Glossary



Hybrid Systems ComprisingSolar PV and Fuel Fired GeneratorsBest Practice GuidelinesTHIS PAGE TO HAVE ACKNOWLEDGEMENTS ETC??Table of Contents TOC \o "1-3" \h \z \u Glossary PAGEREF _Toc298596410 \h iiIntroduction PAGEREF _Toc298596411 \h 1Part 1: System Design PAGEREF _Toc298596412 \h 21.1ENERGY SOURCE MATCHING PAGEREF _Toc298596413 \h 21.2ENERGY EFFICIENCY PAGEREF _Toc298596414 \h 21.3STANDARDS FOR DESIGN PAGEREF _Toc298596415 \h 21.4 OVERVIEW OF SYSTEM DESIGN PAGEREF _Toc298596416 \h 51.5 LOAD (ENERGY) ASSESSMENT PAGEREF _Toc298596417 \h 51.6HYBRID SYSTEM DESIGN METHODOLOGY PAGEREF _Toc298596418 \h 61.6.1Load Assessment and Battery determination PAGEREF _Toc298596419 \h 61.6.2PV ARRAY SIZING: d.c. Bus - Standard Switched Controllers PAGEREF _Toc298596420 \h 101.6.3 PV ARRAY SIZING: d.c. BUS - MPPT PAGEREF _Toc298596421 \h 141.6.4PV Array Sizing: a.c. Bus - Loads Supplied Directly by Array PAGEREF _Toc298596422 \h 181.6.5PV Array Sizing: a.c. BUS - Loads Supplied by Battery PAGEREF _Toc298596423 \h 191.6.6PV ARRAY SIZING: A.C. BUS PAGEREF _Toc298596424 \h 201.6.7 Battery Inverter Selection PAGEREF _Toc298596425 \h 211.6.8Grid Connect Inverter for a.c. Bus system PAGEREF _Toc298596426 \h 221.6.8 Battery Charger PAGEREF _Toc298596427 \h 261.6.8 Selecting and Sizing Fuel fired Generator PAGEREF _Toc298596428 \h 271.6.9 Fuel Generator Control Strategies PAGEREF _Toc298596429 \h 321.6.10 Summary of Losses in a Hybrid System PAGEREF _Toc298596430 \h 331.7 CABLE SELECTION-ARRAY PAGEREF _Toc298596431 \h 361.7.1 Sub-array PAGEREF _Toc298596432 \h 371.8 CABLE PROTECTION: Array PAGEREF _Toc298596433 \h 371.9 CABLE SELECTION-Voltage Drop PAGEREF _Toc298596434 \h 391.10 Main Battery Cable: Selection and Protection PAGEREF _Toc298596435 \h 421.11 PLUGS and SOCKETS PAGEREF _Toc298596436 \h 431.12DC Switch disconnector at controller PAGEREF _Toc298596437 \h 432.1STANDARDS for INSTALLATION PAGEREF _Toc298596438 \h 452.2DOCUMENTATION PAGEREF _Toc298596439 \h 472.3 PV MODULES PAGEREF _Toc298596440 \h 472.4 PV ARRAY PAGEREF _Toc298596441 \h 482.5 OUTDOOR MOUNTED COMBINER BOXES PAGEREF _Toc298596442 \h 502.6 PV ARRAY SWITCH DISCONNECTOR PAGEREF _Toc298596443 \h 512.7CONTROLLER INSTALLATION PAGEREF _Toc298596444 \h 512.8INVERTER INSTALLATION PAGEREF _Toc298596445 \h 512.9 BATTERY INSTALLATION PAGEREF _Toc298596446 \h 512.10VENTILATION OF BATTERIES PAGEREF _Toc298596447 \h 542.11PREVENTING SPARK IGNITION SOURCES NEAR BATTERIES PAGEREF _Toc298596448 \h 552.12PREVENTING EXCESSIVE CURRENT FROM BATTERIES PAGEREF _Toc298596449 \h 562.13 BATTERY SAFETY AND WARNING SIGNS PAGEREF _Toc298596450 \h 562.14 GENERATOR INSTALLATION PAGEREF _Toc298596451 \h 562.15CABLE INSTALLATION PAGEREF _Toc298596452 \h 572.16WIRING OF ARRAYS WITH VOLTAGE ABOVE DVC-A PAGEREF _Toc298596453 \h 582.17 WIRING FROM ARRAYS WITH VOLTAGES ABOVE DVC-A TO PV ARRAY SWITCH-DISCONNECTOR NEAR CONTROLLER PAGEREF _Toc298596454 \h 592.18EARTHING OF ARRAY FRAMES (PROTECTIVE EARTH/GROUND) PAGEREF _Toc298596455 \h 592.19 SIGNAGE PAGEREF _Toc298596456 \h 612.20 COMMISSIONING PAGEREF _Toc298596457 \h 62Part 3: System Maintenance PAGEREF _Toc298596458 \h 633.1 PV Array Maintenance PAGEREF _Toc298596459 \h 63Visual Inspection PAGEREF _Toc298596460 \h 63Mounting System Inspection PAGEREF _Toc298596461 \h 63Module Cleaning PAGEREF _Toc298596462 \h 633.2 Controller Maintenance PAGEREF _Toc298596463 \h 643.3 Battery Bank PAGEREF _Toc298596464 \h 643.4 Inverter Maintenance (Battery and Grid Connected) PAGEREF _Toc298596465 \h 653.5 Balance of System Maintenance PAGEREF _Toc298596466 \h 653.6 Fuel Generator maintenance PAGEREF _Toc298596467 \h 66Annex 1: System Installation Checklist PAGEREF _Toc298596468 \h 67Annex 2: Testing and Commissioning Checklist PAGEREF _Toc298596469 \h 69Annex 3: Table showing Peak Sun hours for various sites and tilt angles PAGEREF _Toc298596470 \h 70Annex 4: Tilt and Orientation diagram for 1°N. PAGEREF _Toc298596471 \h 71Annex 5: System Design PAGEREF _Toc298596472 \h 72DC bus system PAGEREF _Toc298596473 \h 76AC bus system design PAGEREF _Toc298596474 \h 79Glossarya.c. bus systemA PV system, ( stand alone or hybrid, where the PV array is connected to the a.c. side of the system, i.e via a grid connect inverterAlternating Current (AC)The form of electricity in which the polarity of the current is periodically reversed.AltitudeThe height of the Sun from the horizon.Ampere-hoursThe unit used to measure electrical energy and to indicate the storage capacity in batteries. Symbol, Ah. To convert Ah to kWh multiply the Ah by the voltage then divide by 1000.AzimuthThe east–west position of the Sun. The solar industry standard is to express azimuth clockwise from true north (0°–360°); however it can also be quoted with a direction, east or west (i.e.?0°–180°E or 0°–180°W).BatteryElectrical energy storage device. Two or more electrochemical cells electrically connected together in a series or parallel combination to provide the required operating voltage and current levels.Battery CapacityThe maximum total electrical charge, expressed in ampere-hours (Ah) that a battery could deliver to a load under a specific set of conditions. The battery capacity depends on the rate at which the charge is given up by the battery. Battery Charging VoltageThe voltage specified as that required to charge batteries. For 12V batteries the final battery charging voltage is around 14V and photovoltaic modules are often rated at 14V so that the charging current is known at that voltage.Charging RateThe current applied to a battery or cell to restore its capacity. The charging rate is specified by the CX where x is the number of hours to bring the battery to full charge, e.g. if a battery with a capacity of 100 Ah is charged at the C5 rate, it is brought to full charge in 5 hours and 20 Amperes would be the charging current.Central inverterUsually a collection of small inverters centrally located in one housing.CircuitA circuit is the path that current flows from one charged point to another. Circuit breakerA mechanical device which will open a circuit under fault conditions. When too much current passes through, the device will open and prevent current flow. The circuit breaker can then be manually operated to close the biner boxAn electrical component for combining and housing the wiring from the PV array. CurrentThe rate of flow of electrical charge is the net transfer of electrical charge per unit time. The unit of current is the Ampere (A). In electric circuits the current is referred to by the symbol (I).Daily Demand or Daily LoadThis is the energy requirement calculated on a daily basis. This load varies from Day to day and at different times of the year. In sizing a system the average daily demand over the whole of the year is often used. Units can be Wh, kWh, or Ah.Days of AutonomyThe number of days, without input from the energy source, for which the battery storage system must supply electrical energy.d.c. bus systemA PV system (stand alone or hybrid) where the PV array is connected to the d.c. side of the system, i.e. batteries via a controllerDecisive voltage classification (DVC)A classification system for different voltage ranges. Depth of Discharge (DOD)The Ah’s removed from a cell or battery expressed as a percentage of the rated capacity, e.g. the removal of 25 Ah from a fully charged 100 Ah rated battery results in a 25% depth of discharge.Direct Current (DC)Electricity in which the current always moves in the same direction.Discharge RateThe current removed from a cell or battery. Battery manufacturers refer to the rate of discharge not by Amps but by the time it would take to completely discharge the battery. For example, a battery which has a rated capacity of 100 Ah is subjected to a current withdrawal of 5 A, it would take 20 hours to completely discharge the battery. In this case, we say that the battery is discharging at the 20-hour rate or at C20.DisconnectorA mechanical switching device which provides, in the open position, an isolating distance in accordance with specified requirements. EfficiencyThe ratio of energy (power) produced by a device to the energy (power) consumed by the same device: this is a number less than or equal to unity.Electrolyte A non-metallic electrical conductor in which current is carried by the movement of ions. In lead acid batteries, the electrolyte is an aqueous solution of sulphuric acid.EnergyThe amount of electric energy transferred: a product of power and time. Energy is measured in watt hours (Wh) and is calculated using: E = P x tEqualisationThe process of restoring all cells in a battery to an equal state of charge. In a lead acid battery, this is done by using a charging voltage of around 2.5 Volts per cell.Equipotential bondingEquipotential bonding (or protective earthing) involves electrically connecting earthed, conductive metalwork so that it is at the same voltage (potential) as earth throughout. This is required for safety reasons to protect people from electric shocks.Fuel GeneratorA device that converts mechanical energy into electrical energy to supplement the renewable energy source in a Hybrid system. The generator can be powered by petrol, diesel, LP gas or steam.Functional earthingFunctional earthing is designed to ensure optimal performance of the PV array, but it is required only if specified by the manufacturer. FuseA device that protects conductors from excessive current. The fuse is rated to carry a certain current, and when this current is exceeded the fuse will open the circuit (by melting).Hybrid SystemTechnically any system that includes two types of generators is a hybrid system. Throughout this document, the term Hybrid Systems refers to a system comprising solar PV and fuel fired generator.IrradianceThe total amount of solar radiation available at any point in time per unit area and is measured in W/m2 or kW/m2. It is a measure of power. IrradiationThe total amount of solar radiation available per unit area over a specified time period such as one day. It is the sum of irradiance values over a time period and is often measured in kWh/m2/year or MJ/m2/day. It is a measure of energy. Junction boxA box containing a junction of electric wires or cables. Kilowatt peak (kWp)This is a non-SI unit used in the solar industry to describe the nominal power of a solar PV system: it refers to the peak output under standard test conditions.Low Voltage (LV)Electrical systems that operate over 120 V DC (ripple free) or 50 V AC. Systems of these voltages require an electrical license to operate or install.Maximum Power Point (MPP)The MPP is the?point on the I–V curve that gives the maximum power. It occurs when the load resistance is equal to the internal resistance of the?PV cell.Maximum Power Point Tracker (MPPT)An electronic device included within the inverter that alters the PV array’s electrical output so that it is performing at the maximum power possible at any given time.Module inverterAn inverter designed to be mounted on the back of a module.Module efficiencyThe amount of electrical power produced by the module per amount of light energy hitting the module. This is typically lower than cell efficiency due to losses from reflection from glass etc.Monocrystalline solar cellsThe most efficient and most expensive solar cells. They have a smooth monochromatic appearance.Multicrystalline solar cells (polycrystalline)Solar cells, less efficient than monocrystalline, but cheaper to make and buy. They have a ‘glittering’ effect when in sunlight.Multi-string inverterAn inverter with multiple MPPT’s (e.g. one MPPT per string).Nominal Operating Cell Temperature (NOCT)The photovoltaic cell junction temperature corresponding to nominal operating conditions in a standard reference environment of 800 W/m2 irradiance, 20° C ambient air temperature, 1 m/s wind speed and electrically open circuit.Open CircuitAn open circuit is where the current path is broken so that the current is equal to 0.Peak Sun Hours (PSH)A unit of energy used in the solar industry when measuring irradiation. 