Cable Overloading Report

7/27/2019 Cable Overloading Report

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CHAPTER-1

INTRODUCTION

1.1 Underground Electric Transmission Lines (Cables )The electric transmission lines which are installed underground, rather than overhead on poles ortowers are known as underground cables. Underground cables have different technicalrequirements than overhead lines and have different environmental impacts. Due to theirdifferent physical, environmental, and construction needs, underground transmission generallycosts more and may be more complicated to construct than overhead lines.

The design and construction of underground transmission lines differ from overhead linesbecause of two significant technical challenges that need to be overcome. These are: 1) providingsufficient insulation so that cables can be within inches of grounded material; and 2) dissipating

the heat produced during the operation of the electrical cables.

In contrast, a number of different systems, materials, and construction methods have been usedduring the last century in order to achieve the necessary insulation and heat dissipation requiredfor undergrounding transmission lines. The first underground transmission line was a 132 kVline constructed in 1927. The cable was fluid-filled and paper insulated. The fluid was necessaryto dissipate the heat. For decades, reliability problems continued to be associated withconstructing longer cables at higher voltages. The most significant issue was maintenancedifficulties. Not until the mid-1960s did the technology advance sufficiently so that a highvoltage 345 kV line could be constructed underground. The lines though were still fluid filled.This caused significant maintenance, contamination, and infrastructure issues. In the 1990s the

first solid cable transmission line was constructed more than one mile in length and greater than230 kV.

1.2 Underground Transmission in ASETThere are approximately 5 km of transmission lines currently in ASET. Less than one percent ofthe transmission system in ASET is constructed underground. All underground transmissionlines are 138 kV lines or less. There are no 345 kV lines constructed underground, currently inASET.

1.3

Types of Underground Electric Transmission Cables

There are two main types of underground transmission lines currently in use. One type isconstructed in a pipe with fluid or gas pumped or circulated through and around the cable inorder to manage heat and insulate the cables. The other type is a solid dielectric cable whichrequires no fluids or gas and is a more recent technological advancement. The common types ofunderground cable construction include:


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1.3.2 High-Pressure, Gas-Filled Pipe-Type CableThe high-pressure, gas-filled (HPGF) pipe-type of underground transmission line (see Figure 1)is a variation of the HPFF pipe-type, described above. Instead of dielectric oil, pressurizednitrogen gas is used to insulate the conductors. Nitrogen gas is less effective than dielectric fluids

at suppressing electrical discharges and cooling. To compensate for this, the conductorsinsulation is about 20 percent thicker than the insulation in fluid-filled pipes. Thicker insulationand a warmer pipe reduce the amount of current the line can safely and efficiently carry. In caseof a leak or break in the cable system, the nitrogen gas is easier to deal with than the dielectric oilin the surrounding environment.

1.3.3 Self-Contained, Fluid-Filled Pipe-TypeThe self-contained, fluid-filled (SCFF) pipe-type of underground transmission is often used forunderwater transmission construction. The conductors are hollow and filled with an insulatingfluid that is pressurized to 25 to 50 psi. In addition, the three cables are independent of each

other. They are not placed together in a pipe.

Each cable consists of a fluid-filled conductor insulated with high-quality kraft paper andprotected by a lead-bronze or aluminum sheath and a plastic jacket. The fluid reduces the chanceof electrical discharge and line failure. The sheath helps pressurize the conductors fluid and theplastic jacket keeps the water out. This type of construction reduces the risk of a total failure, butthe construction costs are much higher than the single pipe used to construct the HPFF or HPGFsystems.

1.3.4 Solid Cable, Cross-Linked PolyethyleneThe cross-linked polyethylene (XLPE) underground transmission line is often called soliddielectric cable. The solid dielectric material replaces the pressurized liquid or gas of the pipetype cables. XLPE cable has become the national standard for underground electric transmissionlines less than 200 kV. There is less maintenance with the solid cable, but impending insulationfailures are much more difficult to monitor and detect. The diameter of the XLPE cables increasewith voltage.

Figure 2 XLPE Cable for different voltages


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Each transmission line requires three separate cables, similar to the three conductors required forabove ground transmission lines. They are not housed together in a pipe, but are set in concreteducts or buried side-by-side. Each cable consists of a copper or aluminum conductor and a semi-conducting shield at its core. Cross-linked polyethylene insulation surrounds the core. The outercovering of the cable consists of a metallic sheath and a plastic jacket (Figure 3).

Figure 3 XPLE Cable Cross-section

For 345 kV XLPE construction, two sets of three cables (six cables) are necessary for a numberof reasons, primarily so that the capacity of the underground system matches the capacity of theoverhead line. This design aids in limiting the scope of any cable failure and shortens restorationtime in an emergency situation. Most underground transmission requires increased down time forthe repair of operating problems or maintenance issues compared to overhead lines. The doublesets of cables allows for the rerouting of the power through the backup cable set, reducing thedown time but increases the construction footprint of the line.

1.4Ancillary FacilitiesDifferent types of cables require different ancillary facilities. Some of these facilities areconstructed underground, while others are aboveground and may have a significant footprint.When assessing the impacts of underground transmission line construction and operation, theimpacts of the ancillary facilities must be considered, as well.

1.4.1 VaultsVaults are large concrete boxes buried at regular intervals along the underground constructionroute. The primary function of the vault is for splicing the cables during construction and forpermanent access, maintenance, and repair of the cables. The number of vaults required for anunderground transmission line is dictated by the maximum length of cable that can betransported on a reel, the cables allowable pulling tension, elevation changes along the route,and the sidewall pressure as the cable goes around bends. XLPE cable requires a splice every900 to 2000 feet, depending on topography and voltage. Pipe-type cables need a splice at leastevery 3,500 feet. The photos in Figure 4 show examples of vault construction.


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Vaults are approximately 10 by 30 feet and 10 feet high. They have two chimneys constructedwith manholes which workmen use to enter the vaults for cable maintenance. Covers for themanholes are designed to be flush with the finished road surface or ground elevation. Vaults canbe either prefabricated or transported to the site in two pieces or constructed onsite. Excavationsin the vicinity of the vaults will be deeper and wider. Higher voltage construction may require

two vaults constructed adjacent to each other to handle the redundant set of cables.

1.4.2 Transition StructuresFor underground cables less than 345 kV, the connection from overhead to underground linesrequire the construction of a transition structure, also known as a riser. Figures 5 and 6 depictsample transition structure designs. These structures are between 60 and 100 feet tall. They aredesigned so that the three conductors are effectively separated and meet electric coderequirements.

The insulated conductor of the overhead line is linked through a solid insulator device to the

underground cable. This keeps moisture out of the cable and the overhead line away from thesupporting structure.

Lightning arrestors are placed close to where the underground cable connects to the overheadline to protect the underground cable from nearby lightning strikes. The insulating material isvery sensitive to large voltage changes and cannot be repaired. If damaged, a completely newcable is installed.

1.4.3 Transition StationHigh voltage (345 kV or greater) underground transmission lines require transition stations

wherever the underground cable connects to overhead transmission. For very lengthy sections ofunderground transmission, intermediate transition stations might be necessary. The appearanceof a 345 kV transition station is similar to that of a small switching station. The size is governedby whether reactors or other additional components are required. They range in size fromapproximately 1 to 2 acres. Transition stations also require grading, access roads, and stormwater management facilities.

1.4.4 Pressurizing SourcesFor HPFF systems, a pressurizing plant maintains fluid pressure in the pipe. The number ofpressurizing plants depends on the length of the underground lines. It may be located within a

substation. It includes a reservoir that holds reserve fluid. An HPGF system does not use apressurizing plant, but rather a regulator and nitrogen cylinder. These are located in a gas-cabinetthat contains high-pressure and low-pressure alarms and a regulator. The XLPE system does notrequire any pressurization facilities.


