:

Qi = ( ( Tq - Tnqi ) / Tq ) X 100Where:a) Qi : Quality rate of resource i;b) Tq: Total time in minutes for the study period;



c) Tnqi: Sum of the periods when point i does not comply with the concept of quality the whole timeTq.

1.5.5.4.4 Quality of the TRANSMISSION UTILITYs supervision and control resources [QRSj]Description:• Abbreviation: QRSj



ΣΣΣΣTqij QRSj = X 100

Tq X NPRSqjWhere:

- - Tq: Total time in minutes of the calculation period;- - Tqij: Sum of the periods when the resource i complied with the quality concept

during the total time Tq, when seen by center j;Note: Tqij = (Tq Tnqij)where:

- - Tnqij: Sum of the periods when point i does not comply with the quality concept duringthe total time, when seen by center j;

- - NPRSqj: Total number of the TRANSMISSION UTILITYs supervision and controlresources in the supervision network under responsibility of center j and may beassessed for quality.


Resource “k”


TC

100%

Resource “l” Resoruce “m”



98.5

97.5

VOL. IV - Fl. 104 de 192

ransmission resources seen byenter “j”



1.5.5.5 Analytical and assessment reports for the availability of the supervision and control resourcesThe operating centers that will receive the TRANSMISSION UTILITY data will assess the availabilityand quality of the supervision and control resources, issuing non-conformity reports in the followingsituations:• Any of the indicators specified is less in the month than the corresponding guideline set herein;• There is a loss of more than 30% of the supervision and control resources provided by the

TRANSMISSION UTILITY for a period of more than or equal to one hour;• During a major disturbance in the Basic Grid, one or more supervision and local control systems of

the TRANSMISSION UTILITY are out of order or loses the communication with some dataconcentrator of the TRANSMISSION UTILITY, if used.

Based on the aforementioned, there will be two types of reports:• Availability and Quality Assessment Report: issued whenever some availability and/or quality


1.5.5.6 Publishing the TRANSMISSION UTILITY availability, quality and action reportsThe final reports must be issued based on the reports written by the utilities who own the operatingcenters and after equating with the TRANSMISSION UTILITY, including, if applicable,recommendations for correction of any anomaly.Wherever the guidelines specified herein are not met, the Utility that owns the operating center willsend the reports to ANEEL for the appropriate measures to be taken, based on the prevailing laws andcontracts with the TRANSMISSION UTILITY.



Software must be provided for the data transfer, compaction/decompaction, conversion to standardformat COMTRADE (IEEE C37.111-1999) and remote communication interface, as well as software foradjusting and gauging the RDP.

The RDP must contain self-monitoring and ongoing self-diagnosis routines.The internal time of the RDP must be synchronized using a synchro device via satellite signal (GPS).







a) be configurable for current and voltage;b) have a delay time between any channels of less than 1 electrical level referring to 60 Hz;








1.5 s50 ms


2 In20 In




1.6.7 Occurrence metering capacity.The digital disturbance meter (RDP) must have sufficient memory to store the data covering at least 30



(thirty) disturbances lasting 5 (five) seconds each, should several consecutive defects trip the meter.The digital disturbance meter must be able to measure at least 160 ms of pre-failure data for eachfailure or disturbance and the post-failure time must be adjustable between 100 and 5000 ms.Metering a failure or disturbance must only be interrupted where the start-up sensors are non-operative, and after completion of the adjusted post-failure time.Should the sensor remain operative, the disturbance metering must continue until the sensor becomesnon-operative, including the meter for the post-failure time.Should a fresh disturbance occur prior to the completion of the metering time for an earlier disturbance,the meter must start a new metering period, not taking into account the time already passed for theprevious disturbance.




1.7 TECHNICAL REQUIREMENTS OF THE TELECOMMUNICATIONS SYSTEM TO BE DEPLOYED

1.7.1 General requirementsThe telecommunications for the expansion of the Tucuruí-Vila do Conde 500Kv transmission line, 2nd

circuit, shall provide for the operating and administration voice communications systems, as well asremote protection, power supervision and control, telecommunications supervision, emergency control,metering, billing and maintenance of the power transmission line between the substations involved andbetween the latter and the operation centers of the power system involved.The voice and data communications media shall meet the following requirements:• Availability equal to or greater than 99.7% measured for each 30-day period;• Provision should be made for digital circuits complying with the G.821 recommendations issued by

the International Telecommunication Union (ITU);• Analog equipment will be accepted only in cases where it is impossible to make new equipment

compatible with the existing infrastructure. In these cases, the following recommendations shall befollowed: CCIR 391, 392, 394, 395, 396 and 397, as well as the pertinent IEC recommendation;

• The requirements prescribed in IEC 834-1, 870-5 and 870-6 standards shall also be met for theremote protection system, where applicable.

The power system for all telecommunication equipment supplied shall have the followingcharacteristics:• Supervision unit and at least two rectification units;• Two groups of batteries meeting full power requirements for at least 12 hours sized to handle the

total load of all installed telecommunications equipment;• Should lead-acid batteries be used, the groups of batteries shall be housed in a special location,

apart from the other facilities and fitted with a gas exhaust system;• The rectification unit shall have the capacity to simultaneously feed the group of batteries being

charged and all telecommunication equipment with a sizing margin of 30%.

The telecommunication equipment shall be supervised at both the local and remote levels, and shallsound alarms in the facilities should there be any anomaly in the main telecommunication equipment,including the power supply equipment.The equipment must be fitted with remote supervision facilities, and permit remote management, withauto-diagnosis and configuration.The TRANSMISSION UTILITY will be liable for the full operational start-up of the communication links,with all infrastructure required to install the telecommunication system, on the basis of the provisions initem 5 of documents GTS-BTA-S/SE-001 and GTS-IBN-S/SE-001, such as: buildings, 48 Vcc directcurrent power supply for the telecommunication equipment that is able to provide power for at least 12hours, should the Alternating Current System fail, as well as any other infrastructure ranked asnecessary to ensure full performance of the telecommunications system.The TRANSMISSION UTILITY will be responsible for monitoring the voice and data channelsinterconnecting with the ONS and ELETRONORTE, whenever they request it.The purpose of these monitoring facilities is to measure performance indicators in order to check thatthe channels are operating in accordance with the minimum acceptable requirements. If anydiscrepancies are noted in the measurements obtained in relation to the recommended values, theTRANSMISSION UTILITY will agree to undertake corrective maintenance measures as required by thedeadline stipulated under common agreement with the ONS and ELETRONORTE.



Should it be necessary to schedule downtime for any data or voice channels of interest to the ONS andELETRONORTE, the TRANSMISSION UTILITY shall enter into understandings with the OperationsCenter of the ONS and ELETRONORTE to obtain approval for the service requested, at a convenientdate and time.Finally, when submitting the executive project, the TRANSMISSION UTILITY shall demonstrate fromthe calculations made that the communications architecture (configuration, number and capacity of thelinks, etc.) adopted complies with the requirements stipulated in the Notice of Tender herein.

1.7.2 Remote protection requirementsThe telecommunication equipment dedicated to remote protection functions must be designed for usein bulk power system facilities in order to recognize the presence of signals and/or frequencies thatidentify a command to the protection systems.The equipment must be fitted with test switches to permit intervention therein, without having todisconnect the transmission line.The remote protection facilities must maintain the operating reliability and security under adversesignal/noise conditions, and in case of a breakdown in the transmission line conductors (use of theunblocking logic).Independent, redundant telecommunication equipment shall be used for Main and Alternate ProtectionSystems, preferably using independent physical transmission facilities so that the non-availability of oneset of telecommunication facilities does not adversely affect the availability of the other. Each item ofcommunication equipment must be fitted with at least two communications channels. Consequently, thetransmission line protection system will have at least four remote protection channels each way, twoassociated with the primary protection system and two associated with the alternate protection system.The direct trip-switch transfer schemes for each protection system shall be implemented by using twocommunication channels for each of them, combined in series. The outlet points for the trip-switchtransfer receivers shall be connected in series, so that both units shall receive the signal beforeactivating the trip-switch command. The logic shall be designed in order to permit the system to betripped, even if contact is lost in one of the communication channels.The direct trip transfer channels will continue in ongoing operation when the block relays arefunctioning (failure in circuit breakers, faults in line reactors, and overvoltage protection systemoperative) and will function temporarily, when tripped by the line protection schemes. The receptionlogic shall be equipped with the means to identify trip transfer signals, distinguishing those for whichautomatic reconnection should be permitted from those where reconnection should not be permitted.For the remote protection schemes based on permittive overreach logic, one of the channels in eachprotection scheme shall be activated by the line protection overreach metering units. For remoteprotection schemes based on block signal directional comparison logic schemes, these channels will beactivated by the line protection reverse metering units. For remote protection schemes based onpermittive underreach logic, these channels will be activated by the line protection underreach meteringunits.The telecommunication channels shall be specific to the protection schemes and shall not be sharedwith any other applications, ensuring that the time between sending a signal from a insulator and itsreceipt in the opposite insulator is less than 15 ms.Provision shall be made to meter the sending and reception of signals associated with activating theremote protection system, in the event sequence registration system of the facility, in order to facilitateanalyses after the disturbance has occurred.



1.7.3 Voice channel requirementsThe TRANSMISSION UTILITY shall provide a communication system with two voice channels, with atleast one of them being direct; the other may be operated through a switched telephone system, bothfull duplex, with sound and visual signaling facilities for operating communications of the power systembetween:• The substations involved: Tucuruí Disconnecting Station and Vila do Conde;• Should the TRANSMISSION UTILITY decide to use its own or an outsourced local Operations

Center, channels shall be provided between this Center and:- Tucuruí Disconnecting Substation;- Vila do Conde Substation;- ONS North Regional Operations Center COSR-N;- ELETRONORTE COL Belém Operations Center.

• Should the TRANSMISSION UTILITY decide not to use either its own or an outsourced LocalOperations Center, the substations shall provide channels connecting them to the ONS andELETRONORTE Centers, as follows:- Tucuruí Disconnecting and Vila do Conde substations:

º Channels with the ONS North Regional Operations Center - COSR-N;º Channels with the Belém Local Operations Center COL Belém.

Moreover, a mobile communications system shall be provided to cover the entire length of thetransmission lines and substations involved, as support for the electrical and telecommunicationsmaintenance staff.

1.7.4 Data transmission requirementsThe data links specified below shall be sized (quantity of channels, velocity, use of alternative routes,etc.) in order to support the loads imposed by transfer of data and specified controls (see items 1.4, 1.5and 1.6) with the availability and quality ratings as described herein.

1.7.4.1 Supervision and control linksFor supervision and control by ONS and ELETRONORTE, the following redundant data links shall beprovided, preferably through alternative routes.• Should the TRANSMISSION UTILITY decide to use its own or outsourced Local Operations

Center:- Links with the Local Operations Center:

º Tucuruí Disconnecting Substation;º Vila do Conde Substation;º ONS North Regional Operations Center, COSR-N;º Belém Local Operations Center, COL Belém.

• Should the TRANSMISSION UTILITY decide to use a Local Operations Center:- Link with the North Regional Operations Center - COSR-N:

º Tucuruí Disconnecting Substation;º Vila do Conde Substation.



- Link with the Belém Local Operations Center, COL Belém:º Tucurui Disconnecting Substation;º Vila do Conde Substation.

These links shall be independent of any other data link.

1.7.4.2 Other data linksTwo phone extensions for DDR branch direct dialing shall be provided to obtain disturbance registrationdata.Alternative solutions permitting access through a data network may be acceptable, provided that atleast the same performance ratings are guaranteed as those attributed to the links specified above.



1.8 BASIC REQUIREMENTS FOR THE BASIC AND ALTERNATIVE CONFIGURATIONS

As indicated above the TRANSMISSION UTILITIES are not free to modify:• The sites of the Vila do Conde and Tucuruí Disconnecting Substations;• The voltage levels (only alternating current);• System flow distribution (effective impedance).On the other hand, as also indicated above, the TRANSMISSION UTILITIES are free to suggestalternative configurations, including:• Reactive values for the line reactors;• The parameters of the Transmission Line, provided that the requirements in the Annex 7B herein

are met.• Pylon configurations.Regardless of the proposed configuration, the TRANSMISSION UTILITIES shall perform at least thefollowing studies:• Bulk power flow, load rejection and energization at the basic frequency;• Temporary studies for reconnection, load rejection and energization.These studies shall demonstrate compliance with the provisions in the CCPE instructions documentand case study reports mentioned in item 2.1.1 as well as the following criteria and requirements.



Emergency operatingcondition(*)Rated Normal operating

condition Busbars withload

Other busbars

500 500 - 550 475 - 550 475 - 600

345 345 - 362 328 - 362 328 - 362

(*) 1-hour duration

1.8.2 Handling requirements associated with the transmission lines

1.8.2.1 Acceptable overvoltageThe maximum voltage for permanent and dynamic systems at the ends of the transmission lines afterhandling (energization, three-pole reconnection and load rejection) shall be compatible with thesupportability of the insulator substation equipment, line insulation and transmission pylons.



The dynamic voltage effective voltage between the phases at the instant immediately after operatingthe circuit breakers and the sustained voltage effective voltage between the phases in thesubsequent instants shall lie within the range of values given in Table 5.

Table 5 Effective voltage between phases acceptable at the end of the transmission lines afterhandling (kV)


It is acceptable for the overvoltage caused by transmission line energization handling and load rejectionto last for one hour.

1.8.2.2 Energization of transmission linesThe energization of the transmission lines shall be feasible in all situations assessed in the basicconfiguration, complying with the voltage criterion under normal operating conditions as defined in thetable.Specifically, provision shall be made for possible two-way energization, should the system reach thelevel of degradation at which this is feasible in the basic configuration.




0 5 1 1 2 2 3 3 4 4 5 5Arc current (Aef)

0

5

1

1

2





1.8.3 Opening and closing of the disconnecting and earth disconnecting devicesThis equipment shall meet the requirements of the applicable standards.

The opening and closing of the disconnecting and earth disconnecting devices shall take intoconsideration the induced resonant voltages of transmission lines in parallel, operating under normalconditions with maximum load or with single-phase defect. Any possible resonance induction caused bythe transmission lines that affect other existing parallel transmission lines shall also be checked andcorrected.

1.8.4 Circuit breaker cutout requirementsThe 500 kV circuit breakers shall be able to handle the following operations:• Idle line opening: with effective inter-phase voltage of 770 kV at a frequency of 66 Hz, without

relighting the arc. A frequency of less than 66 Hz will be acceptable provided that this is confirmedby system studies.