1?PSH = 1?kW of solar energy falling on a surface of 1?m2 for 1?hour. Photovoltaic (PV)A device that creates electricity when sunlight hits its surface.PowerPower is the rate at which electrical energy is transferred. Power is measured in watts (W), and is calculated using P = V x IPV arrayStrings of PV modules are electrically connected in parallel to form an array. Also called a solar array.PV cellA single PV device. Also called a solar cell.PV modulePV cells are physically and electrically connected to form a PV module. These cells are held together by a frame and covered by a protective substance such as glass. Also called a solar module.PV stringWhen PV modules are connected in series they form a string.PV sub-arrayVery large PV arrays are often made up of many smaller PV arrays known as sub-arrays.PV systemThe PV array and all associated equipment required for it to work. Also called a solar electric system.RegulatorsDevices used to control the charging current to a battery to make sure that the battery is not overcharged.ResistanceThe opposition to current and is measured in ohms (?).Root mean square (RMS)RMS is how AC power is usually quoted; for example: VRMS = 0.707 × VP ... IRMS = 0.707 × IPSelf Discharge RateThe rate at which a battery discharges when it is idle. As a battery ages its self-discharge rate generally increases.Short CircuitA short circuit is where the current is flowing in a closed path across the source terminals.Solar Altitude (Elevation) AngleThe angle between the sun and the horizon. This angle is always between 0° and 90°.Solar Azimuth AngleThe angle between north and the point on the compass where the sun is positioned on a horizontal plane. The azimuth angle varies as the sun moves from east to west across the sky throughout the day. In general, the azimuth is measured clockwise going from 0° (true north) to 359°.Solar CellA small photovoltaic unit that generates an electrical current when hit by sunlight.Solar ModulesSee PV module. Solar radiationEnergy coming from the Sun.Specific GravityThis is the ratio of the density of the battery electrolyte with respect to water. Hydrometers, which sample the electrolyte, are used to monitor the state of charge of the batteries.Standard Test Conditions (STC)Standardised test conditions that make it possible to conduct uniform comparisons of PV modules by different manufacturers. State of ChargeThe available capacity in a cell or battery expressed as a percentage of rated capacity.String inverterAn inverter with only one MPPT.Surge capacityThe capacity of an inverter to deliver power at a higher rate than its rated power output for given short periods (measured in seconds) of time.Switch-disconnectorA mechanical switching device capable of making, carrying and breaking currents in normal circuit conditions and, when specified in given operating overload conditions. In addition, it is able to carry, for a specified time, currents under specified abnormal circuit conditions, such as short-circuit conditions. Moreover, it complies with the requirements for a disconnector. Temperature Correction Factor (Batteries)The amount by which the capacity of a battery should be adjusted to account for changes in temperature. Battery capacities are usually given at a reference temperature of 25° C.Temperature Correction Factor (Solar Cells)The amount by which the voltage, current or power from a solar cell will change with changes in the temperature of the cell.Thin film solar cellsMade from materials that are suitable for deposition on large surfaces such as glass. Very thin in comparison to monocrystalline and multicrystalline solar cells. Least efficient technology, but the cheapest to manufacture.VoltageTthe potential difference between two points. Voltage is measured in volts (V).IntroductionThis set of guidelines sets out best practice for the design, installation and?maintenance of Hybrid Systems comprising solar PV and fuel fired generators..? These systems are typically installed in areas where the grid is not available however they be installed in conjunction with fuel generator based mini-grids e.g. in remote villages.? However these guidelines could also be applied to systems that are used as a back-up system for a building, which is connected to the grid and the client wants a fuel generator available in periods of long grid outages.. The output of such a system either feeds directly to circuits, which are not connected to the grid or connects to circuits during a grid failure via a changeover switch.The guidelines cover following system types:Hybrid systems comprising solar PV (d.c. bus) and fuel fired generators. Hybrid systems comprising solar PV (a.c. bus) and fuel fired generators The guidelines are divided into three parts as follows:Part 1: System DesignPart 2: System InstallationPart 3: System Maintenance System Design outlines the best practice processes undertaken when determining why a system is required and then selecting and matching the equipment that will be part of a hybrid system comprising solar PV and fuel fired generator to meet specified design requirements. It provides the formulas used to match components and for determining the energy output of the system. Once the modules, controllers, batteries, inverter and fuel generator have been determined, international and local standards are applied to determine and select the balance of system requirements such as cables, isolation and protection devices.System Installation outlines the best practices when following international and local standards to install the hybrid system comprising solar PV and fuel fired generatorSystem Maintenance outlines the best practices that should be employed on maintaining the hybrid system comprising solar PV and fuel fired generator to prolong the lifetime of the system as well as to reduce system losses.Note: 1. Throughout the rest of these guidelines, the term Hybrid Systems will be used and it refers to a system comprising solar PV with fuel fired generator.2. Lithium Ion batteries are not covered in this guideline because currently there are international standards with respect to their installationPart 1: System DesignThis set of guidelines provides the minimum knowledge required to design a Hybrid system using the d.c. and a.c. bus configurations. A hybrid system will be designed:Either as a d.c. bus system with fuel generator supplying a.c. loads.; Or as an a.c. bus system with fuel generator supplying a.c. loads. .or as a combination of both The design of any Hybrid system should consider the electrical load as well as a number of criteria, including: BudgetPower quality Environmental impact Aesthetics Site accessibilityfuel availabilityHaving applied the comprehensive design criteria, a designer shall use this information to:Determine the size of the PV array (kWp) to meet the daily energy requirements;Select the appropriate system d.c. voltage; Determine the controller size and type based on the size of the array;Determine the battery capacity;Determine the fuel generator capacity and its run times.Determine all the balance of equipment1.1ENERGY SOURCE MATCHINGHeating and lighting should be supplied from the most appropriate source. For example Cooking - gas or wood burning stove or wood burning/charcoal etc.Water heating - solar water heating with gas or wood backupLighting - electrical lighting most often used but natural light (day lighting) should be considered.1.2ENERGY EFFICIENCYAll appliances should be chosen for the lowest possible energy consumption for each desired outcome, such asHigh efficiency lightingEnergy efficient refrigeration1.3STANDARDS FOR DESIGN System designs should follow any standards that are typically applied in the country or region where the solar installation will occur. The following are the relevant standards for Kenya. These standards are often updated and amended so the latest version should always be applied.The following Kenyan standards are applicable:KS 1672Glossary of terms and symbols for solar photovoltaic power generationKS 1673-1:2003Solar photovoltaic power systems-design, installation, operation, monitoring and maintenance-code of practice .Part 1:General PV KS 1673-2Generic specification for solar photovoltaic systems – system design, installation, operations, monitoring and maintenanceKS 1674Crystalline silicon terrestrial photovoltaic (PV) modules – design qualification and type approval KS 1675 Thin-film terrestrial photovoltaic (PV) modules – design qualification and type approvalKS 1676 Terrestrial photovoltaic (:PV) power generating systems – general and guideKS 1677Procedures for temperature and irradiance corrections to measured I-V characteristics of crystalline silicon photovoltaic devicesKS 1678Photovoltaic devicesKS 1679 UV test for photovoltaic (PV) modulesKS 1680 Overvoltage protection for photovoltaic (PV) power generating systems – guideKS 1681Characteristic parameters of hybrid photovoltaic systemsKS 1682 Salt mist corrosion testing of photovoltaic (PV) modulesKS 1683Rating of direct coupled photovoltaic (PV) pumping systemsKS 1684 Susceptibility of a photovoltaic (PV) module to accidental impact damage (resistance to impact test)KS 1685Photovoltaic system performance monitoring – guidelines for measurement, data exchange and analysisKS 1686 Analytical expression for daily solar profilesKS 1709-1:2009Batteries for use in photovoltaic power systems - Specification Part 1: General requirements.KS 1709-2:2009Batteries