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1.5 Construction of Underground TransmissionInstallation of an underground transmission cable generally involves the following sequence ofevents: 1) ROW clearing, 2) trenching/blasting, 3) laying and/or welding pipe, 4) duct bank andvault installation, 5) backfilling, 6) cable installation, 7) adding fluids or gas, and 8) site

restoration. Many of these activities are conducted simultaneously so as to minimize theinterference with street traffic.

1.5.1 Right-Of-Way Construction ZoneSimilar to overhead transmission construction, underground construction begins by staking theROW boundaries and marking sensitive resources. Existing underground utilities are identifiedand marked prior to the start of construction.

If the transmission line is constructed within roadways, lane closures will be required and trafficcontrol signage installed. Construction activities and equipment will disrupt traffic flow. On

average, several hundred feet of traffic lane are closed during construction. When materials andequipment are delivered, additional lengths or lanes of traffic may be closed. Construction areasneed to be wide and level enough to support the movement of backhoes, dump trucks, concretetrucks, and other necessary construction equipment and materials. Undeveloped portions of theroad ROW may require excavation or fill deposited on hillsides so that the surface is levelled andcompact enough for support of the construction equipment. Construction areas in road ROWs aretypically 12 to 15 feet wide with an additional 5 to 8 feet for trench construction.

If the transmission line is to be constructed in unpaved areas, all shrubs and trees are cleared inthe travel path and in the area to be trenched. Temporary easements would be necessary duringconstruction and permanent easements for the life of the transmission line.

1.5.2 Trenching and BlastingMost commonly, a backhoe is used to dig the trench. The excavation starts with the removal ofthe top soil in unpaved areas or the concrete/asphalt in paved areas. Large trucks haul awayexcavated subsoil materials to approved off-site location for disposal, or if appropriate, re-use. Inaccordance with OSHA requirements, trenches of a certain depth may require additional shoring.Trench size will vary depending on the cable type and the lines voltage. Most commonly,trenches are at least 6 to 8 feet deep to keep cables below the frost line. The trench dimensionswill be greater in places where vaults are located.

Urban road ROWs often contain a wide variety of underground obstacles, such as existingutilities, natural features, topography, major roadways, or underpasses. The dimensions of thetrench might need to be deeper and wider to avoid underground obstacles. Every effort should bemade to prevent impacts to existing utilities such as making minor adjustment to the alignmentof the duct bank, relocating the existing utility, or putting the duct bank below the existinginfrastructure. When trenches are excavated deeper than anticipated, the width of the trench mustbe widened for purposes of stability.


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1.5.3 Jack and BoreJack and bore construction is used in areas where open trench construction is obstructed byexisting features such as railroads, waterways, or other large facilities or utilities. It can be usedfor most types of underground cable construction. Entrance and exit pits are excavated to

accommodate the boring equipment and materials. Typical boring pits are around 14 by 35 feet,and deep enough to accommodate the boring equipment. An auger is used in the entrance pit toexcavate a hole and remove spoils. A jack pushes a reinforced pipe in sections behind the augerhead. When the pipe is installed, the conduit is surrounded by bore spacers and the conduit ispushed into the casing pipe.

The casing pipe is then backfilled with a material that optimizes thermal radiation. Lastly, theentrance and exit pits are restored to their original condition. Typically construction lay downareas are equal to the length of bore to facilitate the welding of the pipe that is installed into thebore hole. The bore entry site may be as much as 150 feet long to handle the drilling equipmentand management of the slurry.

1.5.4 Conduit Assembly for XLPE ConstructionThe assembly of conduits and direct-buried method of XLPE construction are illustrated inFigures 11, 12, and 13. Underground XLPE cable systems can be direct-buried or encased inconcrete duct banks. For duct bank installation, the trench is first excavated a couple hundredfeet. This is because the construction technique provides more mechanical protection, reducesthe need for re-excavation in the event of a cable failure, and shorter lengths of trench are openedat any one time for construction and maintenance activities.

Figure 4 Installation of XLPE Underground Cable Directly Buried


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1.5.5 Pipe InstallationHPFF and HPGF pipe-type installation requires the construction of welded steel pipe sections tohouse the cables. The welding of pipe sections takes place either in or over the trench. Pipewelds are X-rayed, and then protected from corrosion with plastic coatings. When the pipe is

completely installed, it is pressure tested with either air or nitrogen gas. It is then vacuum-tested,vault to vault, which also dries the pipe. Figure 14 show the cross-section for an HPFF or HPGFpipe-type underground transmission line.

Figure 5 Installation of HPFF or HPGF Pipe-Type Underground Cable

1.5.6 Cable InstallationCable pulling and splicing can occur any time after the duct banks and vaults are completed.Prior to installation of the cable, the conduit is tested and cleaned by pulling a mandrel and swabthrough each of the ducts. A typical setup is to lace the reel of cable at the transition structure orat one of the vaults and the winch truck at the next vault. The cable is then pulled from thetransition structure to the nearest vault. Direction of pull between vaults is based on the directionthat results in the lowest pulling and sidewall tensions. Cable lengths are spliced within thevaults.

1.5.7 BackfillingPipe-type conductors operate at about 167 to 185 F with an emergency operating temperature of212 to 221 F. XLPE conductors operate at about 176 to 194 F with an emergency operatingtemperature of about 266 F. Heat must be carried away from the conductors for them to operateefficiently. The air performs this function for overhead lines. The soils in and around the trench


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do this for underground lines. All of the heat generated from direct buried cables must bedissipated through the soil. The selection of backfill type can make a strong difference on thecapacity rating. Different soils have different abilities to transfer heat. Saturated soils conductheat more easily than for instance, sandy soils. For this reason, the design needs to determine thetype of soil nearest the line. A soil thermal survey may be necessary before construction to help

determine the soils ability to move heat away from the line. In many cases, a special backfillmaterial is used instead of soil in the trench around the cables to ensure sufficient heat transfer tothe surrounding soils and groundwater.

1.5.8 Site RestorationSite restoration for underground construction is similar to overhead transmission lineconstruction restoration. When construction is completed, roadways, landscaped areas, andundeveloped areas are restored to their original condition and topography (Figure 16). Highwaylands and shoulders are re-constructed so as to support road traffic. Roadside areas andlandscaped private properties are restored with top soils that was previously stripped and

stockpiled during construction or with new topsoil. Any infrastructure impacted by theconstruction project such as driveways, curbs, and private utilities are restored to their previousfunction, and yards and pastures are vegetated as specified in landowner easements.

1.6Underground Construction ConsiderationsUnderground construction could be a reasonable alternative to overhead in urban areas where anoverhead line cannot be installed with appropriate clearance, at any cost. In suburban areas,aesthetic issues, weather-related outages, some environmental concerns, and the high cost ofsome ROWs could make an underground option more attractive. Underground transmissionconstruction is most often used in urban areas. However, underground construction may be

disruptive to street traffic and individuals because of the extensive excavation necessary. Duringconstruction, barricades, warning and illuminated flashing signs, are often required to guidetraffic and pedestrians. After each days work, steel plates will cover any open trench. All openconcrete vaults will have a highly visible fence around them. When the cable is pulled into thepipe, the contractor should cordon off the work area. There may be time-of-day or work weeklimitations for construction activities in roadways that are imposed for reasons of noise, dust, andtraffic impacts. These construction limitations often increase the cost of the project.The trenching for the construction of underground lines causes greater soil disturbance thanoverhead lines. Overhead line construction disturbs the soil mostly at the site of eachtransmission pole. Trenching an underground line through farmlands, forests, wetlands, andother natural areas can cause significant land disturbances.