2 ENGINEERING AND PLANNING STUDIES FOR THE TUCURUÍ-VILA DO CONDE TRANSMISSIONLINE 2ND CIRCUIT AND TERMINAL SUBSTATIONS.

The Engineering and Planning Studies and documents drafted by ELETRONORTE and CCPE, for the500 kV transmission line and 500 kV substations, are listed below. Parts or all of them may be used, atthe discretion and full liability of the TRANSMISSION UTILITY.

2.1 ENGINEERING AND PLANNING STUDIES AND THE RELATED TECHNICAL DOCUMENTATION

2.1.1 Report

ANEELNo.

COMPANYNo. DOCUMENT

520 PTES-NT-1070/2000 Electromagnetic transitory studies for energization and reconnectionof the 500kV TLs: North-Northeast interconnection 3rd circuit andTucuruí-Vila do Conde TL 2nd circuit

521 PTES-NT-1.071/00 North-Northeast System Study update for choice of conductorcable and establishing type of structure to be used for the Tucuruí-Vila do Conde 2nd circuit

3 GTSB-01/82 andPPL-006/82July /82 -

Infeed to regions of Belém, Marabá, Tucuruí and Vila do CondePermanent Studies 1982/1987 Volume I.

4 GTSB-01/82(Annexes)July /82 -

Infeed to regions of Belém, Marabá, Tucuruí and Vila do CondePermanent Studies 1982/1987 Volume II.

5 TCU-80-2415-RE

March/83 -

Infeed to regions of Belém, Marabá, Tucuruí and Vila do CondePermanent Studies 1982/1987 Volume I.

6 TUC-80-2812 - RE(July/1986)

Checking need for Compact Circuit Transposition stretch: Vila doCondeTucuruí-Marabá-Imperatriz-Presidente Dutra.

7 PPL-RE-1.006/88Nov/88 -

Economic Feasibility Study for Second 500 kV TL Tucuruí/Vila doConde HEP.

8 EPL-RE-1.001/92May/92 Rer.1

Alternative Studies for Power Supply to the metropolitan regions ofBelém and Northeast Pará, including the 3rd Circuit route Vila doConde / Belém 230 kV - 1998/2007.

9 EPL-RE-1.004/94March/94 -

Feasibility Report Tucuruí / Vila do Conde 500 kV TransmissionLine - second circuit.

10 EPL-RE-1.003/95June/95 -

Reassessment of Economic Feasibility Report of Second Tucuruí/Vila do Conde Line 500 kV.

11 EPL-RE-1.002/96June/96 -

Economic Feasibility Study of Power Supply to Vila do Conde andDistribution to the Lower Tocantins Region, State of Pará (SecondTucuruí-Vila do Conde Line - 500 kV).



No.ANEEL

No.EMPRESA DOCUMENT

12 EPL-NT-1.017/94 North-Northeast System Study for Choice of Conductor Cable andDefining the Type of Structure to be Used for the Tucuruí Vila doConde 2nd Circuit.

13 MAR-81-1900 - LM 500 kV TL Tucuruí/Vila do Conde 2nd Circuit Materials Estimate.14 TUC-80-2417 - RE

(September/1983)Studies of Systems for use of Compact Pylons in 2nd Circuit 500 kVof ELETRONORTE.

15 TUC-80-2608 - RE(October/1983)

Power Studies for ELETRONORTE 2nd Circuit of 500 kV.

16 TUC-80-2609 - RE(September/1985)

Power studies for the hypothesis of a Compact Self-Portable Pylon500kV ELETRONORTE 2nd Circuit (Addendum to Report TUC-80-2608-RE).

17 TUC-80-2616 - RE(February/1986)

Check on Reduction in Minimum Distance Conductor/Side Structuredue to slope of insulator chains in the SS pylon In situation oftransit from compact pylon to conventional pylon, from the failurerisk viewpoint.

18 TUC-80-2810 - RE(April/1986)

Interconnection study of 500 kV with 2 (two) Circuits Resonance,Secondary Arc in Three-pole Opening and Earth Switches.

19 TUC-80-2812 - RE(July/1986)

Checking the need for Transposition of the compact Circuit stretch:Vila do Conde-Tucuruí-Marabá-Imperatriz-Presidente Dutra.

20 TUC-80-2618 - RE(July/1988)

Study of Energization and Reconnection at Natural Frequency 2circuits.

21 EPS-NT-1002/98(January/1999)

Assessment of need for busbar reactor input at Vila do Condesubstation.

2.2 SUBSTATION DOCUMENTS

2.2.1 VILA do CONDE SUBSTATION

ANEELNo.

ELETRONORTE No. DESCRIPTION

S1 TUC-093-56000 Vila do Conde Substation 500/230/69 kV Simplified DiagramS2 TUC-093-56110 Vila do Conde Substation 500/230/69 kV General Diagram

page ½S3 TUC-093-56110 Vila do Conde Substation 500/230/69 kV General Diagram

page 2/2S4 TUC-93-2521 Vila do Conde Substation 500/230/69 kV General Location Plan



ANEELNo.

COMPANY No. DESCRIPTION

S5 TUC-93-2522 Vila do Conde Substation 500/230/69 kV 500 kV Substation -General Plan

S6 TUC-93-2523 Vila do Conde Substation 500/230/69 kV 500 kV Substation -General Plan

S7 TUC-93-2537 Vila do Conde Substation 500/230/69 kV Relay Chamber501/502 Equipment location Plan

S8 TUC-93-2587 Vila do Conde Substation 500/230/69 kV Control room Equipment location Plan

S9 TUC-93-4042 Vila do Conde Substation 500/230/69 kV Electrical Cable Laying Plan



S12 TUC-93-4324 Vila do Conde Substation 500/230/69 kV Ancillary Services13800/460-60Hz General Diagram

S13 TUC-93-4331 Vila do Conde Substation 500/230/69 kV Ancillary Services 125Vcc General Diagram

S14 TUC-93-4347 Vila do Conde Substation 500/230/69 kV Earth Grid PlanPart of Page 3

S15 TUC-93-4349 Vila do Conde Substation 500/230/69 kV Earth Grid PlanPart of Page 1

S16 TUC-93-6005 Vila do Conde Substation 500/230/69 kV General Inside andOutside Drainage Network Plan

2.2.2 TUCURUÍ DISCONNECTING SUBSTATION

ANEELNo.


S17 TUC-091-02010 Location PlanS18 TUC-91-62123 500 kV Substation General PlanS19 TUC-91-62124 500 kV Substation General PlanS20 TUC-91-2516 500 kV Substation Physical Layout ProfilesS21 TUC-91-2522 Relay Chamber CR-503 Equipment locationS22 TUC-91-4003 Electrical Cable Laying and Panels PlanS23 TUC-91-4004 Electrical Cable Laying and Panels PlanS24 TUC-91-4321 Earth Grid PlanS25 TUC-91-4322 Earth Grid PlanS26 TUC-91-5801 Earthmoving Plan



ANEELNo.


S27 TUC-91-6005 General Internal Drainage Network PlanS28 TUC-91-4307 13.8KV Sector General DiagramS29 TUC-91-4304 Ancillary Services 13800/460V General DiagramS30 TUC-91-4310 Ancillary Services 125VccS31 TUC-91-4422 Ancillary Services 440/220V - General DiagramS32 TUC-091-56000 Sector 500/230 kV Simplified DiagramS33 TUC-091-56100 Substation %00KV General Diagram - 2S34 TUC-091-56101 Substation %00KV General Diagram - 1

2.3 TRANSMISSION LINE DOCUMENTS

ANEELNo.


1 Basic Design North-Northeast System Basic Design of 500kV TL Tucuruí/Vilado Conde 2nd Circuit Ver. 1 June/1998

2 Basic Design North-Northeast System Basic Design of 500kV TL Tucuruí/Vilado Conde 2nd Circuit Ver. 2 August/1998

(500 kV TL Tocantins MD Tucuruí (Pylon no.9)/Vila do Conde)

2.4 REPORTS

These Reports form an integral part of ANNEX 7B, and the recommendations should be adopted by theTRANSMISSION UTILITY when developing its projects and designs for implementation of the facilities.

ANEELNo

Nº COMPANY DOCUMENT

522 ELETRONORTEGTS-TUC-TUC/VDC II-001

Facilities - Characteristics and Basic RequirementsSubstation: Tucuruí –Disconnecting

523 ELETRONORTEGTS-VDC-TUC/VDC II-001

Facilities - Characteristics and Basic RequirementsSubstation: Marabá




3.1 GENERALThe TRANSMISSION UTILITY should implement GROUP B TRANSMISSION FACILITIES incompliance with Brazilian Law and the applicable environmental requirements applicable.

3.2 AVAILABLE DOCUMENTS

ANEEL No. COMPANY No. DESCRIPTION

24 039/98 Preliminary Environmental Report25 TUC-54-0301-RE Bibliographic Data Collection Environmental Studies for Transmission

System Associated to Tucuruí HEP Field Report.26 TUC-54-0112-PR Program for Field Survey and Appraisal: Atrophic, Biotype and Physical

environments.27 TUC-54-0109-RE

(5 volumes)Environmental Studies for the Transmission System relating to TucuruíHEP: Diagnosis Report on the Current Vegetation Status;Annex I Diagnosis Report Vila do Conde substation;Annex II - Diagnosis Report Tucuruí substation;Annex VIII Diagnosis Report Institutional aspects, Fauna, Atrophicenvironment, photos; andAnnex IX - Diagnosis Report Maps.

28 TUC-54-0113-RE Environmental Studies for the Transmission System relating to TucuruíHEP: Field Survey and Appraisal Report

29 S/N Environmental Studies for the Transmission Lines associated withTucuruí HEP: Annexes.

30 TUC-54-0102-PR Environmental Studies for the Transmission System relating to TucuruíHEP: Program of Flight over the Stretches of Interest, Site Inspectionsand Technical Meetings.

31 TCU-54-0101-PR Environmental Studies for the Transmission System relating to TucuruíHEP: Environmental Study Program for Circuits 1,2 and 3.

32 TCU-54-0401-RE Environmental Studies for the Transmission System relating to TucuruíHEP: Report on Flight over the Stretches of Interest, Site Inspectionsand Technical Meetings.

33 TUC-54-0104-PR Environmental Studies for the Transmission System relating to TucuruíHEP: Research program 01: Socioeconomic studies.

34 TCU-54-0105-PR Environmental Studies for the Transmission System relating to TucuruíHEP: Research program 02: Studies of Fauna.

35 TCU-54-0106-PR Environmental Studies for the Transmission System relating to TucuruíHEP: Research program 03: - Studies of Flora.

36 TCU-54-0202-RE Environmental Studies for the Transmission System relating to TucuruíHEP: Field company, contact persons and interviews.

37 TCU-54-0103-PR Environmental Studies for the Transmission System relating to TucuruíHEP: Bibliographic research program in Belém and São Luís.



ANEEL No. COMPANY No. DOCUMENT

38 TCU-54-0117-RE Environmental Studies for the Transmission System relating toTucuruí HEP: Environmental Impact Report - RIMA.

39 TCU-54-0114-RE Environmental Studies for the Transmission System relating toTucuruí HEP: Research program 03: - Studies of Flora.

40Not numbered(2 Volumes)

Environmental Control Report - October/98North/Northeast Power Transmission System.500 kV Tucuruí / Vila do Conde TL 2nd Circuit;Tucuruí substation - 500 kV; andVila do Conde substation - 500/230/69 kV.

41 Not numbered Costs of Tucuruí HEP and Associated Transmission System Rev. 1May/89



5 TIME-SCHEDULE

The TRANSMISSION UTILITY shall submit the deployment schedule for the TRANSMISSIONFACILITIES belonging to its concession, pursuant to models given in Table A and B of Annex 7B,indicating the intermediate benchmarks, for the following activities: environmental licensing, basicdesign, topography, work site, foundations, pylon erection, conductor cable laying and installation ofequipment, civil construction works and erection of transmission and substation facilities, andcommissioning, permitting monthly check on the progress of the works, to ensure the COMMERCIALOPERATION START-UP within 14 (fourteen) months.




COMPANY NAMEDATE

MONTHSNo DESCRIPTION OF INSTALLATION

STAGES 1 2 3 12 13 14


etc.2 ENVIRONMENTAL LICENSING

3 CIVIL WORKS AND ERECTION3.1 WORK SITE FACILITIES3.2 FOUNDATIONS3.3 PYLON ERECTION3.4 CABLE LAYING





SIGNATURE CREA No

ENGINEER REGION





DATE

MonthsNo.