for use in photovoltaic power systems - Specification Part 2: Modified lead acid batteries KS 1709-4:2009Batteries for use in photovoltaic power systems - Specification Part 4: Recommended practice for sizing lead acid batteries for photovoltaic (PV) systems.KS IEC TS 62257-8-1:2007 Recommendations for small renewable energy and hybrid systems for rural electrification - Part 8-1: Selection of batteries and battery management systems for stand-alone electrification systems - Specific case of automotive flooded lead-acid batteries available in developing countriesKS IEC 61727 Photovoltaic (PV) systems - Characteristics of the utility interface KS IEC 62446:2009 Grid connected photovoltaic systems - Minimum requirements for system documentation, commissioning tests and inspection KS IEC 60904-1 Photovoltaic devices - Part 1: Measurement of photovoltaic current-voltage characteristics KS IEC 62093:2005 Balance-of-system components for photovoltaic systems - Design qualification natural environments.KS IEC 62124:2004 Photovoltaic (PV) stand-alone systems - Design verification.KS IEC 62116:2008 Test procedure of islanding prevention measures for utility-interconnected photovoltaic invertersKS IEC 61683:1999 Photovoltaic systems - Power conditioners - Procedure for measuring efficiencyKS IEC 62109-1:2010 Safety of power converters for use in photovoltaic power systems Part 1: General requirementsKS IEC 62109-2:2011 Safety of power converters for use in photovoltaic power systems Part 2: Particular requirements for inverters*being considered for adoptionThe following international standards (IEC) are applicable:IEC 60364-5Wiring rulesIEC 62548Photovoltaic (PV) arrays – design requirementsIEC 62305Protection against lightningIEC 61730.1Photovoltaic module safety qualification: requirements for constructionIEC 61730.2Photovoltaic module safety qualification: requirements for testingIEC 61215 Crystalline silicon terrestrial photovoltaic (PV) modules – Design qualification and type approvalIEC 61646 Thin-film terrestrial photovoltaic (PV) modules - Design qualification and type approvalIEC 61427-1* Secondary cells and batteries for renewable energy storage - General requirements and methods of test - Part 1: Photovoltaic off-grid applicationIEC 61427-2* Secondary cells and batteries for Renewable Energy Storage - General Requirements and methods of test - Part 2: On-grid application.IEC 61724* Photovoltaic system performance monitoring - Guidelines for measurement, data exchange and analysisIEC 61702* Rating of direct coupled photovoltaic (PV) pumping systems application.IEC/TS 62548Photovoltaic (PV) arrays – design requirementsIEC 62894* Photovoltaic inverters - Data sheet and name plate *Being considered for adoption 1.4 OVERVIEW OF SYSTEM DESIGNFour major issues arise when designing a system:1. The load (power) required to be supplied by the system is not constant over the period of one day;2. The daily energy usage varies over the year;3.The energy available from the PV array may vary from time to time during the day;4.The energy available from the PV array will vary from day to day during the year.Since the system is based on photovoltaic modules, then a comparison should be undertaken between the available energy from the sun and the actual energy demands. The worst month is when the ratio between solar energy available and energy demand is smallest. The design of a hybrid system requires a number of steps. A basic design method follows:Determination of the energy usage that the system must supply.Determining how the system provides the total required daily energy. This could be completely by the PV array with the generator only used as a back up or where the generator is used than the following must be determined :load energy provided directly from fuel firedload energy provided directly from solar arrayload energy provided by batteries being charged by the fuel fired generatorload energy provided by batteries being where a+b+c+d= Total Required Daily EnergyDetermination of the battery storage required.Determination of the energy input required from the PV array. Determination of Fuel generator size and its run times.Selection of the remainder of system components.1.5 LOAD (ENERGY) ASSESSMENT Electrical power is supplied from the batteries (d.c.) or via an inverter to produce 240 volts a.c.. Electrical energy usage is normally expressed in watt hours (Wh) or kilowatt hours (kWh).To determine the daily energy usage for an appliance, multiply the power (in Watts) of the appliance by the number of hours per day it will operate. The result is the energy (Wh) consumed by that appliance per day.An energy assessment should be undertaken for the loads present in the system. For hybrid systems the loads typically are all a.c. however there can at times be some small d.c. loads. The Stand-alone Guideline has examples of energy assessments for a.c. loads and d.c. loads. Example of a large daily energy usage being supplied by a hybrid system is shown in annexure 5.You need to calculate the electrical energy usage with the customer. Many systems have failed over the years not because the equipment has failed or the system was installed incorrectly, BUT BECAUSE THE CUSTOMER BELIEVED THEY COULD GET MORE ENERGY FROM THEIR SYSTEM THAN THE SYSTEM COULD DELIVER. It failed because the customer was unaware of the power/energy limitations of the system.The problem is that the customer may not want to spend the time determining their realistic power and energy needs which are required to successfully complete a load assessment form. They just want to know: How much for a system to power my lights and TV?A system designer can only design a system to meet the power and energy needs of the customer. The system designer must therefore use this process to understand the needs of the customer and at the same time educate the customer. Completing a load assessment form correctly (Refer to annexure 5 to complete the load assessment forms and learn about the design process) does take time; you may need to spend 1 to 2 hours or more with the potential customer completing the tables. It is during this process that you will discuss all the potential sources of energy that can meet their energy needs and you can educate the customer on energy efficiency.For large loads such as villages than if possible it is best to data log the energy profile over a period of time to obtain an hourly load profile.1.6HYBRID SYSTEM DESIGN METHODOLOGYAnnexure 5 of this document contains a worked example for both d.c and a.c bus systems As discussed above, hybrid systems can be one of three types:d.c. bus systems supplying a.c. loads.a.c. bus systems supplying a.c. loads.or a combination of the both.There are a lot of design steps that are common to the both system possibilities and we will be discussing them first in the below sections.1.6.1Load Assessment and Battery determination1. Load Assessment The most important step is to perform a Load assessment before designing any hybrid system. The steps involved in estimating the load are:1.List all the items in the household, village or site in question that will draw electricity from the system 2.Determine the rated power of each of these items.3.Estimate the number of hours per day that the item would be used.Multiply the power (in watts) by the number of hours to determine the energy used by each in a unit called watt-hours (watt-hrs or Wh) item.5.Add up the answers.We also calculate the continuous VA demand and the surge demand to make sure that the inverter can handle the a.c. loads safely. For some systems where the generator is being provided for back-up power, the PV system will be required to meet all the regular loads. Prior to a.c. bus systems, the conservative approach was to assume that none of the load was being provided directly by the array during the day. However in reality, unless the loads were only nigh-time lights, then some of the load would be supplied directly by the solar. This is still a good conservative approach and it is recommended that it still be applied to systems where the generator is used only for backup .For systems where the generator is operating daily, the time that the generator operates should be determined and then based on that information, the following would be determined: load energy provided directly from fuel fired generatorload energy provided directly from solar arrayload energy provided by batteries being charged by the fuel fired generatorload energy provided by batteries being 2. Battery Inverter Efficiency For a.c. systems, the efficiency of the inverter must be considered. Typically the peak efficiency of the inverter may be over 90%, but in many systems, the inverter will sometimes be running when there is very little load on the inverter, so the average efficiency is about 85% to 90%. The total amount of a.c. energy being supplied through the inverter must be divided by this efficiency figure to obtain the energy to be supplied to the inverter from the battery bank.For hybrid systems with generator as back up, it is recommended that all the daily energy required be used.For hybrid systems, where the generator operates daily than it is recommended that:For d.c. bus systems, the energy value used is the total daily energy less the energy supplied directly by generator;For a.c. bus systems, the energy value used is total daily energy minus the energy supplied directly by generator and minus the energy supplied directly by the array through the inverters (grid connect type) connected directly to the array.3. Battery SelectionSystem voltages are generally 12, 24 or 48 Volts. The actual voltage is determined by the requirements of the system. In larger systems, 120V, 240V d.c. or higher could be used, but these are not typical residential or small commercial systems.As a general rule, the recommended system voltage increases as the total load increases. For small daily loads, a 12V system voltage can be used. For intermediate daily loads, 24V is used and for larger loads 48V is used.3346451307465Figure 1: Choosing the system voltageFigure 1: Choosing the system voltage334645406401 kWh3-4 kWhUse 12 Voltsystem voltageUse 24 Voltsystem voltageUse 48 Volt system voltage001 kWh3-4 kWhUse 12 Voltsystem voltageUse 24 Voltsystem voltageUse 48 Volt system voltageThe system voltage change-over points are roughly at daily loads of 1 kWh and 3-4 kW, but this will also be dependent on the actual power profile.One of the general limitations is that maximum continuous current being drawn from the battery to the battery inverter should not be greater than 150Ad.c. .To convert Watt-hours (Wh) to Amp-hours (Ah) you need to divide by the battery system voltage.Battery capacity is determined by