Many engineering factors significantly increase the cost of underground transmission facilities.As the voltage increases, engineering constraints and costs dramatically increase. This is thereason why underground distribution lines (12 - 24 kV) are not uncommon; whereas, there is justover 100 miles of underground transmission currently in the state. There are also no 345 kVunderground segments in Wisconsin.


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1.7Construction Impacts in Suburban and Urban AreasThe construction impacts of underground lines are temporary and, for the most part, reversible.They include dirt, dust, noise, and traffic disruption. Increased particles in the air can cause healthe problems for people who live or work nearby. Particularly sensitive persons include the very

young, the very old, and those with health problems, such as asthma. If the right-of-way is in aresidential area, construction hours and the amount of equipment operating simultaneously mayneed to be limited to reduce noise levels. In commercial or industrial areas, special measuresmay be needed to keep access to businesses open or to control traffic during rush hours.

1.8CostsThe estimated cost for constructing underground transmission lines ranges from 4 to 14 timesmore expensive than overhead lines of the same voltage and same distance. A typical new 69 kVoverhead single-circuit transmission line costs approximately $285,000 per mile as opposed to$1.5 million per mile for a new 69 kV underground line (without the terminals). A new 138 kV

overhead line costs approximately $390,000 per mile as opposed to $2 million per mile forunderground (without the terminals).

These costs are determined by the local environment, the distances between splices andtermination points, and the number of ancillary facilities required. Other issues that makeunderground transmission lines more costly are right-of-way access, start-up complications,construction limitations in urban areas, conflicts with other utilities, trenching constructionissues, crossing natural or manmade barriers, and the potential need for forced cooling facilities.Other transmission facilities in or near the line may also require new or upgraded facilities tobalance power issues such fault currents and voltage transients, all adding to the cost.

While it may be useful to sometimes compare the general cost differences between overhead andunderground construction, the actual costs for underground may be quite different. Undergroundtransmission construction can be very site-specific, especially for higher voltage lines.Components of underground transmission are often not interchangeable as they are for overhead.A complete in-depth study and characterization of the subsurface and electrical environment isnecessary in order to get an accurate cost estimate for undergrounding a specific section oftransmission. This can make the cost of underground transmission extremely variable whencalculated on a per-mile basis.

1.8.1 Underground Operating ConsiderationsPost-construction issues such as aesthetics, electric and magnetic fields (EMF), and propertyvalues are usually less of an issue for underground lines. Underground lines are not visible afterconstruction and have less impact on property values and aesthetics. Apart from cost andconstruction issues, there are continued maintenance and safety issues associated with the right-of-way. The right-of-way must be kept safe from accidental contact by subsequent constructionactivities. To protect individual ducts (for SCFF and XLPE lines) against accidental future dig-ins, a concrete duct bank, a concrete slab, or patio blocks are installed above the line, along witha system of warning signs (high-voltage buried cable).


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Additionally, if the cables are not constructed under roads or highways, the ROW must be keptclear of vegetation with long roots such as trees that could interfere with the system.

1.8.2 Cable RepairRepair costs for an underground line are usually greater than costs for an equivalent overheadline. Leaks can cost $50,000 to $100,000 to locate and repair. A leak detection system for aHPFF cable system can cost from $1,000 to $400,000 to purchase and install depending on thesystem technology. Moulded joints for splices in XLPE line could cost about $20,000 to repair.Field-made splices could cost up to $60,000 to repair. A fault in a directionally drilled section ofthe line could require replacement of the entire section.For example, the cost for directional drilling an HPGF cables is $25 per foot per cable. Thecables in the directional drilled section twist around each other in the pipe so they all would haveto be pulled out for examination. The newer XLPE cables tend to have a life that is one half of anoverhead conductor which may require replacing the underground every 35 years or so.Easement agreements may require the utility to compensate property owners for disruption in

their property use and for property damage that is caused by repairing underground transmissionlines on private property. However, the cost to compensate the landowner is small compared tothe total repair costs. Underground transmission lines have higher life cycle costs than overheadtransmission lines when combining construction repair and maintenance costs over the life of theline.

1.9Reliability of ServiceIn general, lower voltage underground transmission lines are very reliable. However, their repairtimes are much longer than those for overhead lines.

1.9.1 Repair Rates Pipe-Type Transmission CablesFor pipe-type lines, the trouble rates historically, for about 2,536 miles of line correspond toabout:

One cable repair needed per year for every 833 miles of cable.

One splice repair needed per year for every 2,439 miles of cable.

One termination repair needed per year for every 359 miles of cable.These trouble rates indicate that there would be, at most, a 1:300 chance for the most commontype of repair to be needed in any one mile of pipe-type underground line over any one year.

1.9.2 Repair Rates - XLPE linesThere is less available documentation regarding XLPE trouble rates and very little informationfor 345 kV transmission lines. However, the following estimates are generally accepted.

One cable repair needed per year for every 1,000 miles of cable.

One splice repair needed per year for every 1,428 miles of cable.

One termination repair needed per year for every 1,428 miles of cable.


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These trouble rates indicate that there would be, at most, a 1:1,000 chance for the most commontype of repair to be needed in any one mile of XLPE underground line over any one year.

1.9.3 Outage DurationThe duration of outages varies widely, depending on the circumstances of the failure, theavailability of parts, and the skill level of the available repair personnel. The typical duration ofan HPGF outage is 8 to 12 days. The duration of typical XLPE outages is 5 to 9 days. The repairof a fault in a HPFF system is estimated to be from 2 to 9 months, depending on the extent of thedamage.

The outage rate would increase as the number of splices increases. However, the use of concretevaults at splice locations can reduce the duration of a splice failure by allowing quick and cleanaccess to the failure. The outage would be longer if the splice were directly buried, as issometimes done with rural or suburban XLPE lines.

To locate a leak in a pipe-type line, the pipe pressure must be reduced below 60 psi and the linede-energized before any probes are put into the pipe. For some leak probes, the line must be outof service for a day before the tests can begin. After repairs, pipe pressure must be returned tonormal slowly. This would require an additional day or more before the repaired line could beenergized.

To locate an electrical fault in an underground line, the affected cable must be identified. Torepair a pipe-type line, the fluid on each side of the electrical failure would be frozen at least 25feet out from the failure point. Then, the pipe would be opened and the line inspected. Newsplices are sometimes required and sometimes cable may need to be replaced and spliced. Then,the pipe would be thawed and the line would be re-pressurized, tested, and finally put back in

service.

In contrast, a fault or break in an overhead line can usually be located almost immediately andrepaired within hours or, at most, a day or two. One problem that increases emergency responsetime for underground transmission lines is that most of the suppliers of undergroundtransmission materials are in Europe. While some of the European companies keep American-based offices, cable and system supplies may not be immediately available for emergencyrepairs.

1.9.4 Line Life ExpectanciesWhile the assumed life of underground pipe-type or XLPE cable is about 40 years, there arepipe-type cables that has been in service for more than 60 years. Overhead lines in northernWisconsin last 60 plus years. There are some overhead lines that have lasted more than 80 years.


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Role of the Public Service Commission

For most large underground or overhead transmission lines, the utility must apply to the PublicService Commission (PSC) for approval prior to building the line. An applicant must receive aCertificate of Public Convenience and Necessity (CPCN) from the Commission for a

transmission project that is either:

345 kV or greater; or,

Less than 345 kV but greater than or equal to 100 kV, over one mile in length, andrequiring new right-of-way (ROW).

All other transmission line projects must receive a Certificate of Authority (CA) from theCommission if the projects cost is above a certain percent of the utilitys annual revenue. Therequirements for these certificates are specified in Wis. Stat. 196.49 and 196.491.