1 DESIGNS2 PROCUREMENT2.12.22.32.43 CIVIL WORKS AND ERECTIONS3.1 Mobilization3.23.33.43.53.6 Commissioning4 ENERGIZATION4.1STARTING DATE COMMENTS:


SIGNATURE REGION



ANNEX 7CEXPANSION OF THE NORTH / NORTHEAST

INTERCONNECTION

BASIC TECHNICAL REQUIREMENTSAND CHARACTERISTICS

OF THE TRANSMISSION FACILITIES



CONTENTS

1 BASIC REQUIREMENTS FOR THE FACILITIES 72

1.1 INTRODUCTION ........................................................................................................................................................... 721.1.1 General Description 721.1.2 Basic Configuration of the North / Northeast Interconnection 721.1.3 System data used 741.1.4 General requirements 74

1.2 TRANSMISSION LINES.................................................................................................................................................... 761.2.1 Electrical Indicators 761.2.2 Mechanical indicators 781.2.3 Foundations 79

1.3 SUBSTATIONS ............................................................................................................................................................... 811.3.1 General requirements 811.3.2 Equipment requirements 82

1.4 SERIES COMPENSATION ................................................................................................................................................ 841.4.1 Basic information 841.4.2 Requirements for the varistors of the reactive series compensation equipment values 84

1.5 TECHNICAL REQUIREMENTS OF THE PROTECTION SYSTEMS............................................................................ 851.5.1 General 851.5.2 Transmission line protection 851.5.3 Reactor protection 881.5.4 Busbar protection for existing substations 891.5.5 Busbar Protection for the Açailândia Substation 891.5.6 Circuit breaker fault protection system 891.5.7 Special protection systems 90

1.6 SUPERVISION AND CONTROL SYSTEMS............................................................................................................. 921.6.1 Introduction 921.6.2 Supervision and control requirements of the facilities 92

1.7 TECHNICAL REQUIREMENTS OF DIGITAL OSCILLOGRAPHY SYSTEM ........................................................ 1071.7.1 General aspects 1071.7.2 Description of features 1071.7.3 Digital Disturbance Meter trip-switch 1081.7.4 Time Synchronization 1081.7.5 Electromagnetic compatibility requirements 1081.7.6 Characteristics of input and output signals 1081.7.7 Occurrence metering capacity. 1091.7.8 Communication requirements 110

1.8 TECHNICAL REQUIREMENTS OF THE TELECOMMUNICATIONS SYSTEM TO BE IMPLEMENTED.................... 1111.8.1 General requirements 1111.8.2 Remote protection requirements 1121.8.3 Voice channel requirements 113



1.8.4 Data transmission requirements 1131.9 BASIC REQUIREMENTS FOR THE BASIC AND ALTERNATIVE CONFIGURATIONS...................................... 115

1.9.1 Operating voltage 1151.9.2 Maneuvering requirements associated with the transmission lines 1151.9.3 Opening and closing of the disconnecting and earth disconnecting devices 1171.9.4 Circuit breaker cutout requirements 117

2 ENGINEERING AND PLANNING STUDIES FOR THE NORTH / NORTHEASTINTERCONNECTION - 500 KV AND 500 KV SUBSTATIONS BELONGING TO THEINTERCONNECTION 118

2.1 ENGINEERING AND PLANNING STUDIES AND RELATED TECHNICAL DOCUMENTATION FOR THENORTH/NORTHEAST INTERCONNECTION................................................................................................................... 118

2.1.1 Reports 1182.1.2 Electrical System Data Studies 118

2.2 REPORTS ON BASIC REQUIREMENTS AND CHARACTERISTICS ................................................................... 1182.3 ELETRONORTE SUBSTATION DOCUMENTS ..................................................................................................... 119

2.3.1 TUCURUÍ EXPANSION DISCONNECTING SUBSTATION 1192.3.2 MARABÁ SUBSTATION 1192.3.3 AÇAILÂNDIA SUBSTATION 1202.3.4 IMPERATRIZ SUBSTATION 1202.3.5 PRESIDENTE DUTRA SUBSTATION 121

2.4 TRANSMISSION LINE DOCUMENTS............................................................................................................................... 122


3.1 GENERAL................................................................................................................................................................. 123




5 TIME-SCHEDULE 126




1 BASIC REQUIREMENTS FOR THE FACILITIES

1.1 INTRODUCTION

1.1.1 General DescriptionThis Annex presents the basic technical requirements and characteristics of the transmission facilitiesforming part of the expansion of the North / Northeast Interconnection integrating the Tucuruí Expansion Disconnecting Substation and the Presidente Dutra Substation, constituting the third circuitof the existing North / Northeast Interconnection and strengthening the connections between theSouth/Southeast/Center-West and North/Northeast power systems.Figure 6 presents the electrogeographical map of the Brazilian power system, including the projectsassociated with the expansion of the North / Northeast Interconnection.The North / Northeast Interconnection consists of the implementation of the projects listed in subitem1.1.2, basically consisting of:• Third circuit 500 kV TucuruíMarabá;• 500 kV transmission lines MarabáAçailândiaPresidente Dutra.• 500 kV transmission line AçailândiaImperatriz.The implementation of the North / Northeast Interconnection covered by the Auction also consists of thereactive compensation associated with the circuits, and the terminal equipment for handling, protection,supervision and control, telecommunications and all other items of equipment, services and facilitiesrequired to render the public utility transmission service, even if not expressly listed in this Annex 7C.

1.1.2 Basic Configuration of the North / Northeast InterconnectionThe basic configuration consists of the projects listed in the following Tables. The transmission linesare listed in Table 1, while the substations are given in Table 2, not including the reserve units in thesequantities.

Table 1 500 kV transmission lines

Start Finish Circuit KmTucuruí Marabá 3rd 218Marabá Açailândia 251Açailândia Imperatriz 57Açailândia Presidente Dutra 398



Table 2 500 kV substations

Substation Voltage(kV) Main Projects Unit Capacity

(MVAr) (1)Tucuruí 500 1 line input facilities

1 Bus-bar interconnectionMarabá 500 2 line input facilities

1 Busbar interconnection3 single-phase line reactors1 series capacitor bank

33.3279

Açailândia 500 1 Substation yard3 line input facilities2 Bus-bar interconnections3 single-phase line reactors3 single-phase line reactors3 single-phase busbarreactors1 series capacitor bank1 series capacitor bank

33.36054.3315435

Imperatriz 500 1 line input facility

Presidente Dutra 500 1 line input facility1 Busbar Interconnection3 single-phase line reactors1 series capacitor bank

60435

Notes(1) The Unit Capacity of the reactors is referred to 500 kV.(2) For positioning the equipment, consult the diagrams available.

Figure 1 shows the final configuration of the North / Northeast Interconnection, with the transmissionsystem in question shown as a dotted line.In the basic configuration, the third circuit series compensation scheme consists of a bank of 279 MVAr(2300 A and 17.6 Ω) fixed series capacitors on the transmission line between Tucuruí and Marabáconstituting a total of 30% compensation, a bank of 315 MVAr (2300 A and 19.8Ω ) fixed seriescapacitors (CSF) on the transmission line between Marabá and Açailândia, making a total of 30%compensation, and two banks of 435 MVAr (2300 A and 27.4Ω ) fixed series capacitors (CSFs)corresponding to a total of 54% compensation of the transmission line between Açailândia andPresidente Dutra.The above-mentioned basic configuration and the technical requirements in this Annex 7C are theminimum performance standards for other solutions, which should be demonstrated throughdocumentary proof constituting technical justification.



1.1.3 System data usedThe system data used in the studies for the permanent, dynamic and temporary schemes drawn up todefine the basic configuration are made available, pursuant to the documentation listed in item 2.The data on the permanent and dynamic system studies are available in the format of the ANATEMand ANAREDE Network Simulation Digital Programs (CEPEL).The data on the temporary electromagnetic studies are available in the ATP digital program format.

Figure 1 Final configuration of the North / Northeast Interconnection

1.1.4 General requirementsThe design and construction of the transmission lines and the terminal substations should comply withthe latest revisions of the standards issued by the Brazilian Technical Standards Association (ABNT Associação Brasileira de Normas Técnicas), where applicable thereto, or with the latest revisions of theIEC, ANSI or NEC Standards, in this order of preference, unless expressly indicated otherwise.All local environmental conditions required for the preparation of the project, construction activities andoperation of the facilities should be obtained by the TRANSMISSION UTILITY.The TRANSMISSION UTILITY is assigned to the responsibility and prerogative of sizing and specifyingthe equipment and transmission facilities constituting the Public Utility Transmission Service covered bythis competitive bidding process, in order to comply with this Annex 7 and good engineering practices,as well as the market reservation policy.Figure 9 Electrogeographical map of the Brazilian Power System



Main Transmission Lines Configuration 2007.

DIRETORIA DE PLANEJAMENTO E ENGENHARIADEPARTAMENTO DE TRANSMISSÃO

BR-9807

1

2

3

4

5

COARACY NUNES

SANTANA

SANTARÉM

RURÓPOLISITAITUBA

ALTAMIRA

TUCURUÍ

V. CONDE

S.MARIA

SÃO LUÍS

UTINGA

MIRAMAR

TERESINA

B.ESPERANÇA

S.J.PIAUÍ

FORTALEZA

MOSSORÓ

AÇU NATAL

J.PESSOA

RECIFE

MACEIÓ

ARACAJU

SALVADOR

XINGÓIRECÊ

B.J.LAPA

EUNÁPOLIS

FUNIL

BARREIRAS

VITÓRIA

CAMPOS

RIO DE JANEIROC.PAULISTA

MASCARENHAS

SOBRADINHO

P.DUTRA

SERRA DA MESA

RONDONÓPOLIS

C.NOVOSP.FUNDO

IVAIPORÃ

70 MW

50 MW

5

4

31

2

S.QUEBRADA

MANAUS

BALBINA

RIO BRANCO ARIQUEMES

SAMUEL

JIPARANÁ

PORTO VELHO

ABUNÃ

P.BUENO

VILHENA

SINOPGURUPI

MIRACEMA

COLINAS

SORRISO

NOVA MUTUM

MANSOCUIABÁ

BARRA DO PEIXE

RIO VERDE

CORUMBÁ

C.GRANDE

GOIANIA MONTES CLAROS

T.MARIAS

J. FORA

CURITIBA

BLUMENAU

PORTO ALEGRE

ITÁ

F.AREIAITAIPU

S.OSÓRIO/S.CAXIASS.SANTIAGO

XANXERÊS.ROSA

DOURADOS

SÃO PAULO

MARABÁ

XINGUARA

REDENÇÃO

CANDIOTA

GARABISÃO BORJA

ALEGRETEURUGUAIANA

LIVRAMENTO

BRASÍLIA

BOA VISTA

STA ELENA

BELOHORIZONTE

GOV.MANG.

IMPERATRIZ

AÇAILÂNDIA

Eletrobrás

Principais Linhas de TransmissãoConfiguração 2007

+-

COMPLEXO RIO PARANÁ

COMPLEXO RIO PARANAPANEMA

COMPLEXO RIO GRANDE

COMPLEXO RIO PARANAÍBA

COMPLEXO PAULO AFONSO



1.2 TRANSMISSION LINES

1.2.1 Electrical Indicators

1.2.1.1 Electrical parameters for the transmission linesThe positive sequence longitudinal reactance of each stretch of the North / Northeast Expansion shouldallow the distribution of bulk power flows in the North / Northeast Interconnection similar to thereference alternatives given in the studies.

1.2.1.2 Loading the transmission linesThe transmission lines should be able to withstand the following load limits:

Transmission line Rated Load(A) 30mim EmergencyLoad (A)

10mim EmergencyLoad (A)

Tucuruí-Marabá 2300 3100 3600Marabá-Açailândia 2300 3100 3600Açailândia-P.Dutra 2300 3100 3600Açailândia-Imperatriz

2300 3100 3600

1.2.1.3 Definition of the maximum deflection of the conductors and sizing the lightning arrester cablesThe project design for locating the structures and sizing the lightning arrester cables for each stretch ofthe transmission line should adopt the following climate conditions:• Maximum average temperature for the region;• Maximum sunshine;• Wind of no more than 1 m/s.The definition of the maximum deflection of the conductor cables should comply with NBR-5422, takinginto account the maximum average temperature for the region, maximum sunshine, wind of no morethan 1 m/s, for a maximum current of 3,000 A.When sizing the lightning arrester cables, the same climate conditions should be taken intoconsideration as for the definition of the maximum deflection of the conductors, as well as the followingadditional conditions:• Short-circuit current levels of 40 kA at all substations, except in the Tucuruí Expansion

Disconnecting Substation which is 50 kA;• Possibility that the lightning arrester cables for stretches of the line are connected to the earthing

network of the substations and earthed at all structures;• Fault elimination time corresponding to the back-up protection.

1.2.1.4 Reactive compensationThe reactive compensation deriving from the basic configuration is given in Table 2.The reactive compensation deriving from the transmission lines should be defined in a manner wherebythe group formed by the lines and their compensations meets the requirements given in item 1.9 andthe other criteria in this Annex.The data, criteria and conditions needed for the analysis of the TRANSMISSION UTILITY are found inthe documents listed in item 2.



1.2.1.5 Joule loss in the lightning arrester and conductor cablesThe positive sequence resistance per length unit in the transmission lines for a rated frequency of 60Hz at a temperature of 75º C should be equal to or less than that of the basic configuration: 0.019Ω/km.The total loss of the lightning arrester cables should be no greater than that corresponding to twocontinuous galvanized steel Extra High Voltage cables with a diameter of 3/8, earthed at all structuresand in the substations earthing network.

1.2.1.6 ImbalanceThe transmission lines should have a complete transposition cycle, preferably with stretches measuring1/6, 1/3, 1/3 and 1/6 of the total length.


a) Performance in case of atmospheric dischargesNo disconnections may be caused by direct discharges due to the predominant terrain profile in thisregion.The number of disconnections caused by atmospheric discharges may not exceed one de-energization/ 100km / year.

b) Insulation at maximum operating voltageThe insulation of the transmission lines at the maximum operating voltage should be sized on the basisof the pollution characteristics of the region, as classified in Publication IEC 815 Guide for theselection of insulators in respect of polluted conditions.The minimum level of pollution adopted should be compatible with the minimum outflow distance of 25mm/kV for the maximum phase-earth voltage.The insulation of the transmission lines at maximum operating voltage should be sized taking thepollution characteristics of the region into account, according to the classification in Publication IEC815 Guide for the selection of insulators in respect of polluted conditions.The minimum pollution level adopted should be compatible with the minimum outflow distance of 25mm/kV , for the maximum phase-earth voltage.The insulation of the transmission lines at maximum operating voltage should be sized taking the swingof the chain of insulators into account, when blown by the wind, with a recurrence interval of at least 30years.A minimum distance should be maintained in order to avoid discharge at the maximum operatingvoltage between any line conductor and the edge of the right-of-way under the maximum deflection andswing conditions, as stipulated in NBR-5422.

c) Insulating maneuversThe maximum fault risk during energization and reconnection maneuvers should be limited to thefigures given in Table 3.

Table 1 maximum fault risk during energization and reconnection maneuversFault risk (adimensional)Maneuver Between phase and earth Between phases

Energization 10 – 3 10 – 4

Reconnection 10 – 2 10 – 3




a) Visual coronaThe transmission lines should not present a visual corona around the conductor cables and metalworkfor 90% of good weather conditions.

b) Radio interferenceThe signal/noise ratio at the edge of the right-of-way, indicating the level of immunity of the radiosignals (RI) should be at least equal to 24 dB based on the minimum signal level given in DENTELstandard for 50 % of the atmospheric conditions for the year.

c) Audible noiseThe audible noise (RA) at the edge of the right-of-way under the maximum operating voltage underconditions of drizzle (<0.00148 mm/min) or mist lasting 4 hours, or during the first 15 minutes of rainshould be equal to no more than 58 dBA.

d) Electrical fieldThe electrical field one meter away from the ground at the edge of the right-of-way should be 5 kV/m.The field inside the right-of-way should not cause any adverse effects on human beings, due to the useof each stretch thereof.

e) Magnetic fieldThe magnetic field under maximum loading factor conditions and at the edge of the right-of-way shouldbe less than or equal to 67 A/m, equivalent to magnetic conduction of 83 µT. The field inside the right-of-way should not cause any adverse effects on human beings, due to the use of each stretch thereof.