whichever is the greater of the following two requirements:The ability of the battery to meet the load energy being supplied by the battery bank, for some systems this could be for a few days, sometimes specified as ‘days of autonomy’ of the system;ORThe ability of the battery to supply peak power demand.The critical design parameters include:Parameters relating to the energy requirements of the battery:Load energy being supplied by the batteryDaily and maximum depth of dischargeNumber of days of autonomyParameters relating to the discharge power (current) of the battery:Maximum power demandSurge demandParameters relating to the charging of the battery:Maximum Charging CurrentBased on these parameters there are a number of factors that will increase the battery capacity in order to provide satisfactory performance. These correction factors must be considered.4. Days of AutonomyIf the fuel generator is being is used just for back up, extra capacity is necessary when the loads require power during periods of reduced input. The battery bank is often sized to provide for a number of days autonomy. However for hybrid systems where the generator operates daily, the days of autonomy could be less than 1 day.It is recommended that from hybrid systems:With the generator being used as back up, the days of autonomy are between 3 and 5 days.With the generator being operated daily, a minimum of 1-day autonomy is applied.5. Maximum Depth of DischargeThe battery manufacturers will specify the maximum allowable depth of discharge. That is the depth to which the battery can be taken before the battery will be damaged. This figure therefore provides the capacity that can be taken out of the battery to supply the loads before this point is reached. The manufacturer’s depth of discharge can vary in the range 0.5 - 0.8 (50 to 80%). 6. Battery Discharge RateThe actual discharge rate selected is highly dependent on the power usage rates of the connected loads. Many appliances operate for short periods only, drawing power for minutes rather than hours. This affects the battery selected, as battery capacity varies with discharge rate. Relevant information, such as a power usage profile over the course of an average day, is required for an estimate of the appropriate discharge rate.For small systems, this power profile information is often impractical.The C100 (100hr discharge rate) capacity rating of the battery could be used for hybrid systems where 5 days autonomy has been used in determining the battery capacity however for hybrid systems where the generator is required daily, the 10hr (C10) rate. is recommended.7. Battery Temperature deratingBattery capacity is affected by temperature. As the temperature goes down, the battery capacity reduces. In Figure 2, the graph d.c. shows the battery correction factor for low temperature operation. Note that the temperature correction factor is 1 at 25°C as this is the temperature at which the battery capacity has been specified.In Kenya, the night-time temperature varies greatly between the regions at altitude to those regions located in the hotter lower altitudes, so it is important that the lowest temperature for the actual location of the selected site is used. If the system is being installed in regions where the temperature can get very cold, the temperature derating must be determined from figure 2.950033750417Figure SEQ Figure \* ARABIC 2: Effect of Temperature on battery capacity00Figure SEQ Figure \* ARABIC 2: Effect of Temperature on battery capacity8. Battery SelectionDeep discharge type batteries / cells should be selected for the required system voltage and capacity in a single series string of battery cells.Parallel strings of batteries are not recommended, but if it is unavoidable the number of parallel strings should be kept to a minimum. (Note: Battery manufacturers typically only allow a maximum of 3 or 4 batteries in parallel). Where parallel strings are necessary, each string must be separately fused.1.6.2PV ARRAY SIZING: d.c. Bus - Standard Switched ControllersThe calculation for determining the size of the PV array is dependent on the type of controller used. Historically, standard switched controllers were the most common controllers used. In recent years, a number of maximum power point trackers (MPPT) have become available. This section determines how to size the PV array using switched controllers based on the PV array meeting the daily load requirements all year. Section 1.6.3 details how to size a PV array using a MPPT. The size of the solar array should be selected to take account of:Seasonal solar radiation data for selected tilt angle and orientation, taking shading into accountVariation of daily/seasonal energy usage Battery efficiencyManufacturing tolerance of modulesTemperature effects on the modulesEffects of dirt on the modulesSystem losses (e.g. power loss in cables)Inverter efficiency Solar irradiation data is available from various sources; some countries have data available from their respective meteorological department. One source for solar irradiation data is the NASA website: http:/eosweb.larc.sse/. RETSCREEN, a program available from Canada that incorporates the NASA data, is easier to use. Please note that the NASA data has, in some instances, had higher irradiation figures than that recorded by ground collection data in some countries. However, if there is no other data available, this data can be used. Solar irradiation is typically provided as kWh/m2 . However it can be stated as daily peak Sunhrs (PSH). This is the equivalent number of hours of solar irradiance of 1kW/m2. Annexure 1 provides PSH data on the following sites:Mombasa (Latitude 04°03′S Longitude 39°40′E?)Nairobi (Latitude 01°17' S' Longitude 36°49' E)Wajir (Latitude 01° 45' N Longitude 40°03 E)Lodwar (Latitude 03°07'N, Longitude 35°36'E)The variation of both the solar irradiation and the load energy requirement should be considered. If there is no variation in daily load between the various times of the year, the system should be designed for the month having the lowest irradiation, i.e. peak sun hours (PSH). Note: PV systems can be mounted on the roof of a building. The roof might not be facing true north (southern hemisphere) or south (northern hemisphere) or at the optimum tilt angle. The irradiation data for the roof orientation (azimuth) and pitch (tilt angle) will be used when undertaking the design. Please see the following discussion on tilt and orientation for determining peak sun hours for sites not facing the ideal direction.EFFECT OF ORIENTATION AND TILTWhen the roof is not oriented to true north (southern hemisphere) or south (northern hemisphere) and/or not at the optimum inclination, the output from the array will be less than the maximum possible. Annex 4 provides a diagram showing estimated tilt and orientation losses for a location with a latitude of 1°N. The table provides values for orientations at 5° intervals (azimuths) and inclination angles at 10° intervals.Using this figure will provide the system designer/installer with information on the expected output of a system (with respect to the maximum possible output) when it is located on a roof that is not facing true north (for the southern hemisphere) or south (for the northern hemisphere), or at an inclination equal to the latitude angle. The designer can then use the peak sun hour data for their particular location to determine the expected peak sun hours at the orientation and tilt angles for the system to be installed. 1. Daily Energy Requirement from the PV ArrayIn order to determine the energy required from the PV array, it is necessary to increase the energy from the battery bank to account for battery efficiency.The average columbic efficiency (in terms of Ah) of a new battery is 90% (variations in battery voltage are not considered).For hybrid systems having a generator as back up, it is recommended that the total daily energy required is used to determine the daily energy requirement from the PV array and conservatively it is assumed that all the energy is provided via the battery.For hybrid systems where generator operates daily, it is recommended that the energy value used to determine the daily energy requirement from the PV array is: Total Energy requiredminus the energy provided directly by the generatorminusthe energy supplied by the batteries charged by the generatorFor hybrid systems where the generator is operating daily, a specified portion of the daily load energy requirement will be agreed to be met by the array during the day, and the daily energy requirement from the array calculated above will be divided into 2 parts:First part: that portion to be supplied by the PV array during the day. This will not need to be increased to take the battery efficiency into account.Second part: that portion of the load provided by the battery bank as charged by the PV array – this figure will need to be increased to take the battery efficiency into account.2. Oversize FactorAs the hybrid system includes a fuel generator, the oversize factor of 10% (which is the recommended oversize factor for Kenya in the absence of a fuel generator) need not be used. The fuel generator would be sufficient to provide the equalisation charge to the battery bank.3. Derating Module PerformanceThe PV array will be de-rated due to:a. Manufacturer’s Output ToleranceThe output of a PV module is specified in watts and with a manufacturing tolerance based on a cell temperature of 25 degrees Celsius. Historically this has been 5%, but in recent years typical figures have been -0% and +5%. When designing a system it is important to incorporate the actual figure for the selected module.b. Derating Due to DirtThe output of a PV module can be reduced as a result of a build-up of dirt on the surface of the module. The actual value of this derating will be dependent on the actual location; some city locations might have a high dirt derating due to car pollution, some coastal locations might have a high dirt derating due to salt build up and some locations might have long periods with no rain to naturally wash the modules. If in doubt, an acceptable dirt derating value would be 5%.c. Derating Due to TemperatureA solar module’s output power decreases with temperatures above 25°C and increases with temperatures below 25°C. The average cell temperature will be higher than the ambient temperature because of the glass on the front of the module and the fact that the module absorbs some heat from the sun. The output power and/or current of the module must be based on the effective temperature of the cell. This is determined by the following formula:Tcell-eff = Ta.day + 25°CWhere:Tcell-eff = the average daily effective cell temperature in degrees