The Public Service Commission of Wisconsin is an independent state agency that oversees more

than 1,100 Wisconsin public utilities that provide natural gas, electricity, heat, steam, water andtelecommunication services.


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CHAPTER-2

XLPE CABLE STANDARDS AND CABLE SIZING

XLPE cable systems are designed to meet requirements in international and/or national

standards. Some of these are listed below.

2.1 IEC StandardsXLPE cable systems specified according to IEC (International Electrotechnical Commission) areamong many other standards accepted. IEC standards are considered to express an internationalconsensus of opinion. Some frequently used standards are:

IEC 60228Conductors of insulated cables.

IEC 60287

Electric cables - Calculation of the current rating.

IEC 60332

Tests on electric cables under fire conditions.

IEC 60502

Power cables with extruded insulation and their accessories for rated voltage from 1 kV (Um=1,2 kV) up to 30 kV (Um=36 kV).

IEC 60840

Power cables with extruded insulation and their accessories for rated voltage above 30 kV(Um=36 kV) up to 150 kV (Um=170 kV). Test methods and requirements.

IEC 60853Calculation of the cyclic and emergency current rating of cables.

IEC 61443

Short-circuit temperature limits of electric cables with rated voltages above 30 kV (Um=36 kV).

IEC 62067

Power cables with extruded insulation and their accessories for rated voltage above 150 kV

(Um=170 kV) up to 500 kV (Um=550 kV). Test methods and requirements.

2.2 ICEA StandardsFor North America cables are often specified according to ICEA (Insulated Cable EngineersAssociation, Inc.).


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S-97-682Standard for utility shielded power cables rated 5-46 kV.

S-108-720Standard for extruded insulated power cables rated above 46 through 345 kV.

2.3 Cable SizingSTANDARDS AND CODES

IEC-287 Conductor size calculation method, Thermal Conductivity

IEE Wiring Regulations, 16th Edition & ERA Report 69-30, Part 1 & 3 for De-

Rating Factors

IEE Recommendations for the Electrical and Electronic Equipment of Mobile and

fixed Offshore installations KOC-E-008(Clause 6.2.1)- Current carrying Capacity, 6.2.2 & 6.2.3 De-rating

factors, 6.3-Voltage drop

KOC-G-007(Clause- 5.1.5) - Soil temperature at 1.22 m depth: max. 35 C, min.

17C. A design of 40C shall be used for cable system design calculations.

KOC-G-007(Clause - 5.10.3)- Soil Resistivity for use in cable designs shall be 2

Km/w

KOC-E-023(Clause5.0) - Electrical Components and Materials shall be designedfor continuous operation under ambient temperatures of 50 C in the shade. For

buried cables a design temperature of 40 C shall be used.

DATA COLLECTION

a) Interaction with Mechanical Engineer: for pump/compressor/ Blowers etc.drivers - BHP estimated power requirement

b) Interaction with Instrumentation Engineer: for DCS/ESD/Fire alarm/ detectorSystem/ Public Address System etc. and other Instrumentation loads

c) Interaction with HVAC Engineer: for HVAC loads

d) Interaction with Civil Engineer: for Civil loads if any

e) Assess the Lighting and other utility load requirements


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PREPARE THE LOAD LIST

Estimate the Power Factors, use the efficiency of individual loads, and arrive at the inputpower requirement in KW. Assess the motor feeders at full load current & starting current.

Full Load Current (IFL) = P/((3) *V*Cos*) Amps

P = Rated Load (KW) (Output Power)

V =Rated Voltage (KV)

Cos = Power Factor

Efficiency () = Output power/Input Power

Input power = Output power + Losses

SELECT THE METHOD OF INSTALLATION & TYPE OF CABLE

Determine the possible route & route length. Select the type of cable based on method ofinstallation

a) XLPE/SWA/PVC for outside the operating areas

b) XLPE/LC/SWA/PVC for inside the production facility

c) XLPE/SWA/PVC - for inside substation that are intended to be on the trays.

DETAILS OF INSTALLATION & CALCULATION OF DERATING

FACTORS

Assess the degree of derating factor based on following cable (XLPE) installation methods

1.

In Air2. In ground / Duct


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In Air:

i) Select the air temperature is 50 C as derating factor is 0.85 (as per manufacture

Catalogue)

ii) Group rating factor for multi core cables (600/1000V) with spacing 0.15m is 0.7

(3CKT), 0.57 for 6 CKT

In Ground:

i) Select the ground temperature is 40 C as the derating factor from manufacturer

catalogue is 0.82

ii) The grouping factor for LT Cables spacing of 0.15M, the derating factor is 0.74


iii) The grouping factor for HT Cables spacing of 0.15M, the derating factor is 0.71


iv)

Depth of Laying

1) For LT cables (750 mm depth), derating factor is 0.962) For HT cables (1000 mm depth), derating factor is 0.93

FINALIZATION OF CABLE SIZE

Assessment of Derated current of cable under site installed conditions:Site Installed Current (SIC) ,SIC = Ia x D.F (A)

Ia = Allowable load current (Amps) (as per manufacturers catalogue)

D.F = Derating factor (%)

D.F = (Grouping Factor)* (Direct In Ground) *(Depth of laying) *(Thermal Resistivity of

Soil)

Calculate the Voltage Drop of the each cable :

Voltage Drop (Vd) = 3 * I(RCOS + X SIN ) L ---- (IEEE 3.11)

I (IFL) = Full load Current (A)

R = Resistance (/KM)

X = Reactance (/KM)

COS = Load Power Factor

SIN = Load Reactive Factor


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L = Length of the cable (KM)

Check the voltage drop limits as per manufacturer

For feeders to and from area Substations- 1%

For lighting circuit is less than 2.5% For HV Motor the voltage drop at motor terminals shall not exceed 3% at full load and

15% during starting

For LV motors voltage drop at motor terminal shall not exceed 5% and 15% during

starting.

Short Circuit Rating of Cable:

Check the characteristic of protective device provided at source end for protection of

the cable.

i) Derated current of cable is more than current protecting element.

ii)Short circuit withstand capacity of the cable is more than that of the actual fault

current, considering fault clearance time

Where, A = Conductor area in sqmm.

t = Short circuit time in Sec.

Check final load list:

Check the actual Power Factors, use the efficiency of individual loads, and verify the

input power requirement in KW/ current. Check the method of installation & type of cable based on the information in cable

catalogue.

Check the details of Installation & Assessment of de-rating factors are based on

information in cable catalogue.

Finalization of cable size : The following points are calculated base on information

obtained

Check the derated current of cable under site installed condition

Check the Voltage drop :Voltage drop calculated based on the formula

(IEEE 3.11)

Coordination with protective device

Check the short circuit current & time, and ensure that selected cables are

fully protected.


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CHAPTER-3

MODEL DEVELOPMENT

3.1 Overview of MiPower PackageMiPower package aids the power system engineer during operational or planning stages of apower system. This package is extensively useful for power utilities, industries, research andeducational institutions. The package is designed to work with all operating systems. Thepackage offers the following features:

User-friendly GUI to generate power system single line diagrams and reports.

A centralised database to store power system elements information.

Automatic single line diagram generation for a given network topology. Plotting of linear/semi-log/log curves with multiple X/Y variables.

Batch mode facility to create a centralized database for very large networks.

The package is interfaced with many power system application modules.

Print/Plot support for single line diagrams and reports.

Porting of single line diagram to/from AutoCAD.

The package comes with an interface to the following power system applications

Power Flow Analysis

Fault Analysis

Optimal Power Flow Contingency Analysis.