1.2.2.1 Basic conditions for the conductor cable regulation project.

a) Basic status• For minimum temperature conditions, the axial stress should be limited to 33% of the cable failure

stress.• For wind conditions with a recurrence interval of 50 years, the axial stress should be limited to 50%

of the cable failure stress.• For extreme wind conditions, the axial stress should be limited to 70% of the tensile stress of the

cable.b) Normal stress status (EDS)

For the final positioning, at the average temperature with no wind, with the stress level complyingwith the figures given in NBR-5422 Standard (March 1985).

c) Reference statusThe minimum conductor cable clearance from the ground will not take wind pressure into

consideration.1.2.2.2 Mechanical design criteria

For the mechanical design of the transmission line supports, the loading factors caused by the action ofthe wind on the physical components of the line should be established on the basis of probabilistic



characterizations of wind-speeds in the region, treated differently by type: Extended Pressure Systems(EPS) and Thunderstorms (TS).For the wind gauging stations covered in the study, the following parameters should be defined:• Average and variation coefficient (percentage) of the maximum annual wind-speed series at a


average integration times of 3 seconds and 10 minutes. If the number of years in the wind-speeddata series is low, the estimate of the annual maximum wind speed should be based on at least avariation coefficient compatible with the longest wind-speed series measured in the region;



The mechanical design of the transmission line should be prepared in compliance with IEC 826 International Electrotechnical Commission: Loading and Strength of Overhead Transmission Lines.In addition to the hypotheses covered in the IEC Standard, it is also mandatory to introduce loadinghypotheses that reflect Thunderstorms (TS).The electromechanical design of the transmission line should comply with the level of reliabilitycorresponding to a recurrence interval equal or greater than 250 years, referred to an intermediate levelat 2 and 3 stipulated in IEC 826.


1.2.3 FoundationsThe foundations for each structure should be designed structurally and geotechnically in such a way asto ensure all stresses on each pylon are aligned to the specific conditions of its foundation.The loads on the foundations should be calculated for each structure individually under real loadingsituations, taking into account their specific application conditions: Deadweight Span Stress, Wind SpanStress, Transmission Line Connection Point and Deflection Angle, and Pylon height.The physical and mechanical properties of the foundation soil for each structure should be determinedin an accepted scientific manner, accurately portraying the geomechanical parameters of the soil, withthe following stages being implemented:• Preliminary physiographic study and analysis of the route of the transmission line with a



the project.



When calculating the foundations, regional geomorphological aspects should be taken intoconsideration that influence the state of the foundation soil, whether in terms of sensitivity, or propensityto expand or collapse, taking seasonal factors into account.The definition of the type of foundation, as well as its structural and geotechnical sizing should beundertaken while taking into consideration the cracking and skewing limits for the soil support capacityand resistance to compression, dragging and horizontal effects, through the use of rational calculationmethods that are not open to query and generally accepted in geotechnical engineering.



1.3 SUBSTATIONS


1.3.1.1 Basic informationThe TRANSMISSION UTILITY should prepare and present the studies required to define thecharacteristics and performance levels for all items of equipment, taking into account that they will beconnected to the existing system.All items of equipment should be specified in a way that does not adversely affect or limit the operationsof the substations, nor impose operating constraints on the other facilities in the interconnected system.Neither should equipment be used that prevents the use of apparatus based on other existingtechnologies or other supplies or future expansions.The new facilities should be compatible with the existing substations and other aspects of theequipment requirements. The basic requirements and criteria should be complied with for the existingequipment and facilities at the existing substations as specified in the following available documents:GTS-TUC-N/NE III-001, GTS-MAB-N/NE III-001, GTS-IPZ-N/NE III-001 and GTS-PDD-N/NE III-001.At the existing substations, the basic configuration includes equipment with basic electricalcharacteristics similar to the existing equipment, which are presented in the above-mentioneddocuments.

1.3.1.2 Yard arrangementsThe arrangement used in the existing 500 kV substation yard consists of the circuit breaker and a halftype, which should also be used in the new Açailandia Substation. Physical space should be set asidefor installing the reactor handling equipment.For the final horizon of the Açailândia Substation, the use of a further 4 (four) line input facilities isplanned, in addition to the 3(three) used in the implementation phase, as shown in Drawing MAR-101-56000 500kV Sector Simplified Diagram.

1.3.1.3 Current capacity

a) Current on permanent basisThe sizing of the busbars and other equipment should take into account the maximum current value forthe permanent operating condition of 3150 A.

b) Short-circuit capacityThe equipment and other facilities should be able to withstand the short-circuit level of 40 kA in the 500kV busbars, except for the Tucuruí Expansion Disconnecting Substation which is 50 kA.

c) Earthing System.The earthing system for the substations should comply with the criteria for a solidly earthed system.

1.3.1.4 Supportability

a) Voltage on permanent basisThe sizing of the busbars and the equipment should take into account the maximum voltage value of550 kV for the operating condition on a permanent basis.



b) Insulation under pollutionThe facilities should be insulated in order to deal with the pollution characteristics of the region undermaximum operating voltage, according to the classification given in Publication IEC 815 Guide for theSelection of Insulators in Respect of Polluted Conditions.

c) Protection against atmospheric dischargesThe protection system against atmospheric discharges for the substations should ensure perfectshielding of the facilities for currents of over 2 kA, and ensure a defect risk of less than or equal to onedischarge each 50 years.Should there be any buildings, they should comply with the requirements of Technical StandardNBR5419.

1.3.1.5 Field effects

a) Corona effectThe components of the substations, particularly the conductors and metalwork should not present acorona effect at 90 % of good weather conditions. The minimum tension for the start and end of thevisual corona should be 350 kV, for the 500 kV yards. The corona elimination voltage should be locatedabove the maximum operating voltage.

b) Radio interferenceThe maximum external radio interference voltage value for the equipment should be 2,500 µV/m at1000Hz, at the phase-earth voltage 550/√3kV and 362/√3kV.


1.3.2.1 ReactorsThe reactor windings should be interconnected in a star formation with the neutral accessible for solidearthing by reactors or resistors.The insulation of the neutral should be sized for connection with neutral reactors in order to allowunipolar reconnection and eliminate parallel circuit resonance.The magnetization curve should be linear up to a voltage of 750kV.The values for the total losses (losses in the copper plus losses in the iron) referred to a voltage of 550kV and the rated power capacity should be less than 0.3 % of the rated power capacity.

1.3.2.2 Circuit BreakersThe fast reconnection and operating cycle of the circuit breakers should meet the requirements in thestandards applicable thereto.The maximum downtime for the 500 kV and 345 kV circuit breakers should be 2 (two) cycles.The 500 kV and 345 kV circuit breakers should be able to undertake the maneuvering operations listedin item 1.9.4.The 500 kV and 345 kV circuit breakers should have two independent trip-switch logic circuits for polediscrepancy detection, with triple-pole and unipolar drives, as well as an operating cycle compatiblewith the use of automatic single-try triple-pole and unipolar reconnection schemes.

1.3.2.3 Disconnecting switches, earthing plates and earthing switches



This equipment should meet the requirements in the standards applicable thereto and be able to handlethe maneuvers listed in item 1.9.3.The earthing plates and earthing switches for the transmission lines should be fitted with the inducedcurrent breaker capacity in compliance with class B of the IEC 1129 standard.

1.3.2.4 Lightning arrestersThe lightning arresters should be station-type, zinc oxide (ZnO), appropriate for outside installation andwith no spark gap. The use of lightning arresters should be planned at the interface with the existingsystem (line input facility).

1.3.2.5 Current and Power TransformersThe characteristics of the current and power transformers such as: number of secondaries,transformation ratios, load, accuracy, etc., should meet the needs of the protection and meteringsystems.The current transformers should have secondary windings in individual cores, and be appropriate foroutside installation.The bulk power transformers should be capacitative, and be appropriate for outside installation.

1.3.2.6 Indoor facilitiesAll instruments, panels and other items of equipment in the protection, command, supervision andtelecommunication systems should be sheltered and designed according to the standards applicablethereto, in order to ensure flawless performance of these systems in their protection against prematurewear and tear.In case of buildings, the TRANSMISSION UTILITY is responsible for complying with the municipalstandards applicable thereto as well as labor safety standards.



1.4 SERIES COMPENSATION

1.4.1 Basic informationThe existing system is equipped with fixed-series capacitors (CSFs), whose main electricalcharacteristics are shown in Table 19. A location of the reactive series compensation of the North-Northeast Interconnection is given in Figure 1The technical specifications of the existing series compensation equipment will be made available whenrequested by the TRANSMISSION UTILITY.The protection and control system for the associated equipment considers the occurrence of two typesof defects, namely:• Internal defect shown in Figure 3• External defect.

Figure 3 Internal defect

1.4.2 Requirements for the varistors of the reactive series compensation equipment valuesAll the varistors in the reactive series compensation equipment should be based on metal oxide.The energy requirements of the varistors should be defined taking into consideration all the forecastscenarios and exchanges, from the initial configuration through to the planning horizon years. Theserequirements should be defined by the TRANSMISSION UTILITY for the most critical external faultcondition, noted with the parallel line out of service.The varistor protection devices may be tripped under the following situations:Three-phase, two-phase or single-phase internal faults;External fault eliminated over more than 100 ms, three-phase, two-phase or single-phase;Three-phase external faults eliminated over 100 ms with unsuccessful reconnection of only one terminal,

resulting in higher energy for the varistor under calculation, occurring over 600 ms and the openingof this terminal at 700 ms. (Times referred to the instant of occurrence of the fault).

Table 4 Main electrical characteristics of the existing series compensation on the North / Northeast Interconnection

Overcharge (pu)Bank Xc

(Ω)RatedCurrent (A) 8 h 30

min 10 s

VaristorEnergy(MJ/phase)

Ulim(pu)

Series Spark-GapTrip Delay(ms)

C1 21.9 2300 --- 1.35 2.0 21.2 2.60 1.6

C2 17.8 2300 --- 1.35 2.0 30.4 2.60 1.2

C3 and C5 34.2 1950 --- 1.35 2.0 29 2.72 1.0

C4 and C6 28.6 2300 --- 1.35 2.0 19.3 2.56 0.3

Internal faults = faults in the linecompensated by the bank.



1.5 TECHNICAL REQUIREMENTS OF THE PROTECTION SYSTEMS

1.5.1 GeneralAll the protection relays should use numerical digital technology.The protection systems should be integrated at the installation level allowing local and remote accessfor adjustment, recording events, size of input and other pertinent information for each of the protectionrelays or systems. The architecture and protocols used should not impose constraints on the integrationof new equipment, nor the operation of the facilities.All digital equipment and systems should be self-monitored and have self-diagnosis facilities, withautomatic blockage of operations in case of defect, with local and remote indications of any fault ordefect.All protection systems should accept a fault or defect in a component, without this resulting in thedegradation of its end-performance.The current transformers should be arranged in the facility in a way that allows overlapping protectionzones for adjacent primary items of equipment.The equipment protection should be designed in a way that does not depend on remote back-upprotection for the transmission system.The main and (alternate or back-up) protection systems should be powered by independent banks ofbatteries, rectifiers and continuous current circuits.The protection systems should be fitted with outlets for operating two circuit breakers with independenttrip-switches as well as for unipolar and/or triple-pole start-up switches.The current and voltage information for each protection system, whether main, alternate or backup,should be obtained from the current transformer cores and secondary transformers with differentcapacities.All the protection systems and associated equipment should comply with the electromagneticcompatibility standards applicable thereto at the levels of severity appropriate to installation in extra-high voltage substations.The protection systems should comply with the existing requirements in terms of sensitivity, selectivity,speed and operating reliability, in order to avoid downgrading the performance of the power systemunder operating conditions or during disturbances.

1.5.2 Transmission line protectionThe set of equipment and accessories required as being sufficient to detect and eliminate all types ofdefects and other abnormal operating conditions for the transmission lines, distinguishing betweeninternal and external faults on the protected line..

1.5.2.1 Reconnection schemesThe transmission lines should be equipped with reconnection schemes according to the philosophydefined below:

1.5.2.1.1 General requirementsThe reconnection scheme should allow the selection of the type and number of reconnection attemptswith two possibilities: triple-pole and unipolar. In the triple-pole position, any start-up order launched bythe protection system will switch off the three poles of the circuit breaker and begin triple-pole



reconnection. In the unipolar position, in case of a phase-earth defect, the disconnection and thereconnection of the two line terminals should be unipolar; for other types of short circuit, thedisconnection and the reconnection should be triple-pole. Should the reconnection cycle beunsuccessful (for instance, permanent short circuits) the disconnection will be triple-pole.In substations with a ring arrangement, double busbar with double circuit breaker or circuit breaker anda half, provision should be made for the possibility of reconnection through either of the two circuitbreakers associated with the line. The placement or removal of the service, the selection of the type ofreconnection and the circuit breaker to be reconnected should be handled through a selection switchand/or the supervision and control system for the substation.The reconnection relays should be fitted with independent timers with the possibility of adjusting thedowntime for unipolar and triple-pole reconnection.Once a specific reconnection cycle has begun, a new cycle will only be allowed after a minimumadjustable period that will start with the opening of the circuit breaker,The protection to be supplied should offer facilities for optionally undertaking automatic reconnectiononly in case of internal phase-earth short circuits.The synchronism verification scheme should supervise all triple-pole closing commands for the circuitbreakers, consisting of a synchronism checking unit and under-voltage and overvoltage units.

1.5.2.1.2 Triple-pole reconnection schemeThe automatic triple-pole reconnection schemes are for use only after elimination of faults by high-speed or instantaneous protection facilities, and should not be undertaken through manually openedcircuit breakers, during timed protection function operations, defects in busbars, defects in circuitbreakers, receipt of start-up commands directly from the remote terminal, overvoltage protection andstart-up protection due to loss of synchronism, as well as the transformer or line reactor protectionsystems.Either of the transmission line terminals may be selected as the first terminal to be switched on(LEADER) and should be reconnected after the down time. The other terminal (FOLLOWER) should beswitched on after a synchronism-checking relay. In order to select the terminal to be reconnected first,both the terminals should be fitted with reconnection systems and synchronism checking relays.The LEADER terminal should be reconnected only if there is no voltage on the line. The FOLLOWERterminal should be reconnected only after checking synchronism and with an adequate voltage level onthe transmission line side. The synchronism-checking relay should monitor the angle and flow betweenthe voltages to be synchronized.

1.5.2.1.3 Unipolar reconnection schemeThe automatic unipolar reconnection schemes are for use only after the elimination of earth-phasedefects through high-speed or instantaneous protection facilities. These automatic reconnectionschemes should not be tripped by the same functions described in the previous item.The protection facilities should be equipped with phase selection schemes appropriate for eachapplication in order to undertake unipolar opening for single-phase defects on the transmission lines.Should remote protection facilities be used, the phase selection units used should be independent ofthe start-up units and protection measures.During the open-phase operations period required by the unipolar reconnection down-time, theovercurrent directional functions should be blocked for the high-sensitivity zero and negative sequencesassociated with remote protection schemes based on overreach logic, if necessary. During this period



of time, any start-up order sent to the circuit breaker, coming from other phases, for instance, should betriple-pole and should not start up the reconnection of the line.