Celsius (°C)Ta.day = the daytime average ambient temperature for the month that the sizing is being undertaken.Since the modules are used for battery charging, the current at the charging voltage at the effective cell temperature should be used in calculations. For a 12V battery, a charging voltage of 14V is appropriate. If curves are unavailable to determine the current at effective cell temperature, the Normal Operating Cell temperature (NOCT) provided by the manufacturers can be used.Therefore the derated module output current is calculated as follows:The Current of the module at 14V and effective cell temperature (or NOCT current)multiplied by derating due to manufacturer’s tolerancemultiplied by derating due to dirtI (NOCT) x fman x fdirtIf a module has a 3% (0.03) manufacturer’s tolerance, the module’s current is derated by multiplying by 0.97 (1-0.03).If a module has a 5% (0.05) loss due to dirt, the module’s current is derated by multiplying by 0.95 (1-0.05).4. Number of Modules required in the ArrayDetermine the number of modules in series: to do this, divide the system voltage by the nominal operating voltage of each module.To determine the number of strings in parallel, the PV array output current required (in A) is divided by the output of each module (in A). Then round up to the next whole number.To determine the number of strings in parallel, the PV array output current required (in A) is divided by the output of each module (in A). Then round up to the next whole number.5 CONTROLLERS: Standard Switched ControllerPV controllers on the market range from simple switched units that only prevent the overcharge (and discharge) of connected batteries to microprocessor based units that incorporate many additional features such as:PWM and equalisation charge modesDC Load controlVoltage and current meteringAmp-hour loggingGenerator start/stop controlUnless the controller is a model that is current limited, these should be sized so that they are capable of carrying 125% of the array’s short circuit current and withstanding the open circuit voltage of the array. If there is a possibility that the array could be increased in the future, the controller should be oversized to cater for the future growth.(Note: sometimes the controller is called a regulator)1.6.3 PV ARRAY SIZING: d.c. BUS - MPPTPlease refer to start of section 1.6.2 for information on solar irradiation for Kenya.1. Daily Energy Requirement from the PV ArrayThe size of the PV array should be selected to take account of:Seasonal variation of solar irradiationSeasonal variation of the daily energy usageBattery efficiency (Wh)Cable lossesMPPT efficiency Manufacturing tolerance of modulesDirtTemperature of array (the effective cell temperature)With the standard controller, the only sub-system loss was the battery efficiency and the calculations are undertaken using Ah. When using a MPPT, the calculations are in Wh and the sub-system losses in the system include:Battery efficiency (watt-hr)Cable lossesMPPT efficiencyIn order to determine the energy required from the PV array, it is necessary to account for all the sub-system losses. Depending on how the hybrid system operates, the energy required at the battery in Wh is then divided either by all these three losses or just two losses (cable loss and MPPT efficiency) to determine the required energy to be provided by the array.For hybrid systems having a generator as back up, it is recommended that the total daily energy required is used to determine the daily energy requirement from the PV array and conservatively it is assumed that all the energy is provided via the battery.For hybrid systems where generator operates daily, it is recommended that the energy value used to determine the daily energy requirement from the PV array is:Total Energy requiredminus the energy provided directly by the generatorminusthe energy supplied by the batteries charged by the generatorFor hybrid systems where the generator is operating daily, a specified portion of the daily load energy requirement will be agreed to be met by the array during the day, and the daily energy requirement from the array calculated above will be divided into 2 parts:First part: that portion to be supplied by the PV array during the day. This will not need to be increased to take the battery efficiency into account.Second part: that portion of the load provided by the battery bank as charged by the PV array – this figure will need to be increased to take the battery efficiency into account.2. Oversize FactorAs the hybrid system includes a fuel generator, the oversize factor of 10% (which is the recommended oversize factor for Kenya in the absence of a fuel generator) need not be included. The fuel generator would be sufficient to provide the equalisation charge to the battery bank.3. Derating Module PerformanceThe PV array will be de-rated due to:a. Manufacturer’s Output ToleranceThe output of a PV module is specified in watts and with a manufacturing tolerance based on a cell temperature of 25 degrees Celsius. Historically this has been 5%, but in recent years typical figures have been -0% and +5%. When designing a system it is important to incorporate the actual figure for the selected module.b. Derating Due to DirtThe output of a PV module can be reduced as a result of a build-up of dirt on the surface of the module. The actual value of this derating will be dependent on the actual location; some city locations might have a high dirt derating due to car pollution; some coastal locations might have a high dirt derating due to salt build up; and some locations might have long periods with no rain to naturally wash the modules. If in doubt, an acceptable dirt derating value would be 5%.c. Derating Due to TemperatureA solar module’s output power decreases with temperature above 25°C and increases with temperatures below 25°C. The average cell temperature will be higher than the ambient temperature because of the glass on the front of the module and the fact that the module absorbs some heat from the sun. The output power and/or current of the module must be based on the effective temperature of the cell. This is determined by the following formula:Tcell-eff = Ta.day + 25°CWhere:Tcell-eff = the average daily effective cell temperature in degrees Celsius (°C)Ta.day = the daytime average ambient temperature for the month that the sizing is being undertaken.The three different solar modules available on the market each have different temperature coefficients. These are:Monocrystalline ModulesMonocrystalline Modules typically have a temperature coefficient of –0.45%/oC. That is for every degree above 25oC the output power is derated by 0.45%.Polycrystalline ModulesPolycrystalline Modules typically have a temperature coefficient of –0.5%/oC.Thin Film ModulesThin film Modules have a different temperature characteristic resulting in a lower co-efficient typically around 0%/°C to -0.25%/°C, but remember to check with the manufacturer.The derating of the array due to temperature will be dependent on the type of module installed and the average ambient maximum temperature for the location.The typical ambient daytime temperature in many parts of Kenya is between 25 and 40oC during some parts of the year. So it would not be uncommon to have module cell temperatures of 65oC or higher.With switched controllers, the temperature effect was used to determine the operating current of the module/array. With MPPT’s, the temperature derating power factor must be calculated.Therefore the derated module output power (Pmod) is calculated as follows:The Power of the module at STCmultiplied by derating due to manufacturers tolerancemultiplied by derating due to dirtmultiplied by derating due to temperaturePstc x fman x fdirt x ftempIf a module has a 3% (0.03) manufacturer’s tolerance, the module current is derated by multiplying by 0.97 (1-0.03).If a module has a 5% (0.05) loss due to dirt, the module current is derated by multiplying by 0.95 (1-0.05).If a module is operating at an ambient temperature of 30 degrees and a temperature coefficient of -0.5%, it has a 15% (0.15) loss due to temperature (0.5%x(30+25-25)). The module current is derated by multiplying by 0.85 (1-0.15).4. Number Of Modules Required In ArrayTo calculate the required number of modules in the array, divide the required array power by the adjusted (i.e. derated) module power. The exact final number required will depend on the MPPT selected, and then matching the array to the MPPT voltage operating windows.5. Selecting MPPTThe output voltage of the MPPT shall match the battery voltage selected. The maximum input power rating of the MPPT shall be equal to or greater than the rated power of the array.The maximum input current rating of the MPPT must be equal to or greater than the rated current of the array. Note that the current of the array will be dependent on the number of parallel strings, while the number of parallel strings will be dependent on the number of modules in series in each string. The number of modules in series must match the operating voltage window of the MPPT as detailed below.Matching the PV Array to the Voltage Specifications of the MPPT The MPPT typically will have a recommended minimum nominal array voltage and a maximum voltage. In the case where a maximum input voltage is specified and the array voltage is above the maximum specified, the MPPT could be damaged.Some MPPT controllers might allow the minimum array nominal voltage to be the same as that of the battery bank. However the MPPT will work better when the minimum nominal array voltage is higher than the nominal voltage of the battery. Please check with the MPPT manufacturer because these could vary.It is important that the output voltage of the string is matched to the operating voltages of the MPPT and that the maximum voltage of the MPPT is never reached.The output voltage of a module is affected by cell temperature changes in a similar way to the output power. The manufacturers will provide a voltage temperature coefficient. It is generally specified in V/°C (or mV/°C) but it can also be expressed as a %.To ensure that the Voc of the array does not reach the maximum allowable voltage of the MPPT, the minimum day-time temperatures for that specific site are required. In early morning at first light, the cell temperature will be very similar to the ambient temperature because the sun has not had time to heat up the module. In Kenya, the average minimum temperature is 200C (this could be lower in some mountain areas) and it is recommended that this temperature is used to determine the maximum Voc. (Note: If installing systems in the mountains use the appropriate minimum temperature. Many people also use 0°C, if appropriate for the area). The maximum open circuit voltage is determined similarly to the temperature derating factor for the power.1.6.4PV Array Sizing: a.c. Bus - Loads Supplied Directly by ArrayPlease refer to start of section 1.6.2 for information on solar irradiation for Kenya.1. Daily Energy Requirement from the PV ArrayThe size of the PV array should be selected to take account of:Seasonal variation of solar irradiationSeasonal variation of the daily energy usage being supplied directly by the arrayCable losses (d.c and a.c)Grid connect inverter efficiencyManufacturing tolerance of modulesDirtTemperature of array (the effective cell temperature)The sub-system losses in the system include:Cable losses, d.c. and a.c.Grid Connect Inverter EfficiencyIn order to determine the energy required from the PV array, it is necessary to account for all the sub-system losses. The a.c. energy that is being supplied directly during the day is increased by dividing by the d.c. cable losses, the grid connect inverter efficiency and the a.c. cables losses. (Note: the a.c. cable losses are those between the grid connect inverter and the a.c. point of attachment, which is usually the main switchboard or nearest distribution board)2. Oversize FactorAs the hybrid system includes a fuel generator, we don’t have to consider an oversize factor. 