Over Current Relay co-ordination

Stability Analysis

- Transient Stability Analysis- Dynamic Stability Analysis- Voltage Instability Analysis- Network Reduction- Sub-Synchronous Resonance

Electro-Magnetic Transient Analysis

Harmonic Analysis Long Term Load Forecast

Line Parameter Calculation

Cable Parameter Calculation

Power flow analysis program computes the voltage magnitudes, phase angles and power flows(MW/kW, MVA/kVA, MVAr/kVAr) for a network under steady state operating conditions.


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Stability programs are used to study dynamics of power systems under disturbance conditionsto determine whether synchronous generators and motors remain in synchronism. Systemdisturbances may be caused by the sudden loss of a generator or transmission line, by suddenload increase or decrease and by short circuits and switching operations. The stability programcombines power flow equations and machine dynamic equations to compute the angular swings

of machines during disturbances. The program also computes the critical clearing times fornetwork faults and allows the engineer to investigate the effects of various machine parameters,network modifications, disturbance types and control schemes.

3.2 System Model


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3.3 Results from simulation of preliminary modelLoad Flow Analysis is one of the most common computational procedures used in powersystem analysis. The load flow problem can be defined as: Given the load power consumption atall buses of a known electric power system configuration and the power

generation at each generator, find the power flow in each line and transformer of theinterconnecting network and the voltage magnitude and phase angle at each bus.

Analysing the solution of this problem for numerous conditions helps to ensure that the powersystem is designed to satisfy its performance criteria while incurring the most favourableinvestment and operation costs. Planning, design and operation of power systems require suchcalculations to

Analyse steady-state performance of the power system under various operatingconditions.

Study the effects of change in equipment configuration.

Given the power consumption at all buses of a known electric power system configuration andthe power production at each generator, load flow analysis program, PowerLFA calculates thepower flow in each line and transformer of the interconnecting network and the voltagemagnitude and angle at each bus.

Load flow programs are divided into two types - static (off-line) and dynamic (real time).Mostload flow studies for system analysis are based on static network models. Real time load flowsthat incorporate data inputs from the actual networks are typically used by utilities inSupervisory Control And Data Acquisition (SCADA) systems. Such systems are used primarilyas operating tools for optimisation of generation, var control, dispatch, losses and tie-line control.

Since load flow problem pertains to balanced, steady state operation of power systems, a singlephase, positive sequence model of the power system is used.


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CHAPTER-4

INPUT DATA FOR BUS, TRANSFORMER, TRANSMISSION LINE

AND LOAD

4.1 Bus DataBUS NO. BUS KV VMIN-PU VMAX-PU

1 33 0.95 1.05

2 33 0.95 1.05

4 33 0.95 1.05

7 0.415 0.95 1.05

8 0.415 0.95 1.05

13 0.415 0.95 1.05

14 0.415 0.95 1.0515 0.415 0.95 1.05

16 0.415 0.95 1.05

17 0.415 0.95 1.05

18 0.415 0.95 1.05

19 0.415 0.95 1.05

21 0.415 0.95 1.05

22 0.415 0.95 1.05

23 0.415 0.95 1.05

25 0.415 0.95 1.05

30 0.415 0.95 1.0534 0.415 0.95 1.05

35 0.415 0.95 1.05

36 0.415 0.95 1.05

37 0.415 0.95 1.05

38 0.415 0.95 1.05

39 0.415 0.95 1.05

40 0.415 0.95 1.05

41 0.415 0.95 1.05

43 0.415 0.95 1.05

52 0.415 0.95 1.0574 0.415 0.95 1.05

78 0.415 0.95 1.05


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4.2Transformer DataFROM TO IMPE DANCE NOMINAL RATING

NAME* NAME* R(P.U) X(P.U.) TAP MVA

MINTAP MAXTAP TAPSTEP SHIFT-DE

Bus4 Bus7 0.00104 0.02081 1 3

0.95 1.05 0.0125 0

Bus4 Bus8 0.00104 0.02081 1 3

0.95 1.05 0.0125 0

Bus2 Bus96 0.00104 0.02081 1 3

0.95 1.05 0.0125 0

Bus96 Bus13 0.00208 0.04161 1 1.5

0.95 1.05 0.0125 0

4.3Transmission Line DataFROM TO L

INEPARAME TER RATING

KMSkV

NAME* NAME* R(P.U) X(P.U.) B/2(P.U.) MVA

Bus1 Bus2 0.00012 0.00007 0 5 0.2

Bus2 Bus4 0.00012 0.00007 0 9 0.2

Bus13 Bus14 0.20032 0.11619 0 0 0.2

Bus13 Bus15 0.1829 0.10608 0 0 0.2

Bus13 Bus16 0.20903 0.1498 0 0 0.3

Bus13 Bus17 0.33096 0.19196 0 0 0.4

Bus13 Bus18 0.31296 0.03821 0 0 0.1

Bus13 Bus19 0.20903 0.09093 0 0 0.2

Bus13 Bus22 0.32516 0.14144 0 0 0.3

Bus13 Bus23 0.05806 0.02021 0 0 0

Bus13 Bus25 0.10161 0.03536 0 0 0.1

Bus8 Bus34 0.06968 0.04993 0 1 0.2

Bus8 Bus35 0.06968 0.04993 0 0 0.2

Bus8 Bus36 0.06968 0.04993 0 2 0.2

Bus8 Bus37 0.07258 0.02526 0 0 0.1

Bus37 Bus38 0.30193 0.02526 0 0 0.1

Bus37 Bus39 0.10887 0.03789 0 0 0.1Bus8 Bus40 0.33677 0.14649 0 0 0.3

Bus8 Bus41 0.13064 0.07577 0 0 0.1

Bus8 Bus43 0.00376 0.00449 0 1 0

Bus8 Bus74 1.16127 0.50515 0 0 1

Bus8 Bus74 0.58064 0.25258 0 0 1

Bus8 Bus78 0.20903 0.09093 0 0 0.2


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4.4Generator DataFROM REAL Q-MIN Q-MAX V-SPEC CAP. MVA STAT

NAME* POWER(MW) MVAR MVAR P.U. CURV RATING

Bus1 80 0 60 1 0 100 3

Bus90 2.97 0 0.423 1 0 3 0

Bus91 0.4 0 0.3 1 0 0.5 0

Bus105 0.96 0 0.72 1 0 1.2 0

4.5Load DataFROM

NAME*

REAL

MW

REACTIVE

MVARBus38 0.085 0.012

Bus40 0.057 0.008

Bus41 0.014 0.002

Bus25 0.099 0.014

Bus23 0.2 0.029

Bus18 0.045 0.006

Bus17 0.065 0.009

Bus16 0.121 0.017

Bus15 0.064 0.009

Bus14 0.144 0.02

Bus78 0.198 0.028


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CHAPTER-5

RESULTS AND DISCUSSION

5.1 Transformer flows and Transformer lossesFROM TO FORWARD LOSS %

NAME NAME MVA ANG-DEG MW MVAR LOADING

Bus4 Bus7 3.150 15.656 0.0104 0.2071 105.2@

Bus4 Bus8 3.136 12.940 0.0103 0.2052 104.7@

Bus2 Bus96 1.808 15.619 0.0034 0.0681 60.3$

Bus96 Bus13 1.787 13.554 0.0068 0.1361 120.6@

NUMBE OF TRANSFORMERS LOADED BEYOND 125% 0

NUMBER OF TRANSFORMERS LOADED BETWEEN 100% AND 125% 3






5.2 Bus Voltages and PowersNODE FROM

V-

MAG ANGLE MVA

ANG-

DEG MVA ANG-DEG MVARNO. NAME P.U. DEGREE GEN GEN LOAD LOAD COMP

1 Bus1 1 0 8.101 14.592 0 -90 0

2 Bus2 0.9995 -0.01 0 -90 0 -90 0

4 Bus4 0.9987 -0.02 0 -90 0 -90 0

7 Bus7 0.9798 -3.67 0 -90 0 -90 0

8 Bus8 0.9829 -3.69 0 -90 0 -90 0

13 Bus13 0.9696 -6.36 0 -90 0 -90 0

14 Bus14 0.9362 -7.15 0 -90 0.145 8.108 0

15 Bus15 0.9562 -6.67 0 -90 0.065 8.11 0

16 Bus16 0.9398 -7.27 0 -90 0.122 8.11 0


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NUMBER OF BUSES EXCEEDING MINIMUM VOLTAGE LIMIT (@ mark) : 19