1.5.2.1.4 Synchronism checking relaysThe synchronism checking relays used in the triple-pole reconnection schemes should allowadjustment of the reconnection time, taken as from the opening of the circuit breaker and including thetypical downtime for the respective voltage class. Additionally, this should allow adjustments ofdifferences in voltage, angular phase shift, different frequencies and also allow the selection of thefollowing conditions for closing the circuit breaker:• Live busbar dead line,• Dead busbar live line,• Live busbar live line,• Dead busbar dead line.

1.5.2.2 Main and Alternate Protection SystemsEach line terminal should be fitted with two independent sets of protection equipment: main protectionand alternate protection, fully redundant, each providing full primary and backup protection and bothable to protect the transmission line on which they are installed, whether or not series compensation isused.The primary protection equipment used in the main and alternate protection systems should be able todetect and eliminate faults individually and independently between phases and between phase andearth for 100% of the length of the protected line, with no intentional time lags.The total elimination time for all types of faults, including the circuit breaker opening time for all the lineterminals should not exceed 100 ms.The backup protection constituting part of the main and alternate protection systems should be phasedin, consisting of remote relays or functions included in the main/alternate protection schemes fordefects between phases and earth-phase (21/21N), with at least three direction/direct protection zonesand through neutral directional overcurrent relay (67N) with instant and timed units.The main and alternate protection equipment should allow the correct selection of the defective phasesto order the disconnection of the circuit breaker on either a single- or triple-pole basis. The use ofremote units with zero sequence compensation is banned for phase selection.Should remote relay protection systems be used, they should be endowed with the following functionsand characteristics:• Metering elements to detect faults between phases and between phases and earth (21/21N), with

at least three direct zones and one reverse zone. The metering units should have a maximumtransitory overreach of 5% for solid defects with maximum exponential component.

• The remote protection systems should be supplemented through the use of neutral directionalovercurrent protection (67N).

• Allow adequate elimination of faults to take place during the energization of the transmission line,even when the power supply to the protection system comes from a line pickup.

• Allow remote unit blocking due to bulk power capacity swings (680SB).If the primary protection system works on remote relays, it should run the following basic remoteprotection schemes through the configuration of its logic:• Permittive Underreach Trip Transfer (PUTT);• Permittive Overreach Trip Transfer (POTT);



• Directional Comparison Block (DCB).• Direct Trip Transfer (DTT).• Hybrid System (POTT, weak-infeed, echo)

The remote protection systems should comply with the following requirements:

• The selection of the remote protection logic to be adopted in each case should take into accountthe effects of the variations in the source impedances, the length of the transmission line, theexistence of magnetic couplings with other transmission lines, taps on the transmission lines andwhether or not there is any series compensation.

• The neutral directional overcurrent protection system (67N) should be incorporated into the remoteprotection system used.

• For remote protection schemes based on metering units adjusted at overreach, improperoperations block logic should be used during sequential fault elimination on parallel lines.

• When necessary, the schemes should be equipped with echo and weak in-feed logic.• Should a direct Trip Transfer (DTT) scheme be used, measures should be applied allowing the

remote disconnection of the circuit breaker in case of any defect in a telecommunications channel(single-channel operation).

• Provision should be made for functional checking of all remote protection transmission andreception channels regardless of the communications media used, with no risk of accidentaldisconnection and with no need to switch off the transmission line.

For terminals connected to busbars with ring or circuit breaker and a half arrangements, logic systemsshould be provided to protect the stretch of the line that remains energized when the respectiveinsulation switch is open (line out of service), with the line circuit breaker(s) closed (stub bus).The protection system should be selected and able to detect and eliminate all types of faults along thetransmission line.The main and alternative protection systems should include a trip-switch scheme due to loss ofsynchronism (78).All transmission line terminals should be equipped with the main and alternate protection systems forovervoltages (59) with instant and timed elements allowing independent adjustments, and a range of1.1 1.6 Vnom.The instant overvoltage protection facilities should operate only for dynamic events involving the threephases, and may not operate for overvoltages during maneuvers and surges where overvoltages arenot noted simultaneously in the three phases. The timed overvoltage protection should operate forsustained overvoltages at any of the three phases.All transmission line terminals should be fitted with synchronism checking schemes to supervise thetriple-pole closing command for the circuit breakers.

1.5.3 Reactor protectionIn addition to the built-in protection equipment (gas relay, trip valve, etc.) all reactors should be fittedwith two independent protection schemes:• Main protection scheme;• Backup protection scheme.



The maximum total time for the elimination of internal faults in the reactor by the main protectionscheme may not exceed 100 ms, including the protection relay operation time as well as the auxiliaryrelays and the circuit breaker opening time and the Trip Transfer time to the remote terminal.The main protection system of the reactor should consist of a three-phase differential relay or 3 single-phase differential relays.The differential protection should use the CTs for each of the phases of the High Voltage terminals, andthe CTs for each of the phases of the reactor neutral terminals, providing protection for faults betweenphases and between phases and the earth.The backup protection for the faults between phases should be handled by three overcurrent relayswith instant and timed elements (50/51) connected to the secondaries of the CTs installed at the HighVoltage terminals of the reactor and the fault protection between phase and earth should be handled bythe overcurrent relay with instant and timed element (50N/51N) connected to the secondary of the CTinstalled in the reactor neutral terminal.For reactors installed directly on the transmission line, all their protection equipment should work on thecircuit breakers of the next terminal on the associated transmission line, and should forward the directstart-up transfer to the remote terminal, blocking the closing of the local and remote circuit breakers.

1.5.4 Busbar protection for existing substationsEquipment and the associated schemes should be planned as required to integrate the new line inputfacilities with the existing differential busbar protection scheme at the following DisconnectingSubstations: Tucuruí Expansion Disconnecting, Marabá, Imperatriz and Presidente Dutra.Independent dedicated current transformer cores should be used for each differential protection, withthe use of auxiliary TCs being banned.Where there are existing busbar protection facilities with high impedance relays, the magneticcharacteristics of the TCs to be added should be identical to those of the existing CTs.

1.5.5 Busbar Protection for the Açailândia SubstationThis consists of the set of equipment and accessories needed and sufficient to detect and eliminate alltypes of faults in the substation busbars.The total elimination time for all types of defects in the busbars should not be greater than 100 msincluding the busbar protection relay operation time, the auxiliary relays and the circuit breaker openingtime.Each busbar on the facility should be fitted with a protection system consisting of busbar protection(87B) fed by secondaries independent of the current transformers.The busbar protection system should be stable (not operate) for faults outside the busbars, even incase of saturation of the current transformers.The busbar protection system should not operate improperly should the secondary current transformercircuit be opened.

1.5.6 Circuit breaker fault protection systemAll the circuit breakers in the substation should be protected by a circuit breaker fault protectionscheme.



The total time for the elimination of faults by the protection scheme for defective circuit breakers shouldnot exceed 250 ms, including the operation times for the relays, the auxiliary relays and the opening ofthe circuit breakers.The fault protection for the system for the circuit breakers should control the opening of the smallestnumber of circuit breakers adjacent to the faulty circuit breaker sufficient to eliminate the fault, whennecessary transferring the direct start-up to the circuit breaker of the remote terminal.At the existing substations, the circuit breaker defect protection system should be dedicated, allowingintegration with the existing circuit breaker fault protection schemes. The overcurrent sensors should beadjustable in a range of (0.1 2.0) x I n, with the timer in the range of 0 0.5s.

1.5.7 Special protection systems

1.5.7.1 Emergency Control Scheme (ECE)The Emergency Control Scheme (ECE Esquema de Controle de Emergência) should beimplemented at the Emergency Control Units (UCEs - Unidades de Controle de Emergência). TheEmergency Control Units are Digital Control Units (UCD - Unidades de Controle Digital) specifically forprocessing the Emergency Control Scheme (ECE - Esquema de Controle de Emergência) of the 500kV network of ELETRONORTE.There should be an Emergency Control Scheme (ECE) for each substation with 500 kV transmissionlines. In order to implement the Emergency Control Scheme (ECE), the TRANSMISSION UTILITYshould use as many Emergency Control Units (UCEs) as required.The characteristics described below are specific to the Emergency Control Scheme (ECE), and shouldbe strictly complied with by the TRANSMISSION UTILITY.• The Emergency Control Units (UCEs) should be functionally independent of the other units in the

Control and Supervision Protection System (SPCS) with regard to the performance of theirfunctions. These units should be connected to the Data Path (VDD − Via de Dados) solely to sendand receive information that should be displayed on the Supervision and Operation Units (USO −Unidades de Supervisão e Operação) of the Substations and Operating Centers;

• The Emergency Control Schemes (ECEs) for the various substations should be directly connectedamong themselves and with the existing Emergency Control Schemes (ECE) in theELETRONORTE System. Each Emergency Control Scheme (ECE) should be fitted with at leastfive RS-232C standard serial ports with onboard IEC-870-5-101 TCP-IP Communication Protocol;

• This connection should be dedicated to the Emergency Control Scheme (ECE) function andshould meet the following response time requirements:- The maximum total time estimated for decision-taking by an Emergency Control Scheme

(ECE)at a specific substation due to an alteration in the digital entries and/or violation ofthe limits established for the supervised functions occurring at another substation,including communication times should be less than or equal to 100 ms.

- Within a single Emergency Control Scheme (ECE) at the same substation, the action timeshould be less than or equal to 20 ms.

• Should the Digital Control Units (UCD) proposed for an Emergency Control Scheme (ECE) beunable to perform the functions specified below, the TRANSMISSION UTILITY should install theprotection relays in the quantity and type necessary and sufficient the handle these functions. Asmentioned above, these relays should also be exclusive for the Emergency Control Scheme (ECE)function, and may not be shared with the Control and Supervision Protection System (SPCS).

The following functions should be performed by the Emergency Control Units (UCEs):



• Bulk Power Capacity Direction Function:- Three-phase or phase start-up;- Characteristic inverse time curve;- Possibility of reversing direction;- Easy adjustment of the start-up point in terms of bulk power capacity (W) or current (A);- Fitted with independent alarm and off-switch outlets with local and remote reset;- Interface with fiber-optics.

• Under- and Overvoltage Function (for the busbars):- Start-up by phase;- Defined time characteristic;- Continuous function 27 adjustment in the 0.3 - 0.8 rated voltage range and function 59 in

the 1.1 1.5 rated voltage range;- Accuracy of more than 2%;- Pick Up / Drop Out ratio higher than 0.98;- Interface with fiber-optics.

• Under and Overfrequency Function- Equipped with 4 independent frequency stages;- Minimal adjustment range for each operating stage: 50 - 70 Hz, adjustable at intervals of

0.01 Hz.- Accuracy of +/- 0.005 Hz of adjusted value.- The unit operation should be blocked by under-voltage, adjustable at 40% - 80% of the

rated voltage.- Each unit should be equipped with alarm and disconnection functions.- The start-up of this unit should only be possible after an assessment period of no less than

3 cycles in order to eliminate possible future improper start-ups due to the aperiodiccomponent or other transitory factors in the voltage wave.

- Maximum reset time for this unit should be 50 milliseconds.- Maximum acceptable error for each timer will be +/- 5%.- Independent metering and outlet circuits by start-up stages.

1.5.7.2 Safety control schemes (ECS)The Tucuruí Expansion Disconnecting, Marabá, Imperatriz and Presidente Dutra Substations will beintegrated with the Safety Control Scheme (ECS - Esquema de Controle e Segurança) for the PowerSystem in South / Southeast / Center-West/North/Northeast Brazil.The following data should be available for connecting the CLP to the system:• Analog input:

- Flow of active bulk power on all transmission lines, generators and transformers;- Voltage at all busbar sections.

• Digital entry points:- Status indication with two circuit breaker contact points, disconnecting switches, generator

cut-off selection switches (for power plants);- Indication of protection scheme status;









- Requirements that may require dedicated systems: High uptake rate information to detect isolation High uptake rate information to detect disturbances.



1.6.2.1 General requirementsThe Tucuruí-Vila do Conde 500kV transmission line, 2nd circuit, involves the installation of a set of itemsof equipment including line input facilities, among other items, in existing substations belonging toELETRONORTEConsequently, all equipment to be installed by the TRANSMISSION UTILITY must be supervisedlocally in line with the philosophy adopted by the company that owns the said substations. Thissupervision must be duly integrated in the Supervision and Control Digital Systems (SDSCs) to beinstalled by ELETRONORTE.The architecture and basic requirements of these Supervision and Control Digital Systems (SDSCs) areprescribed in the documents Characteristics and Basic Requirements of Facilities, referring to the Vilado Conde SS and Tucuruí Disconnecting SS.If the TRANSMISSION UTILITY system were to start up before the SDSCs of ELETRONORTE areinstalled, it shall be designed to operate independently with a plan for later integration in the SDSCs.In addition to local supervision, the power equipment must permit remote supervision by the followingOperation Centers:• Center of the utility that owns the Vila do Conde SS and Tucuruí Disconnecting SS

- Belém- COL-Belém Local Operating Center•



• ONS Center:- North Regional Operation Center, COSR-N, in Brasilia-DF

Therefore, to meet the supervision and control requirements, the supervision systems will require to beinstalled in the facilities in order to:• Obtain information to enable the supervision and local control of the equipment to be installed;• Integrate, in the existing substations, with the Supervision and Control Digital Systems (SDSCs) to

be deployed by ELETRONORTE, for exchange of information;• Interconnect to the ONS Center, as stated in the item Requirements for Supervision and Control

by ONS and using the protocol IEC 870-5-104 or DNP 3.0.• Interconnect to COL-Belém, as mentioned in item Requirements for supervision by utility that

owns the substations. These interconnections must be made using the protocol already deployedtherein.