3. Derating Module PerformancePlease refer to derating module performance section in section 1.6.3 for determining the derating of the module performance.4. Number Of Modules Required In ArrayTo determine the PV array output power required (in W) the daily energy requirement from the array (in Wh) is divided by the selected daily irradiation value (that is, the PSH). Since there is a generator in the system, the PSH could be the yearly average or, if the generator run time needs to be reduced, it might be based on the worst month with respect to load energy and solar resource energy.To calculate the required number of modules in the array, divide the required array power by the adjusted (derated) module power. The exact final number required will depend on the grid connect inverter selected and then matching the array to the grid connect inverters voltage operating windows.Section 1.6.8 provides in detail how the select the grid connect inverter and matching it with the array.1.6.5PV Array Sizing: a.c. BUS - Loads Supplied by Battery Please refer to start of section 1.6.2 for information on solar irradiation for Kenya.1. Daily Energy Requirement from the PV ArrayThe size of the PV array should be selected to take account of:Seasonal variation of solar irradiationSeasonal variation of the daily energy usage being supplied directly by the arrayd.c Cable losses between array and grid connect inverterGrid connect inverter efficiencyA.c cables losses between the grid connect inverter and the battery inverterBattery inverter efficiency when operating as a battery chargerd.c. cable losses between the battery inverter and battery and back to the battery inverterWatt-hr efficiency of the battery bankBattery inverter efficiency when providing a.c. power from the battery bankManufacturing tolerance of modulesDirtTemperature of array (the effective cell temperature)The sub-system losses in the system include:Cable losses- a.c and d.c.Grid connect inverter efficiencyBattery inverter efficiency both when charging batteries and when providing a.c. power from the batteriesWatt-hr efficiency of the battery bankIn order to determine the energy required from the PV array, it is necessary to account for all the sub-system losses. The a.c. energy that is being supplied to the loads via the battery bank and charged by the PV array by dividing by the:d.c. Cable losses between array and grid connect inverterGrid connect inverter efficiencya.c cables losses between the grid connect inverter and the battery inverterBattery inverter efficiency when operating as a battery chargerd.c. cable losses between the battery inverter and battery Watt-hr efficiency of the battery bankd.c. cable losses between the battery and battery inverter Battery inverter efficiency when providing a.c. power from the battery bank 2. Oversize FactorAs the hybrid system includes a fuel generator, we don’t have to consider an oversize factor. 3. Derating Module PerformancePlease refer to derating module performance section in section 1.6.3 for determining the derating of the module performance.4. Number Of Modules Required In ArrayTo determine the PV array output power required (in W), the daily energy requirement from the array (in Wh) is divided by the selected daily irradiation value (that is the PSH). Since there is a generator in the system, the PSH could be the yearly average or if generator run time wants to be reduced it might be based on the worst month with respect to load energy and solar resource energy.To calculate the required number of modules in the array, divide the required array power by the adjusted (derated) module power. The exact final number required will depend on the grid connect inverter selected, followed by matching the array to the grid connect inverter’s voltage operating windows.Section 1.6.8 provides in detail how the select the grid connect inverter and matching it with the array.1.6.6PV ARRAY SIZING: A.C. BUS Sections 1.6.4 and 1.6.5 detail how to determine the size of an array in an a.c. bus system when loads were being supplied direct (1.6.4) and when loads were being supplied via the battery (1.6.5). In reality in an a.c. bus system the loads could be supplied by both and therefore determining the array will involve undertaking the two calculations, that is determining size of array to meet loads directly and the size of array meeting loads by battery and adding the two array sizes to get the total array size required.For hybrid systems with generator as back up then it is recommended that all the daily energy required is used to determine the daily energy requirement from the PV array and for conservatism it is assumed that all the energy is provided via the battery.For hybrid systems having a generator as back up, it is recommended that the total daily energy required is used to determine the daily energy requirement from the PV array and conservatively it is assumed that all the energy is provided via the battery.For hybrid systems where generator operates daily, it is recommended that the energy value used to determine the daily energy requirement from the PV array is: Total Energy requiredMINUS the energy provided directly by the generatorMINUSthe energy supplied by the batteries charged by the generatorFor hybrid systems where the generator is operating daily, a specified portion of the daily load energy requirement will be agreed to be met by the array during the day, and the daily energy requirement from the array calculated above will be divided into 2 parts:First part: that portion to be supplied by the PV array during the day. This will not need to be increased to take the battery efficiency into account.Second part: that portion of the load provided by the battery bank as charged by the PV array – this figure will need to be increased to take the battery efficiency into account.1.6.7 Battery Inverter SelectionThe type of battery inverter selected for the installation depends on factors such as cost, surge requirements, power quality and for inverter/chargers, a reduction of the number of system components required.Inverters are available in 2 basic output types (topologies): modified square (or sine) wave and sine wave. Modified square (sine) wave inverters generally have good surge and continuous capability and are usually cheaper than sine wave types. However, some appliances, such as audio equipment, television and fans can suffer because of the output wave shape.Sine wave inverters often provide a better quality power than the 240V grid supply. If affordable to the end-user, it is recommended that sine wave inverters be used. There are many types of battery inverters available:Inverter only (modified square wave or sine wave)Inverter/Charger: this converts to being a battery charger when there is another a.c. power source available e.g. fuel fired generator (modified square wave or sine wave)Interactive inverters: These act as inverter chargers, but the inverter can synchronise with the fuel generator. (Sine wave only)Multimode inverters: these are similar to the interactive inverter, but having an extra feature whereby they can provide the a.c. supply for the grid connect inverters to operate even while the multimode inverters is operating in battery charger mode.The selected inverter should be capable of supplying continuous power to all AC loadsANDCapable of providing sufficient surge capability to start any loads that may surge when turned on and particularly if they turn on at the same time.Where an inverter cannot meet the above requirements, attention needs to be given to load control and prioritisation strategies.However in some hybrid systems, where the generator operates daily, the inverter might be sized based on its battery charging capability, meaning it has a larger VA rating than that required to meet the continuous power requirements.For a.c bus systems, the battery inverter also needs to be sized according to the size of the solar array. The battery inverter must be sized so that all the solar power in Kw required for charging the battery bank can be provided through the battery inverter. A conservative approach is that the battery inverter kVA rating is 80% of the grid- connect inverter rating. However this figure could be reduced based on the amount of power that is supplied directly to the loads and the fact that solar power does vary throughout the day. However it is important that solar power is not wasted, meaning the solar might not be able to charge the batteries because of the capacity of the battery inverter. 