NUMBER OF BUSES EXCEEDING MAXIMUM VOLTAGE LIMIT (# mark) : 0

NUMBER OF GENERATORS EXCEEDING MINIMUM Q LIMIT (< mark) : 0

NUMBER OF GENERATORS EXCEEDING MAXIMUM Q LIMIT (> mark) : 0

5.3 Line flows and Line lossesFROM TO FORWARD LOSS %

NAME NAME MVA ANG-DEG MW MVAR LOADING

Bus1 Bus2 4.05 14.592 0.0019 0.0011 81.0#

Bus2 Bus4 6.289 14.286 0.0046 0.0026 70.1$Bus13 Bus14 0.15 8.902 0.0048 0.0028 78.3#

Bus13 Bus15 0.066 8.428 0.0008 0.0005 34.4^

Bus13 Bus16 0.126 9.021 0.0035 0.0025 59.2$

Bus13 Bus17 0.067 8.693 0.0016 0.0009 35.0^

Bus13 Bus18 0.046 8.094 0.0007 0.0001 65.6$

Bus13 Bus19 0.161 8.705 0.0058 0.0025 98.4#

Bus13 Bus22 0.104 8.708 0.0037 0.0016 63.5$

Bus13 Bus23 0.205 8.259 0.0026 0.0009 97.9#

Bus13 Bus25 0.101 8.239 0.0011 0.0004 69.1$

Bus8 Bus34 0.527 9.387 0.02 0.0144 49.7^

Bus8 Bus35 0.392 9.031 0.0111 0.0079 91.0#Bus8 Bus36 0.752 9.876 0.0408 0.0292 44.3^

Bus8 Bus37 0.301 8.537 0.0068 0.0024 94.7#

Bus37 Bus38 0.089 8.014 0.0026 0.0002 85.9#

Bus37 Bus39 0.205 8.391 0.005 0.0017 99.2#

Bus8 Bus40 0.058 8.444 0.0012 0.0005 35.2^

Bus8 Bus41 0.014 8.145 0 0 7.4&

Bus8 Bus43 0 -90 0 0 0.0*

Bus8 Bus74 0 173.25 0 0 0.0*

Bus8 Bus74 0 173.25 0 0 0.0*

Bus8 Bus78 0.21 8.863 0.0095 0.0042 99.1#Bus13 Bus83 0.493 10.94 0.0841 0.0366 94.3#

Bus13 Bus84 0.128 8.475 0.0028 0.0012 78.2#

Bus13 Bus21 0.107 9.166 0.0068 0.003 65.4$

Bus7 Bus30 3.091 12.01 0.0052 0.005 90.1#

Bus90 Bus4 0 -18.264 0 0.0016 0.3*

Bus91 Bus4 0 -18.264 0 0.0016 0.3*


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After running the load flow two transformer are overloaded i.e 33/0.4kV , 3 MVA HT PANELSand 33/11kV, 3 MVA LT PANEL 1 shown in transformer flows and transformer losses outputabove. Due to this overloading , line losses and bus power flow are increased.

Improvement

Now instead of changing or installing new set of cable lines, we increased the capacity of cableby making it double circuit. When increasing the transformer capacities following results areobtained:-

5.4 Result with increased line capacityTransformer Data

FROM TO IMPE DANCE NOMINAL RATING

NAME* NAME* R(P.U) X(P.U.) TAP MVA

MINTAP MAXTAP TAPSTEP SHIFT-DE

Bus4 Bus7 0.00089 0.01783 1 3.50.95 1.05 0.0125 0

Bus4 Bus8 0.00089 0.01783 1 3.5

0.95 1.05 0.0125 0

Bus2 Bus96 0.00104 0.02081 1 3

0.95 1.05 0.0125 0

Bus96 Bus13 0.00156 0.03121 1 2

0.95 1.05 0.0125 0

! NUMBER OF LINES LOADED BEYOND 125% : 0

@ NUMBER OF LINES LOADED BETWEEN 100% AND 125% : 0

# NUMBER OF LINES LOADED BETWEEN 75% AND 100% : 18

$ NUMBER OF LINES LOADED BETWEEN 50% AND 75% : 6

^ NUMBER OF LINES LOADED BETWEEN 25% AND 50% : 5

& NUMBER OF LINES LOADED BETWEEN 1% AND 25% : 1

* NUMBER OF LINES LOADED BETWEEN 0% AND 1% : 6


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Output:

Transformer flows and Transformer Losses

FROM TO FORWARD LOSS %

NAME NAME MVA ANG-DEG

MW MVAR LOADING

Bus4 Bus7 3.141 15.105 0.0088 0.1765 89.9#

Bus4 Bus8 3.126 12.398 0.0087 0.1748 89.4#

Bus2 Bus96 1.794 14.499 0.0034 0.0670 59.8$

Bus96 Bus13 1.775 12.439 0.0050 0.1006 89.8#

! NUMBER OF TRANSFORMERS LOADED BEYOND 125% : 0

@ NUMBER OF TRANSFORMERS LOADED BETWEEN 100% AND 125% : 0

# NUMBER OF TRANSFORMERS LOADED BETWEEN 75% AND 100% : 3$ NUMBER OF TRANSFORMERS LOADED BETWEEN 50% AND 75% : 1

^ NUMBER OF TRANSFORMERS LOADED BETWEEN 25% AND 50% : 0

& NUMBER OF TRANSFORMERS LOADED BETWEEN 1% AND 25% : 0

* NUMBER OF TRANSFORMERS LOADED BETWEEN 0% AND 1% : 0

Bus Voltages and Powers

FROM V-MAG ANGLE MVA ANG-DEG MVA ANG-DEG MVAR

NAME P.U. DEGREE GEN GEN LOAD LOAD COMP

Bus1 1 0 8.068 13.917 0 -90 0

Bus2 0.9995 -0.01 0 -90 0 -90 0

Bus4 0.9987 -0.02 0 -90 0 -90 0

Bus7 0.9828 -3.14 0 -90 0 -90 0

Bus8 0.9854 -3.16 0 -90 0 -90 0

Bus13 0.9757 -5.26 0 -90 0 -90 0

Bus14 0.9425 -6.04 0 -90 0.145 8.108 0

Bus15 0.9624 -5.57 0 -90 0.065 8.11 0


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NUMBER OF BUSES EXCEEDING MINIMUM VOLTAGE LIMIT (@ mark) : 17

NUMBER OF BUSES EXCEEDING MAXIMUM VOLTAGE LIMIT (# mark) : 0

NUMBER OF GENERATORS EXCEEDING MINIMUM Q LIMIT (< mark) : 0

NUMBER OF GENERATORS EXCEEDING MAXIMUM Q LIMIT (> mark) : 0

Line flows and Line losses

FROM TO TO FORWARD LOSS %

NAME NODE NAME MVA ANG-DEG MW MVAR LOADING

Bus1 2 Bus2 4.034 13.917 0.0019 0.0011 80.7#

Bus2 4 Bus4 6.27 13.74 0.0046 0.0026 69.9$

Bus13 14 Bus14 0.15 8.892 0.0047 0.0027 77.8#

Bus13 15 Bus15 0.066 8.424 0.0008 0.0005 34.2^

Bus13 16 Bus16 0.126 9.009 0.0035 0.0025 58.8$Bus13 17 Bus17 0.067 8.686 0.0016 0.0009 34.8^