The protocols adopted for communicating with the operating centers (ONS and ELETRONORTE) mustbe configured in mutual agreement with said utilities.Moreover, this configuration must permit that said centers identify the operating status of theTRANSMISSION UTILITY supervision systems installed in the substations. This data will be modeledas status indications in the databases of those operating centers;Important Note:Should an operating center be introduced in the Notice of Tender herein known as a data concentrator,in the communication highway with any of the ELETRONORTE or ONS operating centers, theconfiguration of the protocol must permit that said centers identify the operating status of the dataconcentrator and, moreover, the data concentrator must be able to identify the operating status of allsystems hierarchically subordinate thereto and transfer such data to the corresponding centers, asapplicable.The TRANSMISSION UTILITY should bear the costs of modifying the metalwork and software as wellas the other services required for the existing Digital Supervision and Control Systems (SDSC) to einstalled by ELETRONORTE at the substations in order to permit full supervision of the electricalequipment through the existing man-machine interfaces (IHM) in the local control rooms at thesubstations. The quantity and types of points supervised shall be similar to those of the existingsystems.The TRANSMISSION UTILITY is also required to be responsible for installing and starting up theoperation of all equipment and systems required to facilitate the connection with the aforementionedoperating centers. As the interface between the TRANSMISSION UTILITY equipment and theaforementioned operating centers is required to be the digital input point of their communicationscomputers, this includes the installation of communication systems, modems and/or routers at all dataconnection terminals.As an alternative to installing new supervision and control resources, the TRANSMISSION UTILITYmay, by prior agreement with the companies that own the existing facilities, choose to expand theavailable supervision and control resources, provided all the requirements stipulated in the itemcaptioned Supervision and Control Systems (Sistemas de Supervisão e Controle) and TechnicalRequirements for the Telecommunications System to be Deployed (Requisitos Técnicos do Sistema deTelecomunicações a ser Implantado) are met.

1.6.2.2 List of information to be supervisedAs a general supervision and control requirement, all TRANSMISSION UTILITY equipment to beinstalled in the Tucuruí Disconnecting Station and Vila do Conde substations shall be supervised. The



data collected at said substations shall be transferred to the operating centers mentioned in the Noticeof Tender herein as specified below:(a) Telemetering



• The following measurements shall be collected and transferred to the operating centers:- Phase-phase voltage bay in kV in all line input facilities;- Active three-phase power in MW and reactive in MC/Ar in all line input facilities, measured

between the line and line reactor;- Phase current in amperes in all transmission line terminals;- Temperature of the windings and oil of each line reactor (per phase) in ºC;- Frequency in Hz of a phase on all busbars involved;


• (b) Status indication



• The facility supervision and control systems must be able to respond to integrity sweepsundertaken by the centers connected thereto (ONS and ELETRONORTE) which may be cyclical,adjusting the period by parameters, typically every five minutes, or by event, such as rebooting thesupervision and control resources at the centers, or on request;






(c) Each acquisition and control unit (UAC) shall be fitted with an internal clock and calendar to informthe day, month, year, hour, minute, second and millisecond of each status variation meteringoperation. These inner clocks must be fitted with synchro circuits based on a signal with anabsolute date obtained from a GPS system to ensure that the supervision and control of the



various facilities is undertaken on the same time basis. The system shall be designed to achievebetter accuracy than one millisecond.


(e) ll control and supervision system information transferred to the operating centers of the utilitiesmentioned herein shall be raw data, as collected from the transducers or interleaving relays, that is,with no prior processing except when explicitly agreed on a case-by-case basis with one of saidutilities. In these cases, the quality indicators shall include at least the following:



• (f) Information for sequencing events:


• Set of InformationThe information provided below and stored by the facilities supervision and control systemshall be transferred to COSR-N and COL-Belém, containing the instant when the event tookplace; while additional points may be included during the development of the final design

- Reactor:º 2nd stage oil overheating;º 2nd stage winding overheating;º 2nd stage gas protection;º Pressure blow valve;º Differential protection per phase;º Phase and neutral overcurrent coil protection;º Block relay operation.

- Transmission Line:º Main phase protection start-up by phase;º Main phase protection trip-switch;º Supplemental phase protection start-up per phase;º Supplemental phase protection trip-switch;º Main earth protection start-up per phase;º Main earth protection trip-switch;º Supplemental earth protection start-up per phase;º Supplemental earth protection trip-switch;



º Automatic reconnection start;º Circuit breaker fault scheme switch;º Overvoltage trip-switch;º Bulk power oscillation blocking;º Bulk power oscillation trip-switch;º Remote protection, block/release or permittive signal transmission;º Remote protection, trip transfer transmission;º Remote protection, receipt of block/release or remote permittive signal transmission;º Remote protection, transfer trip transfer receipt;º Faulty cutout blocking;º Switch-on time 2nd zone;º Switch-on time 3rd zone;º Switch-on time 4th zone;º Faulty cutout blocking;º Timed directional overcurrent;º Instant directional overcurrent;º Block relay switch-on.



- Digital Disturbance Metersº Start-up and failure

(g) Data age

• Maximum data age is understood to be the maximum time between the instant of the event of itsvalue in the facility (process) and its receipt at the ONS and ELETRONORTE operating centers.







(h) Dead BandDepending on the communications protocol adopted, the analog information may be reportedback on an exception basis to the operating centers mentioned herein. In these cases the valueadopted for the dead band used in the screening process must be agreed mutually between theutility that owns the center (ONS and ELETRONORTE) and the TRANSMISSION UTILITY. If noagreement is reached, the dead band value shall be 0 (zero).

1.6.3 Requisitos de supervisão pelo agente proprietário das subestaçõesThe TRANSMISSION UTILITY must provide the Operating Centers the utility that owns the existingsubstations with facilities for remote supervision of the equipment to be installed, pursuant to therequirements presented in the subitem entitled List of Information to be Supervised, applied inaccordance with the following criteria::• Supervision by the Local Belém Operating Center COL-Belém:

- Tucuruí Disconnecting Substation;- Vila do Conde Substation

The figure below offers a simplified overview of the supervision requirements for the substations(facilities) covered herein, through ELETRONORTE Operating centers. This is included merely as anillustration to offer a graphic overview of the requirements specified in the wording of the Notice ofTender herein.



Alternatively, the TRANSMISSION UTILITY may decide to connect the Centers of the utility that ownsthe substations (facilities) through one of the TRANSMISSION UTILITYs own operating center,provided the requirements described under Supervision and Control Systems herein are met. In theNotice of Tender herein, this center is generally called a data concentrator. In said case, the structureof centers shown in the preceding figure would be changed by inserting the data concentrator at ahierarchical level between the facilities and ELETRONORTE centers, therefore, included herein. Thefigure below illustrates a possible configuration.

COLBelém1

Key:1) Operating Centers used by the utilities that own substations:

COL Belém Belém local operating center

2) Supervision and control expansions in existing substations:PATC Supervision and control resources in the Tucuruí Disconnecting

substationPAVC Supervision and control resources in Vila do Conde substation

3) Supervision and control resources in ELETRONORTE substations.

PAT PAV2

PAV


Existing resourcesPAT



1.6.4 ONS supervision and control requirements

1.6.4.1 Basic requirements for equipment supervisionThe basic resources for supervising equipment that must be provided to ONS are described in the itemListed Information to be Supervised and cover:• Telemetering with 4 second scanning, which can be parameterized;• Status indicators reported by exception and with an integrity cycle, that can also be parameterized;• Sequence of events (SOE).

1.6.4.2 Requirements that may require dedicated systems

1.6.4.2.1 Information with a high acquisition rate for detecting confinementThe frequency measurements must be sent to COSR-N in Hz for each busbar relating to the line inputfacilities herein, acquired and transferred within a 200 ms period (a measurement for each substationinvolved).

1.6.4.2.2 High Uptake Rated Data for Disturbance DetectionThe kV measurement of the phase-phase bay of the 500 kV line of the Tucuruí Disconnecting Stationand Vila do Conde substations must be sent to the COSR-N. Please note the high transfer rate of saiddata, which differs from the rate normally used for normal data uptake, which is typically four seconds.

PAT PAV


Existing resources

PAV

COLBelém

Key:The following is used in addition to the acronyms in the preceding figure:CD – Data concentrator, common name given to a supervision and controlsystem that is inserted between the facilities and ELETRONORTE Centers.

PAT

CD1



1.6.4.3 Architecture of Interconnection with ONSSupervision and control is one of the mainstays of the real-time operation of the power system, andtoday in the Tucuruí and Vila do Conde region, is structured on a hierarchical system with supervisionand control systems installed in the following ONS operating centers:• North Regional Operating Center COSR-N;• National Power System Operation Center - CNOS.This structure is in a simplified form in the following figure just for illustration. The TRANSMISSIONUTILITY shall provide the data interconnections between the ONS operating center (except for CNOS)and each of the supervision systems of the substations involved.

Note in the above figure that the ONS Cbetween COSR-N, Tucuruí disconnecting a

Alternatively, the TRANSMISSION UTILITYof the TRANSMISSION UTILITYs own odescribed herein, in Supervision and

CNOS1

1) Operating centers used by ONCNOS National Power SyCOSR-N North Regional O

2) Supervision and control expaa) PATC Supervisio

disconnecting substab) PAVC Supervision

substation.3) Supervision and control resou

)

PAT


COSR-N1

PAT PAVExisting resources

PAV

Key:S:

stem Operating Center;perating Center.

nsion in existing substations:n and control resources in the Tucuruítion;and control resources in the Vila do Conde

rces in existing substations

VOL. IV - Fl. 100 de 192

enters figure are linked up through data interconnectionsnd Vila do Conde substations.

may decide to interconnect the ONS COSR-N through oner outsourced operating center, provided the requirementsControl Systems and Technical Requirements of the



Telecommunication System to be Deployed are met.. In the Notice of Tender herein, this center isgenerally called a data concentrator. In said case, the structure of centers shown in the precedingfigure would be changed by inserting the data concentrator at a hierarchical level between the COSR-Nand ONS centers, therefore, included herein. The figure below illustrates a possible configuration

1.6.4.4 Equipment registration requirementsThe metering of all equipment to be opthe start-up. This data must include:• Descriptive parameters of Trans

pursuant to model π, and the malongitude of each facility and pylo

• Rated capacity in MVAr and ratebe used, such as capacitors, rea

• Provision of diagrams of operatio• Provision of the diagrams with th

each facility;• All diagrams shall be issued on

agreed in advance between the

CNOS

The following is used in addition to thCD Data concentrator, name commbetween the facilities and the ONS ce


PATExisting resources

PAT

COSR-N

VOL. IV - Fl. 101 de 192

erated by ONS shall be sent thereto at least three months before

mission Lines, including series impedance and its susceptance,ximum current in amps, maximum power in MVA and latitude andns;d voltage in kV, of all static reactive support equipment that may

ctors, etc.,ns with the name of all equipment in each facility;e exact site of all metering points, remote signaling and control of

hard and soft copies, to an import and export standard to beTRANSMISSION UTILITY and ONS;

CD1

PAV

Key:e acronyms of the preceding figure:only given to a supervision and control systemnters

PAV



• A list, compatible with the supervision and control requirements herein of the metering, remotesignaling, control and SOE points that will travel through the interconnection (or interconnections)as the ONS supervision and control system, in a format compatible with the protocol adopted forthe interconnection and organized by SSCL/UTR and data concentrators, if used;

• In the event of direct data interconnections with UTRs, and if applicable, parameters that permit theconversion of the data sent to the Center to engineering values;

• Whenever applicable, top and bottom scale constraints for all supervised analog points.

1.6.5 Availability and quality assessment requirements

1.6.5.1 GeneralThe supervision and control resources provided by the TRANSMISSION UTILITY to meet therequirements herein shall have their availability and quality measured according to the concepts andguidelines established below.These resources will be assessed for each metering or control point, based on their availability/qualityseen by the centers mentioned herein. Thus, not only will the data collection equipment in the facilitiesbe assessed, but also all systems that are inserted between such equipment and the computer systemof the aforementioned centers, including the communication system and interfacing equipment with thecommunication computers (for example, modems).Assessment by a supervision and control resource will help observe not only telemetering and statusindicators but also the operating status of remote terminals, supervision and local control systems anddata concentrators, since the operating status of said equipment will be received by the Centers asstatus indicators.Moreover, aggregate indices will be calculated to give an overview of the availability and quality of thesupervision and control resources of the TRANSMISSION UTILITY.

1.6.5.2 Concept of Supervision and Control Resources AvailabilityAn item of information of any of the types specified herein is said to be unavailable for any of thecenters whenever:• The quality indicator received together with the information shows any abnormality, for example:

- Information deactivated at origin (facility);- Information invalid at origin;- Information not updated;

Notes:1) This case will be considered if the power equipment associated with the point is in repairor out of order due to operating requirements and the TRANSMISSION UTILITY uses one ofthese points, typically deactivated at origin to mark the fact.2) The manual quality points does not characterize an item of information as unavailable butrather of poor quality, as described in the item Concept of Quality of the Supervision andControl Resources.

• Analog information violates one of its respective scale restraints;• An item on status marker information is inconsistent.• • All SOE points of a supervision and control system or remote terminal are said to be unavailable whenan event occurs that must trip the sequential meter and this is not done.



A SOE point is said to be unavailable whenever it is not reported.All points subordinate to a supervision and control system of a facility will be said to be unavailablewhenever there is no response from said system to requests from the center(s) or data concentrator, ifused. Moreover, when using data concentrators, all points subordinate to the concentrator will be saidto be unavailable when it does not respond to the requests from any of the operating centers mentionedherein.Any point is said to be unavailable whenever it is under maintenance.

1.6.5.3 Quality concept of supervision and control resourcesAny information of any type specified herein is said to be violating the quality guidelines when:• The quality indicator marks information entered manually by the TRANSMISSION UTILITY

operator (if any);• It does not meet the data age requirement.• In the case of analog data, it does not meet the accuracy requirement;• In the case of time stamp data, it does not meet the accuracy requirement.

1.6.5.4 Indicators







Di = ( ( T - TIi ) / T ) X 100Where:







ΣTij





supervision network under center j responsibility.1.6.5.4.3 Quality per supervision and control resource [Qi]

Description:• Abbreviation: Qi


• Study period: Monthly• Unit of measurement: Percentage• Nature: Supervision and Control Systems• Aggregation: Monthly, per supervision and control resources and per operating center• Quality guideline: The acceptable minimum value is 97.5%, on a monthly basis;• Data required: As in equation• Equation:

Qi = ( ( Tq - Tnqi ) / Tq ) X 100Where:a) Qi : Quality rate of resource i;b) Tq: Total time in minutes for the study period;c) Tnqi: Sum of the periods when point i does not comply with the concept of quality the whole time

Tq.1.6.5.4.4 Quality of the TRANSMISSION UTILITYs supervision and control resources [QRSj]


PROCURADGERAL/ANE VISTO

Description:• Abbreviation: QRSj



ΣTqij QRSj = X 100Tq X NPRSqj

Where:- - Tq: Total time in minutes of the calculation period;- - Tqij: Sum of the periods when the resource i complied with the quality concept

during the total time Tq, when seen by center j;Note: Tqij = (Tq Tnqij)where:

- - Tnqij: Sum of the periods when point i does not comply with the quality concept duringthe total time, when seen by center j;

- - NPRSqj: Total number of the TRANSMISSION UTILITYs supervision and controlresources in the supervision network under responsibility of center j and may beassessed for quality.