1.6.8Grid Connect Inverter for a.c. Bus system1. Inverter SizeThe selection of the inverter for the a.c. bus system will depend on:The power output of the arrayMatching the allowable inverter string configurations with the size of the array in kW and the size of the individual modules within that arrayInverters are typically rated for:Maximum d.c. input power, i.e. the size of the array in peak watts;Maximum d.c. input current; andMaximum specified output power, i.e. the a.c power they can provide to the grid; The maximum power of the array is calculated by the following formula:Array Peak Power = Number of modules in the array X the rated maximum power (Pmp) of the selected module at STC.The designer must follow the manufacturer’s recommendation when matching the peak power rating of the array to that of the inverter. If the manufacturer does not have specific recommendations, the designer should follow the following guidelines for specifying the rating of the inverter. Worked Example:Using the information from the previous examples, what is the maximum d.c. input power of the array? Answer:As previously calculated, the peak power of the array is 4kWp. Does that mean the inverter should be rated at 4kW?Many inverter manufacturers provide the maximum rating of a solar array in peak power for a specific size inverter. Designers shall follow the recommendations of the manufacturer. If the manufacturer does not provide any recommendations, the designer could match the array to the inverter allowing for the derating of the array.In the section on Derating Module performance, the typical PV array output in watts is derated due to:Manufacturer’s tolerance of the modulesDirtTemperatureInverter with Crystalline ModulesBased on figures of:1 for manufacturers' tolerance, 0.95 for dirt derating, and 0.85 for temperature derating (Based on ambient temperature of 30°C )The derating of the array is: 0.1 x 0.95 x 0.85 = 0.80As a result of this method of derating being experienced in the field, the inverter can easily be rated at 80% of the peak power of the array and possibly even less. However, if possible, confirm with your inverter supplier.Inverter with Thin Film ModuleThe temperature effect on thin film modules is less than that on crystalline modules. Assuming the temperature coefficient is only -0.1%/°C, the temperature derating at ambient temperature of 30°C is 0.97.Based on figures of:1 for manufacturer’s tolerance, 0.95 for dirt derating, and 0.97 for temperature derating (Based on ambient temperature of 30°C) The derating is: 1 x 0.95 x 0.97 = 0.915As a result of this method of derating being experienced in the field, the inverter can easily be rated at 91% of the peak power of the array and possibly even less. However if possible confirm with your inverter supplier.Worked Example:What would the maximum input power rating of an inverter be if the 4kWp system were connected to a) crystalline modules, b) thin film modules?Answer:The array peak power is 4kWp .a) With crystalline modules, this array can be connected to an inverter with an output rating of:0.8x 4kW = 3.2kW (for crystalline modules)b) With thin film modules, this array can be connected to an inverter with an output rating of:0.91x 4kW = 3.64kW (for thin film modules)2. Matching Array Voltage To Inverter Operating VoltagesThe output power of a solar module is affected by the module’s cell temperature. As shown in previous sections for multicrystalline PV modules, this effect can be as much as 0.5% for every degree variation in temperature. This variation in power due to temperature is also reflected in a variation in the open circuit voltage and maximum power point voltage.Most inverters will have an operating voltage window. If the solar array voltage is outside this window, the inverter will either not operate or the output power of the system will be greatly reduced. Most inverters will also have a minimum and maximum input voltage, which will be specified by the manufacturer. If the maximum input voltage is exceeded, the inverter could be damaged. Some inverters will nominate a voltage window within which they will operate, and then also include a maximum voltage, higher than the maximum operating voltage of the window: this figure is the voltage where the inverter could be damaged.For best performance of the system, the output voltage of the solar array should be matched to the operating voltages of the inverter. To minimise the risk of damage to the inverter, the maximum voltage of the inverter shall never be reached.As stated earlier, the output voltage of a module is also affected by changes in cell temperature. As cell temperature increases, output voltage decreases. As cell temperature decreases, output voltage increases. The PV module manufacturers will provide a voltage temperature co-efficient. It is generally specified in V/°C (or mV/°C), but it can be expressed in %/°C .To design systems where the output voltages of the array do not fall outside the range of the inverter’s d.c. operating voltages and maximum voltage (if different), the minimum and maximum day time temperatures for that specific site are required.The following sections detail how to determine the minimum and maximum number of solar modules allowed to be connected in series to match the operating voltage window of an inverter. Many of the inverter manufacturers have software programs for doing these calculations. Ensure that the temperature information for each design is site-specific. MINIMUM VOLTAGE WINDOWWhen the temperature is at a maximum, the Maximum Power Point (MPP) voltage (Vmp) of the array should never fall below the minimum operating voltage of the inverter. The actual voltage at the input of the inverter is not just the Vmp of the array, the voltage drop in the d.c. cabling must also be included when determining the actual inverter input voltage.Since the array is typically operating with irradiance levels of less than 1kW/m?, the actual MPP voltage can be reduced further. It is recommended that a safety margin of 10% on the lower inverter window is included. Worked Example:Using the information from the previous examples, what is the minimum number of modules that can be connected in a string to an inverter with a minimum input voltage of 150V? Assume that the module has a Vmp of 36.0V and that the MPP voltage co-efficient is 0.18V/°C. Assume a voltage drop of 3% and that the maximum cell temperature experienced is 75°C.Note: The voltage coefficient for Vmp and Voc are slightly different. If the coefficient for each is provided, use them accordingly. If only the voltage coefficient for Voc is provided, it can be used for Vmp calculations. Answer:The Vmp of a module is 36.0V. The difference between the cell temperature and STC is (75°C -25°C) = 50°CFor every degree Celsius, the voltage is reduced by 0.18V. Therefore, the reduced Vmp of the module is 36.0 – (50 x 0.18) = 27.0V.Assuming the voltage drop is 3%, the further reduced Vmp of a module is (28.0 x 0.97) = 26.19V.The minimum input voltage of the inverter is 150V. After adding the 10% safety margin, the new minimum input voltage is (150V x 1.1) = 165V.The minimum number of modules that can be connected in a string is then (165V / 27.16V) = 6.3. This number must be rounded up, therefore the minimum number of modules that can be connected in a string to this inverter = 7.MAXIMUM VOLTAGE WINDOWAt the coldest daytime temperature, the open circuit voltage of the array shall never be greater than the maximum allowed input voltage for the inverter. The Open Circuit voltage (Voc) is used because this figure is greater than the MPP voltage and it is the applied voltage when the system is first connected – prior to the inverter starting to operate and connecting to the grid.Note: Some inverters provide a maximum voltage for operation and a higher voltage as the maximum allowed voltage. In this situation, the MPP Voltage is used for the operation window and the open circuit voltage for the maximum allowed voltage.In early morning, at first light, the cell temperature will be very close to the ambient temperature because the sun has not had time to heat up the module. Therefore the lowest daytime temperature for the area where the system is installed shall be used to determine the maximum Voc. It is recommended that a safety margin of 5% on the maximum input voltage is included. Worked Example:Using the information from the previous examples, what is the maximum number of modules that can be connected in a string to an inverter with a maximum input voltage of 600V? Assume that the module has a Vmp of 41.0V and that the Voc co-efficient is 0.16V/°C. Assume that the minimum cell temperature experienced is 0°C.Answer:The Voc of a module is 41.0V. The difference between the cell temperature and STC is (0°C -25°C) = -25°CFor every degree Celsius, the voltage is increased by 0.16V. Therefore, the increased Voc of the module is 41.0 – (-25 x 0.16) = 45.0V.The maximum input voltage of the inverter is 600V. After subtracting the 5% safety margin, the new maximum input voltage is (600V x 0.95) = 570V.The maximum number of modules that can be connected in a string is then (570V / 45V) = 12.7. This number must be rounded down, therefore the maximum number of modules that can be connected in a string to this inverter = 12.In this example, each string must consist of between 7 -12 modules only. As we required 16 modules, we could have two parallel strings of 8 modules. It is important that the number of modules in a string is selected to ensure that the output voltage of the array is always within the voltage operating window of the inverter.1.6.8 Battery ChargerThe output of a fuel-fired generator is usually a.c. and must be converted to d.c. for the purpose of battery charging. The device that does this rectification is called a battery charger. The battery charger should be selected such that it converts the 240-volt, 50 Hz a.c. to d.c. at the required voltage for the battery storage bank. It should be able to provide a continuous direct current up to the maximum allowable charge rate of the batteries. The efficiency of the battery charger also needs to be considered. If it is not specified, the average efficiency can be calculated by dividing the average d.c. output power by the average a.c. input power to the battery charger. When the battery charger is selected, the battery charger’s maximum and continuous AC requirement, and maximum and continuous DC output can be obtained from the specifications. For transformer type chargers, the charging rate at low battery voltages is determined by the maximum output capability of the charger and will reduce at higher battery voltages. For solid-state chargers, the charging current is fixed until the battery bank nears full charge, at which point the charging current is reduced to a 'float' level.The battery manufacturer must specify the maximum rate of charging current from the battery charger. This is generally rated at the 10h rate.The maximum charge rate is:Ibc=0.1×C10That is, it is 10% of the C10 capacity of the battery.A separate battery charger is typically used when the inverter is just an inverter. In many hybrid systems, the inverter acts as a charger as well as being an inverter.1.6.8 Selecting and Sizing Fuel fired GeneratorFuel fired generators are energy sources that serve the purpose of supplying energy to a load in the event that the main energy source is not available or underperforms or when the load demand is larger than the main energy source can provide. They are run intermittently and aid in demand management. Although having a comparatively higher fuel