Bus13 18 Bus18 0.046 8.095 0.0007 0.0001 65.1$

Bus13 19 Bus19 0.161 8.698 0.0057 0.0025 97.7#

Bus13 22 Bus22 0.104 8.7 0.0037 0.0016 63.0$

Bus13 23 Bus23 0.205 8.257 0.0026 0.0009 97.3#

Bus13 25 Bus25 0.101 8.237 0.0011 0.0004 68.7$

Bus8 34 Bus34 0.527 9.38 0.0199 0.0143 49.6^

Bus8 35 Bus35 0.392 9.026 0.011 0.0079 90.7#

Bus8 36 Bus36 0.752 9.866 0.0405 0.0291 44.2^

Bus8 37 Bus37 0.301 8.535 0.0068 0.0024 94.4#

Bus37 38 Bus38 0.089 8.015 0.0026 0.0002 85.6#Bus37 39 Bus39 0.205 8.39 0.0049 0.0017 98.9#

Bus8 40 Bus40 0.058 8.443 0.0012 0.0005 35.1^

Bus8 41 Bus41 0.014 8.145 0 0 7.4&

Bus8 43 Bus43 0 -90 0 0 0.0*

Bus8 74 Bus74 0 -145.614 0 0 0.0*

Bus8 74 Bus74 0 -145.614 0 0 0.0*

Bus8 78 Bus78 0.21 8.859 0.0095 0.0041 98.8#

Bus13 83 Bus83 0.491 10.895 0.0825 0.0359 93.4#

Bus13 84 Bus84 0.128 8.471 0.0028 0.0012 77.6#

Bus13 21 Bus21 0.107 9.152 0.0067 0.0029 65.0$

Bus7 30 Bus30 3.092 11.988 0.0052 0.0049 89.9#

Bus90 4 Bus4 0 -85.207 0 0.0016 0.3*

Bus91 4 Bus4 0 -85.207 0 0.0016 0.3*

Bus30 100 Bus100 1.108 10.725 0.089 0.0638 98.2#

Bus30 101 Bus101 0.913 13.33 0.2868 0.1248 95.9#

Bus30 102 Bus102 1.065 11.95 0.2462 0.1071 94.4#


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! NUMBER OF LINES LOADED BEYOND 125% : 0

@ NUMBER OF LINES LOADED BETWEEN 100% AND 125% : 0

# NUMBER OF LINES LOADED BETWEEN 75% AND 100% : 18

$ NUMBER OF LINES LOADED BETWEEN 50% AND 75% : 6

^ NUMBER OF LINES LOADED BETWEEN 25% AND 50% : 5

& NUMBER OF LINES LOADED BETWEEN 1% AND 25% : 1

* NUMBER OF LINES LOADED BETWEEN 0% AND 1% : 6


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CHAPTER-6

PRESENT WORTH ANALYSIS

In the power system analysis viability of any project depends on both technical and commercialfeasibility. While tools like load flow analysis decides the technical feasibility, present worthanalysis can be used to decide the economic viability of the project. Given the data, presentworth analysis is done to determine the feasibility, net cash inflow and Benefit to investmentratio. On selecting this option the following dialog box appears,

The data required for performing the present worth are as follows

General Interest rate in percentage

overhead and maintenance charges in percentage

Project life in years

Investment Capital investment in Rupees

Savings Peak Load power saving in MW,

Unit energy charges in Rupees

Loss Loadfactor

Enter loss load factor otherwise use Cal button to obtain theloss load factor


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n

n

ii

ifactorAnnuity

)1(

1)1(

Click on Compute to check the feasibility. The project feasibility block displays the net present

worth, benefit to investment ratio and the feasibility.

6.1ProcedureCash outflow

Annual Expenses = Investment* (O&M charges/100);

Present worth of annual expenses = Annual expenses * Annuity factor

Where n = number of project life in years

i = interest rate

Present worth of cash out flow = Investment + Present worth of annual expenses;

6.2Cash Inflow (savings)Peak Load Power saving = Losses in MW in BaseLosses in MW in improved case

Load factor = Average power/ Maximum demand

Loss load factor = A*Load factor+(1-A)*(Load factor)^2 where A=constant

For sub transmission system A= 0.3 distribution A=0.2

Energy Saved annually = Peak load power saving in MW*1000*8760*Loss Load factor-

Cost of Energy saving = Energy Saved * Unit of Energy

Present worth of net cash inflow = Cost of Energy saving * annuity factor

Net Present Worth savings = Present worth of net cash inflow - Present worth of cash out flow-

Net Benefit = ( Net Present worth + Investment )

Benefit to Investment ratio = ( Net Benefit / Investment )

If the net present worth is positive, the project is feasible.

Click on Save and Open to save the present worth analysis feasibility report.


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The report consists of

6.3DataInterest Charges in percentage, O and M Charges in percentage, Project Life in Years, CapitalInvestment in rupees, Peak Load Power Saving in MW, Loss Load Factor, Unit ChargeRupees/kwh

6.4OutputAnnual expenses in rupees

Present worth of annual expenses in rupees

Present worth of cash outflow in rupees

Annual saving in energy in kWh

Cost of energy saving in rupees

Present worth of cash Inflow in rupees

Net Present Worth in rupees

Benefit to Investment Ratio

Whether the project is feasible or not

6.5Sample Case studyPresent worth analysis feasibility report

FEASIBILITY STUDY USING PRESENT WORTH CALCULATION

Interest Charges : 12.0 %

O and M Charges : 3.0 %Project Life : 10 Years

Capital Investment : 900000 Rs

Peak Load Power Saving : 0.050 MW

Loss Load Factor : 0.432

Unit Charge : 2.00 Rs/kwh

Annual Expenses : 135000 Rs


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Present Worth of Annual Expenses : 762780 Rs

Present Worth of Cash Outflow : 1662780 Rs

Cost of energy saving : 378432 Rs

Present Worth of Cash Inflow : 2138225 Rs

Net Present Worth : 475445 Rs

Benefit to Investment Ratio : 1.528

Project is Feasible

6.6 Feasibility study using Present Worth Calculation

Date and Time : Sat May 11 14:34:03 2013

FEASIBILITY STUDY USING PRESENT WORTH CALCULATION

Interest Charges : 12.0 %

O and M Charges : 3.0 %

Project Life : 10 Years

Capital Investment : 800000 Rs

Peak Load Power Saving : 0.029 MW

Loss Load Factor : 0.325

Unit Charge : 2.00 Rs/kwh

Annual Expenses : 24000 Rs

Present Worth of Annual Expenses : 135605 Rs

Present Worth of Cash Outflow : 935605 Rs

Annual Saving in Energy : 83559 kwh

Cost of energy saving : 167119 Rs

Present Worth of Cash Inflow : 944259 Rs

Net Present Worth : 8654 Rs

Net Benefit : 808654 RsBenefit to Investment Ratio : 1.011

Project is Feasible


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CHAPTER-7

OVERVOLTAGE TRANSIENT BEHAVIOUR OF SYSTEM UNDER

STUDY

Although it may seem like more, there are actually only four basic causes of field failures(surface or underground) in trailing cables and drag cables. They are:

Mechanical damage Current overload Excessive tension Poor temporary splices

Individually, or in combination, these can result in significant downtime. Awareness ofsymptoms, or other signs of problems, can aid cable users in determining what the problemmight be and how to correct it. After one of the above events occurs the cable is either

immediately rendered unusable or a series of subsequent problems begins which make it appearthat the cable is at fault. Information regarding these events has been compiled and documentedwith photographs of typical failures. An explanation of what to look for and how to handle eachsituation is found below in Conditions, Possible Causes, and Corrective Action.