1.6.5.5


Transmission resources seen byCenter “j”

100%

c
Resourc“k”
ORIAEL

Analytical and assessment reports for the availabilit



98.5

97.5

Resour“l”

Resoruce

VOL. IV - Fl. 105 de 192

y of the supervision and control resources



The operating centers that will receive the TRANSMISSION UTILITY data will assess the availabilityand quality of the supervision and control resources, issuing non-conformity reports in the followingsituations:• Any of the indicators specified is less in the month than the corresponding guideline set herein;• There is a loss of more than 30% of the supervision and control resources provided by the

TRANSMISSION UTILITY for a period of more than or equal to one hour;• During a major disturbance in the Basic Grid, one or more supervision and local control systems of

the TRANSMISSION UTILITY are out of order or loses the communication with some dataconcentrator of the TRANSMISSION UTILITY, if used.

Based on the aforementioned, there will be two types of reports:• Availability and Quality Assessment Report: issued whenever some availability and/or quality


1.6.5.6 Publishing the TRANSMISSION UTILITY availability, quality and action reportsThe final reports must be issued based on the reports written by the utilities who own the operatingcenters and after equating with the TRANSMISSION UTILITY, including, if applicable,recommendations for correction of any anomaly.Wherever the guidelines specified herein are not met, the Utility that owns the operating center willsend the reports to ANEEL for the appropriate measures to be taken, based on the prevailing laws andcontracts with the TRANSMISSION UTILITY.



Software must be provided for the data transfer, compaction/decompaction, conversion to standardformat COMTRADE (IEEE C37.111-1999) and remote communication interface, as well as software foradjusting and gauging the RDP.

The RDP must contain self-monitoring and ongoing self-diagnosis routines.The internal time of the RDP must be synchronized using a synchro device via satellite signal (GPS).







a) be configurable for current and voltage;b) have a delay time between any channels of less than 1 electrical level referring to 60 Hz;








1.5 s50 ms


2 In20 In




1.7.7 Occurrence metering capacity.



The digital disturbance meter (RDP) must have sufficient memory to store the data covering at least 30(thirty) disturbances lasting 5 (five) seconds each, should several consecutive defects trip the meter.The digital disturbance meter must be able to measure at least 160 ms of pre-failure data for eachfailure or disturbance and the post-failure time must be adjustable between 100 and 5000 ms.Metering a failure or disturbance must only be interrupted where the start-up sensors are non-operative, and after completion of the adjusted post-failure time.Should the sensor remain operative, the disturbance metering must continue until the sensor becomesnon-operative, including the meter for the post-failure time.Should a fresh disturbance occur prior to the completion of the metering time for an earlier disturbance,the meter must start a new metering period, not taking into account the time already passed for theprevious disturbance.




1.8 TECHNICAL REQUIREMENTS OF THE TELECOMMUNICATIONS SYSTEM TO BE IMPLEMENTED

1.8.1 General requirementsThe telecommunications for the expansion of the North/Northeast Interconnection should service theoperations and administration voice communications systems, as well as remote protection, electricalsupervision and control, telecommunications supervision, emergency control, metering, billing andmaintenance of the power transmission line between the substations involved, and between thesesubstations and the Operating Centers of the power system involved.The voice and data communications media should comply with the following requirements:• Availability equal to or greater than 99.7% measured for each period of 30 (thirty) days;• Provision should be made for digital circuits complying with the G.821 recommendations issued by

the International Telecommunication Union (ITU);• Analog equipment will be accepted only in cases where it is impossible to locate new equipment

compatible with the existing infrastructure. In these cases, the following recommendations shouldbe followed: CCIR 391, 392, 394, 395, 396 and 397, as well as the pertinent IEC recommendation;

• The requirements in IEC standards 834-1, 870-5 and 870-6 should be followed for the remoteprotection system as well, where applicable.

The energy system for all telecommunications equipment supplied should have the followingcharacteristics:• Supervision unit and at least two rectification units;• Two banks of batteries meeting full power requirements for at least 12 hours sized to handle the

total load all installed telecommunications equipment;• Should lead-acid batteries be used, the banks of batteries should be placed in a special location,

separate from the other facilities and fitted with a gases exhaust system;• The rectification unit should have the capacity to simultaneously feed the bank of batteries being

charged and all telecommunications equipment with a sizing margin of 30%.The telecommunications equipment should be supervised at both the local and remote levels, andshould sound alarms in the facilities in case of any anomaly in the main telecommunications equipment,including the power supply equipment.The equipment should be fitted with remote supervision facilities, and allow remote management, withself-diagnosis and configuration.The TRANSMISSION UTILITY will be responsible for the full operationalization of the communicationslinks, with all infrastructure required to implement the telecommunications system, on the basis of theprovisions in item 5 of documents GTS-TUC-N/NE-III-001 and GTS-MAB-N/NE III-001 IBN-S/SE-001,GTS-IPZ-N/NE III 001, GTS-PDD-N/NE III 001, such as: buildings, 48 Vcc direct current powersupply for the telecommunications equipment, able to provide power for at least 12 hours, should theAlternating Current System fail, as well as any other infrastructure ranked as necessary to ensure thefull functioning of the telecommunications system.The TRANSMISSION UTILITY will be responsible for monitoring the voice and data channels thatinterconnect with the National Electricity System Operator (ONS), and ELETRONORTE, whenever sorequested thereby. The purpose of these monitoring facilities is to measure performance indicators inorder to check that the channels are operating in accordance with the minimum acceptablerequirements. If any discrepancies are noted in the measurements obtained compared to therecommended values, the TRANSMISSION UTILITY will agree to undertake corrective maintenance



measures as required within the deadline stipulated under common agreement with the ONS andELETRONORTE.Should it be necessary to schedule downtime for any data or voice channels of interest to the ONS andELETRONORTE, the TRANSMISSION UTILITY should enter into understandings with the ONSOperating Center and ELETRONORTE with which it is connected, in order to obtain approval for theservice requested, at a convenient date and time.Finally, when submitting the executive project, the TRANSMISSION UTILITY should demonstrate thatthe communications architecture (configuration, number and capacity of the links, etc.) adoptedcomplies with the requirements stipulated in this Notice of Tender, through a Calculation Memorandum.

1.8.2 Remote protection requirementsThe telecommunication equipment dedicated to remote protection functions should be appropriate foruse in bulk power system facilities in order to recognize the presence of signals and/or frequencies thatidentify a command to the protection systems.The equipment should be fitted with test switches that allow intervention therein, without having to de-energize the transmission line.The remote protection facilities should maintain the operating, reliability, safety and security underadverse signal/noise ratio conditions, as well as in case of breakage of the transmission line conductors(use of the unblocking logic).Independent, redundant telecommunication equipment should be used for Main and AlternateProtection Systems, preferably using independent physical transmission facilities so that the non-availability of one set of telecommunications facilities does not adversely affect the availability of theother. Each item of communications equipment should be fitted with at least two communicationschannels. Consequently, the transmission line protection system will have at least four remoteprotection channels each way, two associated with the primary protection system and two associatedwith the alternate protection system.The direct trip-switch transfer schemes for each protection system should be implemented through theuse of two communications channel for each of them, combined in series. The outlet points for the trip-switch transfer receivers should be connected in series, so that both units should receive the signalbefore activating the trip-switch command. The logic should be designed in a way that allows thesystem to be tripped, even if contact is lost with one of the communications channels.The direct trip transfer channels will remain continuously operative when the block relays arefunctioning (occurrence fault in the circuit breakers, faults in the line reactors, and overvoltageprotection system operative) and will function temporarily, when tripped by the line protection scheme.The reception logic should be equipped with the means to identify trip transfer signals, distinguishingthose for which automatic reconnection should be permitted from those where reconnection should notbe permitted.For the remote protection schemes based on permittive overreach logic, one of the channels in eachprotection scheme should be brought into action by the line protection over reach metering units. Forremote protection schemes based on block signal directional comparison logic schemes, the channelsshould be brought into action by the line protection reverse metering units. For remote protectionschemes based on permittive underreach logic, these channels will be brought into action by the lineprotection underreach metering unit.The telecommunications channels should be specific to the protection schemes, and should not beshared with any other applications, ensuring that the time between sending a signal from a terminal andits receipt at the opposite terminal is less than 15 ms.



Provision should be made to record the sending and reception of signals associated with bringing theremote protection system into action, in the sequence of events registration system of the facility, inorder to ensure faster analysis of post-disturbance occurrences.

1.8.3 Voice channel requirementsThe TRANSMISSION UTILITY should provide a communication system with two voice channels, withat least one of them being direct; the other may be operated through a switched telephone system,both full duplex, with sound and visual signaling facilities for operational communications of the powersystem between the:• Substations involved: Tucuruí Expansion Disconnecting, Marabá, Açailândia, Imperatriz and

Presidente. Dutra• Should the TRANSMISSION UTILITY decide to use the local Operating Center, either its own or

outsourced, channels should be provided between this Center and the:- Tucuruí Expansion Disconnecting Substation;- Marabá Substation;- Açailándia Substation;- Imperatriz Substation;- Presidente Dutra Substation;- North Regional Operating Center (ONS - COSR-N);- ELETRONORTE Local Operating Center (COL Belém and COL São Luiz))

• Should the TRANSMISSION UTILITY decide not to use a Local Operating Center, whether in-house or outsourced, the substations should have channels available connecting them through theONS and ELETRONORTE Centers as follows:- Channels linking them to North Regional Operating Center COSR-N (ONS):

º Tucuruí Expansion Disconnecting Substation;º Marabá Substation;º Imperatriz Substationº Açailândia Substation;º Presidente. Dutra Substation.

- Channels linking them to Belém Local Operating Center - (ELN) COL-Belém:º Tucuruí Expansion Disconnecting Substation;º Marabá Substation;

• Channels linking them to São Luiz Local Operating Center - (ELN) COL-São. Luiz:º Imperatriz Substation;º Açailândia Substation;º Presidente Dutra Substation.

Additionally, a mobile communications system should be supplied to cover the entire length of thetransmission lines and the substations involved, providing support for the electrical andtelecommunications maintenance staff.

1.8.4 Data transmission requirementsThe data links specified below should be sized (number of channels, speed, use of alternative routes,etc.) in order to support the loads required to transfer the information and the specific controls (noteitems 1.5, 1.6, 1.7 and 1.8) with the availability and quality ratings as described in this Notice of Tender.



1.8.4.1 Supervision and control linksFor supervision and control by the ONS and ELETRONORTE, the following redundant data linksshould be supplied, preferably through alternative routes.• Should the TRANSMISSION UTILITY decide to use the Local Operating Centers, either in-house

or outsourced:- Links with the Local Operating Center:

º Tucuruí Expansion Disconnecting Substation;º Marabá Substation;º Açailândia Substation;º Imperatriz Substation;º Presidente Dutra Substation;º North Regional Operating Center COSR-N (ONS);º ELETRONORTE Local Operating Center: COL-Belém and COL-São Luiz

• Should the TRANSMISSION UTILITY decide not to use the Local Operating Center(s), either in-house or outsourced:- Links with the North Regional Operating Center - COSR-N (ONS):

º Tucuruí Expansion Disconnecting Substation;º Marabá Substation;º Imperatriz Substation;º Açailândia Substation;º Presidente Dutra Substation.

- Links with the ELETRONORTE Local Operating Center - COL-Belémº Tucuruí Expansion Disconnecting Substation;º Marabá Substation;

- Links with the ELETRONORTE Local Operating Center - COL-São Luizº Imperatriz Substation;º Açailândia Substation;º Presidente Dutra Substation.

1.8.4.2 Other data linksIn order to handle the disturbance records data uptake, two direct extension dialing (telephoneextensions should be provided).Alternative solutions allowing access through a data network may be accepted, provided that at leastthe same performance ratings are guaranteed as those assigned to the links specified above.



1.9 BASIC REQUIREMENTS FOR THE BASIC AND ALTERNATIVE CONFIGURATIONSAs indicated above the TRANSMISSION UTILITIES are not free to modify:• The locations of the Expansion Tucuruí Disconnecting, Marabá, imperatriz and Presidente Dutra

Substations;• The voltage levels (only alternating current);• System flow distribution (effective impedance).

On the other hand, as also indicated above, the TRANSMISSION UTILITIES are free to suggestalternative configurations, including:• \location of the Açailândia Substation• Reactive values for the line and busbar reactors;• The parameters of the Transmission Line, provided that the requirements in the Annex 7C herein

are met.• Pylon configurations.

Regardless of the proposed configuration, the TRANSMISSION UTILITIES shall perform at least thefollowing studies:• Bulk power flow, load rejection and energization at the basic frequency;• Temporary studies for reconnection, load rejection and energization.

These studies shall demonstrate compliance with the provisions in the Electricity Systems planningGroup (GCPS Grupo Coordenador do Planejamento dos Sistemas Elétricos) criteria document andthe study reports listed in item 2.1.1 as well as the following criteria and requirements.



Emergency operating condition(*)Rated Normal operating condition

Busbars with load Other busbars500 500 - 550 475 - 550 475 - 600345 345 - 362 328 - 362 328 - 362

(*) 1-hour duration

1.9.2 Maneuvering requirements associated with the transmission lines

1.9.2.1 Acceptable overvoltageThe maximum voltage for permanent and dynamic systems at the ends of the transmission lines aftermaneuvering (energization, three-pole and unipolar reconnection and load rejection) shall becompatible with the supportability of the insulator substation equipment, of the insulators andtransmission lines.



The dynamic voltage effective voltage between the phases at the instant immediately after operatingthe circuit breakers and the sustained voltage effective voltage between the phases in thesubsequent instants shall lie within the range of values given in Table 6.Table 6 Rms voltage between phases acceptable at the end of the transmission lines after maneuver(kV)


It is acceptable for the overvoltage caused by transmission line energization maneuvering and loadrejection to last for one hour.

1.9.2.2 Energization of transmission linesThe energization of the transmission lines shall be feasible in all situations assessed in the basicconfiguration, complying with the voltage criterion under normal operating conditions as defined in thetable 5.Specifically, provision shall be made for possible two-way energization, should the system reach thelevel of degradation at which this is feasible in the basic configuration, except for transmission lineMarabá-Açailândia.




0 5 10 15 20 25 30 35 40 4 5 55Arc current (Aef)

0

50

100

150

200





1.9.3 Opening and closing of the disconnecting and earth disconnecting devicesThis equipment shall meet the requirements of the applicable standards.The opening and closing of the disconnecting and earth disconnecting devices shall take intoconsideration the induced resonant voltages of transmission lines in parallel, operating under normalconditions with maximum load or with single-phase defect. Any possible resonance induction caused bythe transmission lines that affect other existing parallel transmission lines shall also be checked andcorrected.

1.9.4 Circuit breaker cutout requirementsThe 500 kV circuit breakers shall be able to handle the following operations:• Idle line opening: considering the longest line, with effective inter-phase voltage of 770 kV at a

frequency of 66 Hz, without relighting the arc. A frequency of less than 66 Hz will be acceptableprovided that this is confirmed by system studies.





2 ENGINEERING AND PLANNING STUDIES FOR THE NORTH / NORTHEAST INTERCONNECTION -500 KV AND 500 KV SUBSTATIONS BELONGING TO THE INTERCONNECTION

The Engineering and Planning studies and the documents prepared by CCPE AND ELETRONORTEfor the 500 kV transmission line and the 500 kV substations belonging to the North/Northeastinterconnection are listed below, and may be used partially or in full at the discretion of theTRANSMISSION UTILITY, and for the sole liability thereof.

2.1 ENGINEERING AND PLANNING STUDIES AND RELATED TECHNICAL DOCUMENTATION FORTHE NORTH/NORTHEAST INTERCONNECTION

2.1.1 ReportsANEEL No Nº COMPANY DOCUMENT

501RE TUCPDD3FT02/00 OUT/2000

Definition of parallel and series compensation from the standpoint ofthe permanent system optimized route for the third 500 kV circuit,Tucuruí/Presidente Dutra

502RE TUCCPDD3FT03/00 OUT/2000

Permanent system and stability studies to define the additionalequipment and reactive compensation for operations on the thirdcircuit, Tucuruí/Presidente Dutra and the North-South II andSoutheast-Northeast interconnections

503PTES-NT-1070/2000 Studies of transitory electromagnetic effects linked to the

energization and reconnection measures for the 500kV:transmission lines: North-Northeast Interconnection, 3rd circuit andTucuruí-Vila do Conde transmission line, 2nd circuit

2.1.2 Electrical System Data StudiesANEEL No COMPANY IN

CHARGE DOCUMENT

504 CCPE Database used in the Bulk Power Flow and Stability Simulations, inthe ANATEM and ANAREDE program formats, CEPEL

505 CCPE Database used in the transitory electromagnetic equipment studies inthe ATP digital program format

2.2 REPORTS ON BASIC REQUIREMENTS AND CHARACTERISTICSThese Reports form an integral part of ANNEX 7C, and the recommendations should be adopted by theTRANSMISSION UTILITY when developing its projects and designs for implementation of the facilities.

ANEEL No No COMPANY DOCUMENT

506 ELETRONORTEGTS-TUC-N/NE II-001

Facilities - Characteristics and Basic RequirementsSubstation: Tucuruí Expansion Disconnecting

507 ELETRONORTEGTS-MAB-N/NE II-001

Facilities - Characteristics and Basic RequirementsSubstation: Marabá

508 ELETRONORTEGTS-IPZ-N/NE II-001

Facilities - Characteristics and Basic RequirementsSubstation: Imperatriz

509 ELETRONORTEGTS-PDD-N/NE II-001

Facilities - Characteristics and Basic RequirementsSubstation: Presidente Dutra



2.3 ELETRONORTE SUBSTATION DOCUMENTS

2.3.1 TUCURUÍ EXPANSION DISCONNECTING SUBSTATION

ANEEL No ELETRONORTE No DESCRIPTION1 TUC-091-02010 Location Plan2 TUC-091-02020 500 kV Sector Physical Arrangements M-M Cross-section3 TUC-091-56000 500/230 kV Sector Simplified Diagram

2.3.2 MARABÁ SUBSTATION

ANEEL No ELETRONORTE No DESCRIPTION4 TUC-095-02527 500/230/69 kV substation Basic Location Plan5 TUC-95-2528 500 kV substation General Plan6 TUC-95-2529 500 kV substation General Plan7 TUC-095-02004 Series Compensation Stage Physical Arrangement Plan8 TUC-95-2531 500 kV substation D-D and E-E Cross-section9 TUC-095-02006 Series Compensation Stage Physical Arrangement A-A and

B-B Cross-section10 TUC-95-5801 Earth-leveling Project Plan11 TUC-95-65605 Earth-leveling Typical Cross-sections12 TUC-095-04601 Series Compensation Stage Earthmoving Plant Cross-

section13 TUC-95-6003 General Internal and External Drainage Network - Plan14 TUC-095-04608 Series Compensation Stage Yard Drainage Plan15 TUC-95-2544 Centralized Command Building Equipment Location Ground

and Upper Floors16 TUC-95-4346 500 kV substation Earthing Network Partial Plan Page 117 TUC-95-4347 500 kV substation Earthing Network Partial Plan Page 218 TUC-095-19021 Series Compensation Stage Earthing Network Plan19 TUC-95-4039 500 kV substation Installation of Electric Conduits and Boxes -

Plan20 TUC-95-4065 500 kV substation Installation of Electric Conduits and Boxes21 TUC-95-4066 500 kV substation Installation of Electric Conduits and Boxes -

Plan22 TUC-95-4067 500 kV substation Installation of Electric Conduits and Boxes -

Plan23 TUC-095-45004 Series Compensation Stage Electric Conduits and Boxes

Plan and Details24 TUC-95-7301 Fire Protection Systems Plan, Cross-sections and Details

Page 125 TUC-95-7305 Fire Protection Systems - Hydrants Plan Page 226 TUC-95-4424 Supplementary Lighting and 220 V Power Outlets Plan27 TUC-95-4425 Supplementary Lighting and 220 V Power Outlets Plan28 TUC-95-4437 Supplementary Lighting and 220 V Power Outlets Plan29 TUC-95-4426 Outside Lighting, Ring-road and 440 V Power Outlets and

Telephones Plan



ANEEL No ELETRONORTE No DESCRIPTION30 TUC-95-4427 Outside Lighting, Ring-road and 440 V Power Outlets and

Telephones Plan31 TUC-95-4438 Outside Lighting, Ring-road and 440 V Power Outlets and

Telephones Plan32 TUC-095-48001 Bank of Series Capacitors Lighting and Outside Power Outlets

Plan33 TUC-95-4336 13.8 kV Power Feed General Diagram34 TUC-095-56102 Protection and Control General Diagram Page 135 TUC-095-56102 Protection and Control General Diagram Page 236 TUC-095-56102 Protection and Control General Diagram Page 336A TUC-095-56010 General Diagram

2.3.3 AÇAILÂNDIA SUBSTATION

ANEEL No ELETRONORTE No DESCRIPTION

37 MAR-101-56000 Simplified Diagram

2.3.4 IMPERATRIZ SUBSTATION

ANEEL No ELETRONORTE No DESCRIPTION38 MAR-96-9756 500 kV Substation Electrical Equipment Yard Plan39 MAR-096-56001 500 kV Substation Simplified Diagram40 MAR-096-00702 Basic Location Plan41 MAR-96-00835 Control House Command Room Equipment Location Plan42 MAR-96-1304 500 kV Substation Electrical Equipment Yard Cross-Section -

Page 443 MAR-96-5481 500 kV Substation Electrical Conduits and Cable Routes - Partial

Plan Page 344 MAR-96-5482 500 kV Substation Electrical Conduits and Cable Routes Partial

Plan Page 445 MAR-96-05861 500 kV Substation Outside Lighting, Supplementary, 440 V, 220 V

Power Outlets and FOs Plan46 MAR-96-6203 500 kV Yard 2nd Circuit Earthing Grid Partial Plan Page ½47 MAR-96-6204 500 kV Yard 2nd Circuit Earthing Grid Partial Plan Page 2/248 MAR-096-8215 Firefighting System Hydrants Plan Part 149 MAR-096-09015 Series Compensation Stage Relay House CR-502A - Equipment

Arrangements50 MAR-96-09542 500 kV Substation Ancillary Services 440 V System

Alternating Current Diagram51 MAR-96-09544 500 kV Substation Ancillary Services 125 V System

Continuous Current Diagram52 MAR-096-56107 General Protection and Control Diagram Page 153 MAR-096-56107 General Protection and Control Diagram Page 254 MAR-096-56107 General Protection and Control Diagram Page 355 MAR-096-56107 General Protection and Control Diagram Page 456 MAR-096-92000 Series Compensation Stage Ancillary Services General Diagram



2.3.5 PRESIDENTE DUTRA SUBSTATION

ANEEL No ELETRONORTE No DESCRIPTION57 MAR95-0706 500 kV Sector Electrical Equipment Yard - Plan58 MAR-095-02001 Series Compensation Stage Physical Arrangement Plan59 MAR-95-0708 500 kV Sector Electrical Equipment Yard Cross-Section Z-10460 MAR-95-0709 500 kV Sector Electrical Equipment Yard Cross-Sections Z-105,

Z-350 and Detail Z-12561 MAR-095-02006 Series Compensation Stage Physical Arrangement Cross-Sections

A-A and B-B62 MAR-95-6300 Earth-Moving - Plan63 MAR-095-04601 Series Compensation Stage Earth-Moving Plan Cross-Sections64 MAR-95-8101 500 kV Sector Rainwater Runoff Network General Plan65 MAR-095-04608 Series Compensation Stage Drainage Plan66 MAR-95-9708 Command House Equipment Arrangement As Built Plan67 MAR-095-09015 Series Compensation Stage Relay House CR-502 A Equipment

Arrangement68 MAR-095-09020 Teresina Span Stage Relay House CR-502B Equipment

Arrangement69 MAR-95-5801 Handling Yard Earthing Network General Plan70 MAR-095-19001 Series Compensation Stage Earthing Network Plan71 MAR-95-5307 500 kV Sector Handling Yard Electrical Conduits Partial Plan

Page one72 MAR-95-5308 500 kV Sector Handling Yard Electrical Conduits Partial Plan

Page two73 MAR-95-5309 500 kV Sector Handling Yard Electrical Conduits Partial Plan

Page three74 MAR-095-45000 Bank of Series Capacitors Electrical Conduits and Boxes Plan75 MAR-95-8118 500/230/69 kV Sector General Arrangement of Fire-Fighting Water

System Plan and Details76 MAR-95-5834 500, 230, 69 kV Substation Access Roads Outside Lighting, 440 V

Perimeter Plan77 MAR-95-5882 500 kV Sector Handling Yard Supplementary Outside Lighting and

220 V Power Outlets Plan78 MAR-95-5879 500 kV Sector Handling Yard Outside Lighting and 440 V Power

Outlets Plan79 MAR-095-48001 Series Compensation Stage Outside Lighting and Power Outlets

Plan80 MAR-95-1083 500/230/69/13.8 kV Sectors Ancillary Services AC System at

13800-460-220/127 VCA and DC System 125 VCC SimplifiedDiagram

81 MAR-095-92000 Series Compensation Stage Ancillary Services General Diagram82 MAR-095-56102 General Protection and Control Diagram Page 183 MAR-095-56102 General Protection and Control Diagram Page 284 MAR-095-56000 Simplified Diagram



2.4 TRANSMISSION LINE DOCUMENTS

ANEEL No ELETRONORTE No DESCRIPTION301 a 304 MAR82-1488

(4 pages)500 kV transmission line - Tucuruí Marabá Route C2

305 a 308 MAR-83-1473(4 pages)

500 kV transmission line Marabá Route Imperatriz C2

309 a 396 MAR-82-1400 toMAR-82-1487(88 pages)

500 kV transmission line - Tucuruí Route Marabá C2 Plan andProfile

ANEEL Nº ELETRONORTE Nº DESCRIPTION

397 a 469 MAR-83-1400 toMAR-83 1472(73 pages)

500 kV transmission line - Marabá Imperatriz C2 Plan and Profile

470 MAR-82-2250 500 kV transmission line - Tucuruí Marabá C2 Reduced Profile withProbe Records

471 MAR- 83-2250 500 kV transmission line - Marabá Imperatriz C2 Reduced profilewith Probe Records

472 a 478 MAR-84-1555(7 pages)

500 kV transmission line - Imperatriz Presidente Dutra C2 RoutePlan

479 S/Nº 500 kV transmission line - Imperatriz Grajaú C2 Reduced Profilewith Probe Record

480 S/Nº 500 kV transmission line - Grajaú Presidente Dutra C2 ReducedProfile with Probe Records

481 S/Nº North/Northeast C3 Interconnection - Tucuruí/Presidente Dutra Stretch Preliminary Route Guideline Study October 2000




3.1 GENERALThe TRANSMISSION UTILITY should implement GROUP C TRANSMISSION FACILITIES incompliance with Brazilian Law and the applicable environmental requirements applicable.



5 TIME-SCHEDULE

The TRANSMISSION UTILITY shall submit the deployment schedule for the TRANSMISSIONFACILITIES belonging to its concession, pursuant to models given in Table A and B of Annex 7C,indicating the intermediate benchmarks, for the following activities: environmental licensing, basicdesign, topography, work site, foundations, pylon erection, conductor cable laying and installation ofequipment, civil construction works and erection of transmission and substation facilities, andcommissioning, permitting monthly check on the progress of the works, to ensure the COMMERCIALOPERATION START-UP within no more than 22 (twenty two) months.




COMPANY NAMEDATE

MONTHSNo DESCRIPTION OF

INSTALLATION STAGES 1 2 3 20 21 22


etc.2 ENVIRONMENTAL

LICENSING

3 CIVIL WORKS ANDERECTION

3.1 WORK SITE FACILITIES3.2 FOUNDATIONS3.3 PYLON ERECTION3.4 CABLE LAYING





SIGNATURE CREA No

ENGINEER REGION





DATE

MONTHSNo.


1 DESIGNS2 PROCUREMENT2.12.22.32.43 CIVIL WORKS AND

ERECTIONS3.1 Mobilization3.23.33.43.53.6 Commissioning4 ENERGIZATION4.1STARTING DATE COMMENTS:


SIGNATURE REGION

ANNEX 7A EXPANSION OF THE SOUTH / SOUTHEAST ...€¦ · 1.2.1.4 Reactive compensation The reactive...

Documents

Transcript of ANNEX 7A EXPANSION OF THE SOUTH / SOUTHEAST ...€¦ · 1.2.1.4 Reactive compensation The reactive...