7.1 Mechanical DamageCondition: Outer jacket is usually torn or crushed open and has rough edges or abrasion marksleading up to the opening. This is the obvious case. In other cases, the jacket may have little orno marks on the outside, but the conductor insulation inside is ruptured either partially or totally.If this is not a total electrical failure, it will lead to leakage current, nuisance tripping, and

downtime. Figure 1 shows mechanical damage that was hidden beneath a small mark on theouter jacket.

Mechanical damage to inner components also occurs when the cable is bent in a radius farsmaller than the manufacturers recommendations. When dragging cables, be sure to work allkinks, knots, and loops out of the run. Otherwise, the loop will become taut around the cable andend up one times the cable diameter(Figure 2) instead of the normal twelve to sixteen timesthe cable diameter. As a result of exceeding manufacturers bend radius recommendations,damage to all conductors and insulation is imminent. Small diameter ropes can cut the jacketand/or squeeze the core until insulation damage occurs.

Possible Causes:Sharp rocks, roof falls, sharp edges on shuttle car reeling devices, run-over,small bend radiuses all contribute to cable failures of this nature.

Corrective Action: Cable handlers, machine helpers, and other operations personnel all need tobe made aware of the sometimes delicate nature of soft copper stranding and the rubber materialsinside the cable. Developing an appreciation for the product capabilities and limitations will go along way toward reducing mechanical damage. Training on proper bending radius will also behelpful. Large diameter ropes or slings can reduce handling damage.


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7.2 Current OverloadCondition: Cable insulation carries a 90 Celsius rating. Jacketing compounds have notemperature rating. Jackets are compounded for the highest mechanical strength, since that is its

primary function. If power conductors are run at 90C in free air and no greater than the ratedamperage, the cable will perform for its anticipated life. Problems arise when the cable is:1) wound up on a reel without the proper derating factor applied,2) stacked in a pile,3) direct buried without increase of conductor size, or4) run at maximum amperes and voltage drop.In these cases, the power conductor can reach temperatures up to 200C (392 Fahrenheit). Thismelts the tin coating and darkens the conductors colour. The jacket vitrifies and cracks open.

Possible Causes:When no longer in free air, the cable cannot dissipate the heat from the powerconductors into the atmosphere. Heat builds up inside the cable; the conductors surpass their

temperature rating, and the jacket heat-ages at a rapid rate.

Corrective Action: Always perform amperage calculations prior to ordering cable for new orrebuilt equipment. Be sure to derate for multiple layers of cable on the shuttle car reel. Whenupgrading the horsepower of mining equipment, a larger conductor size becomes necessary. Onparticularly long runs of cable, calculate voltage drop prior to ordering cable. High current at lowvoltage can also overheat a cable.

7.3 Excessive TensionCondition:Excessive tension many times manifests itself rapidly, as shown in Figure 5. Other

times it is hidden. When cables are operated somewhat above manufacturers limits, the flexiblestranded power conductors start a fatigue process of high wear at intimate points of contact.This is particularly true where the center bunchs outerwires intersect the six-bunch layers innerindividual wires. Under normal tension and wear, a little dust is the by-product. Under highertension, notching occurs, as shown in Figure 6. Individual wires literally abrade in two againsteach other. Once several wires fatigue-break, the ends continue to flex against surrounding wiresand an exponential growth rate of broken wires results.

Possible Causes: Shuttle car reel tensioning is the single biggest cause. When the cable does notwant to rise up off of wet mine floors, operators increase tension on the reel. For drag cables,expediency precipitates long lengths being dragged.

Corrective Action: Keep the shuttle car reel set so that 15 to 20 feet of cable is suspendedbetween the shuttle car and the mine floor during reeling and de-reeling. Keep the tie-point backin a crosscut and not in the main haulage way. This spreads the tension of the dynamic reelreverse over 15 to 20 feet of cable instead of 3 to 4 feet. When dragging cable, a rule-of-thumbis to not exceed 200 feet when pulling by one rope or sling. Add extra slings and pull the cableup in loops of 200 feet.


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7.4 Poor Temporary SplicesCondition: Splices have to be rebuilt regularly due to one of the following: ground check wirebreaks, power conductor breaks by connector, splice pulls in two, jacket wearing rapidly, etc.

Possible Causes: Crimp sleeve too small or applied with improper compression. Bunches aresometimes cut out to facilitate connector application. If the conductors are not staggered withinthe splice, the splice becomes bulky. The splice jacket wears against the guiders on the shuttlecar or against the mine floor when dragging a trailing cable.

Corrective Action: Round cables must have the helix or twist of all conductors built back intothe splice. Do not straighten the conductors out after jacket removal. Rebuild the splice using thefactory helix. This alone will decrease fatigue failure at the connector on all round Type SHD-GC, Type G-GC, and Type W more than anything else will. Do not cut off any wires to make aconnector fit. Get a larger connector. The connector sleeve must be compressed so the wires

deform slightly, but are not crushed.If urgency dictates corner-cutting, flag the splice for rebuild during the next scheduledmaintenance time. Flat cables must have the connectors staggered to reduce the bulkiness.Tensioning from power conductor to power conductor must be as equal as possible on all cablesplices. This allows all power conductors to participate in the tensile load. Leave the groundingand ground check conductors approximately inch slack so they do not carry any tensile load.Single conductor splices, do not provide equal tensioning of the conductors and should only beused on a very temporary basis. The non-staggered power conductor connections, too muchlength on the ground check splice, and unequal tension of the power conductors. A short-livedsplice on a round Type W cable due to the helix not being rebuilt.


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CHAPTER-8

CONCLUSION

Form results of Cable Overloading analysis it is concluded that:

a) Cable overloading occurs due to line loading i.e loading in line by the load is above its

limits so care should be taken care during planning.

b) Insulation breakdown or oil breakdown also results in cable overloading so insulation

should be checked time to time to reduce chances of overloading and outages.

c) Load shedding, operation , rated capacity operation of transformer is must needed for

efficient operation of lines.

d) In this paper, the capacity of overloaded cable is increased by using double circuit line.

8.1 Reasons for Cable OverloadingThe appropriate size and number of cable depends directly on the number and size of conductorsintended and the allowable fill area. Also, since cable offer flexibility for modification andexpansion, engineers and designers should plan cable systems to be sized and designed toanticipate both current and future needs. Overfilling and improperly securing wires in cable canlead to a number of serious hazards. Weight is one issue; all cable and their associated supportsare rated for a specific maximum weight, based partly on the allowable fill area and the spacingof the cable supports. Overloading cable can lead to a breakdown of the tray, its connectingpoints, and/or supports, causing hazards to persons underneath the cable and even leading to

possible electric shock and arc flash/ blast events from component failure when the cables aresuddenly no longer supported.

Additionally, cables in can be damaged by improperly securing and installing other cables andwires in the same cable. The NEC requirements for cable tray fill also consider the heat build upin conductors while current flows. When cable trays are overloaded, excessive heat build up inand around live conductors can cause the insulation to break down, leading to potential shockhazards or fires. Fires can occur either in the cable (which may provide a fire path) or incombustible materials near the cable. Furthermore, the improper use of flexible cord could leadto the spread of toxic fumes if a fire were to occur.


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References

[1] Technical Document on Power System Studies, MiPower Software, PRDC Bangalore.

[2] Present worth analysis by MiPower Software, PRDC Bangalore.

Cable Overloading Report

Documents

Transcript of Cable Overloading Report