cost than any renewable energy source, as well as their fuel base being of a fossil nature, they do provide assistance at times when a constant and quality supply of electricity cannot be provided.Fuel generators are very useful in the context of Hybrid applications in the case that a solar power system is not able to provide enough energy to satisfy a particular load demand. They are also useful in the purpose of charging batteries or even being directly connected to the load demand so as to provide a continuous supply of electricity to the Hybrid system, depending on the particular set-up of the system.The critical factors for selecting a fuel generator are-:Whether the fuel generator can meet all the power requirements of the appliances that need to be operated when the fuel generator is operating. The total of these requirements is the apparent power (VA) of the appliances. In general the battery charger must be considered a load.Not to oversize the fuel generator, because operating fuel generators at “light” loading will lead to increased wear and tear and greater maintenance requirements.Possible configurations for generator in a Hybrid system are:-Switched: which can be either with a separate inverter and charger as shown in Figure 3 or similar to that shown in Figure 4, where the interactive inverter shown is actually an inverter/charger and the switching for the loads from the generator to the inverter is internal. These types of systems are always configured as d.c. bus.Parallel: where the inverter is interactive and synchronises with the generator. These can be configured d.c. bus and a.c. bus depending on the type of inverter.Switched Configuration - The key feature of a switched configuration is that the output from the fuel generator may supply both the battery charger and the a.c loads directly (refer to figure 3). When the fuel generator is not running, the a.c loads will be switched to the inverter. A changeover switch may do the switching between the fuel generator and inverter automatically, or this can be done manually. In either case, it is essential that the changeover switch or contactor shall have a ‘break-before-make’ action. Where a manual changeover switch is used, a switch with a “centre-OFF” position is recommended. The battery charger, inverter and automatic changeover contactor may be incorporated into a single unit (inverter-charger).If the inverter output is not synchronised before changeover, a break in supply of at least 500ms should ideally be maintained. This will prevent arcing of the contacts and increase the life of the contactor. The length of time required of the break in supply depends on the type of loads being supplied. Large inductive loads may require 500ms or more, while 30ms may be adequate for standard household loads. A switched configuration provides reasonably efficient utilisation of the fuel generator power, but does require that a.c loads are tolerant of short breaks in supply. Desktop computers operating on this kind of system will require their own mini-UPS system, or extremely careful co-ordination between computer usage and changeover time. Alternatively, a dedicated inverter (sized specifically to suit the sensitive a.c equipment), and separate wiring could be used for loads requiring no-break power. In this case, the low volt cut-out setting on the no-break inverter should be set to minimum in order to avoid drop out due to battery voltage dips caused by load surges in the main inverter. A parallel system, by contrast provides no-break power but it is not ideal in every situation. An intermediate form is a switched system using a very fast changeover. This requires that the inverter synchronises first, before changing over, and that the changeover contactor has a very fast action, operating in less than one cycle. This may be short enough not to affect the operation of sensitive loads. The availability of trained personnel may be another factor in the decision whether to use a manual switched system.Figure 3: Switched ConfigurationGenerator Sizing for Switched ConfigurationThe fuel generator must be sized to meet the AC demand when the fuel generator is operating, as well as the demand of the battery charger. The fuel generator must also be capable of meeting the surge demand. The fuel generator should therefore be sized to meet the following two formulae:Sgen = (Sbc + Smax chg.) x fgoWhere: Sgen = Minimum apparent power rating of the fuel generator. (VA)Sbc = max apparent power consumed by the battery charger under conditions of max output curent and typical max charge voltage. (VA)Smax.chg = max a.c. demand during battery charging (VA)fgo = Fuel generator oversize factor.And,Sgen= (Sbc + Ssur.chg) fgo Alt Surge RatioWhere: Sgen = Minimum apparent power rating of the fuel generator. (VA)Sbc = max apparent power consumed by the battery charger under conditions of max output curent and typical max charge voltage. (VA)Ssur.chg = max a.c. surge demand during battery charging (VA)fgo = Fuel generator oversize factor.Parallel Configuration - The key feature of a parallel configuration is the use of an interactive inverter i.e. one which allows bi-directional power flow. An interactive inverter works as an inverter or battery charger, and is capable of synchronising with, and supplying a.c power in parallel with, a fuel generator (refer to figure 4). A contactor (or contactors) under the control of the inverter connects a.c. loads to the inverter or the fuel generator or both. When operating in parallel with the fuel generator, the direction and magnitude of power flow through the inverter at any instant is controlled to ensure optimal (or near optimal) loading of the fuel generator and battery charging at the highest possible rate, while at all times meeting the load demand. This configuration provides the best use of the fuel generator, and the highest quality of output power (a pure sine wave, without breaks in the supply voltage). Some inverters even “clean up” the fuel generator output waveform. A parallel configuration may also allow the battery size to be greatly reduced. An important practical consideration is that the inverter’s allowable voltage and frequency window must be wide enough to cope with the range of operation of the fuel generator. Switched systems are preferable to parallel systems where the quality of fuel generator power is poor, such as with an old fuel generator supplied by the client. The issue here is that a fuel generator with poor governing and/or voltage regulation may cause difficulties for an interactive inverter trying to maintain synchronism. A switched system may also be considered when the charging capacity of interactive inverters is inadequate for the battery and system operating conditions. An important concept in parallel systems is that of synchronisation. For two a.c. power sources to operate in parallel, they must be synchronised before being connected together; the voltage from each source must be identically matched in frequency and phase, as well as amplitude. This also means that the inverter must produce a pure sine wave output.It is much simpler to control the inverter output to achieve synchronisation, than to control the fuel generator. The inverter already has all the internal circuitry to completely control its output - whereas a fuel generator requires additional synchronising gear. For an alternator, synchronisation means physically synchronising the rotation of the machine with the voltage waveform of the supply that it is synchronising with. The cost of this scale of equipment is such that it is usually only considered for fuel generators around 100kVA or more, and would be used where two or more fuel generators are required to operate in parallel, i.e. only used with large capacity (high cost) systems. Figure 4: Parallel SystemGenerator Sizing for Parallel ConfigurationIn parallel systems, the fuel generator and inverter sizing are interrelated. Therefore the combined ratings of the fuel generator and inverter can be sized to meet the maximum demand and surge demand of the loads.The following equations may be used to determine the minimum fuel generator sizing:Sgen = (SmaxSinv30min) fgoWhere: Sgen = Minimum apparent power rating of the fuel generator. (VA)Smax = max apparent a.c. power demand (VA)Sinv30min= 30 min apparent power rating of the inverter (VA)fgo = Fuel generator oversize factor.And,Sgen= (Ssur Sinv.sur) fgo Alt Surge RatioWhere: Sgen = Minimum apparent power rating of the fuel generator. (VA)Ssur = surge rating of the loads (VA)Sinv.sur = surge rating of the inverter (VA)fgo = Fuel generator oversize factor.However, in practice the fuel generator will be larger because many other factors must be considered. These include:Whether the maximum demand is required for long periods during the day, when the customer might not want the fuel generator operating for that length of time.Whether the fuel generator using the inverter to charge the batteries forms part of the design of the hybrid system. If the inverter is acting as an “inverter” for long periods of time when the fuel generator is operating, the batteries are not being charged. This could result in longer fuel generator running time than originally planned.Sometimes a parallel inverter is selected just for its ability to change between fuel generator and inverter without having any break in power supply and therefore the paralleling feature is not required in the system sizing.If the fuel generator is only required to operate every 2nd or 3rd day to meet the requirements to charge the batteries, the inverter must be sized to meet the maximum demand and the fuel generator sized to meet demand plus battery charging as per the formulas for switched systems.1.6.9 Fuel Generator Control StrategiesIn addition, the actual operation of the fuel generator will depend on how the fuel generator is controlled, which could be:if the fuel generator starts at a pre-determined time each day, the battery’s depth of discharge will vary and the fuel generator run-time will vary;if the fuel generator is started on ‘low battery’ state of charge, the fuel generator start time will vary each day, and the frequency of starts may vary;if the fuel generator is started on both time of day or state of charge, the result will be a mixture of the above, depending on which condition is reached first.The variations in operating conditions mentioned above may have serious consequences. Firstly, the client may only want the fuel generator to start during certain times of the day. Secondly, and more importantly in a PV-fuel generator system, if the fuel generator fully charges the battery in the morning just before the PV array starts to generate, valuable PV power may be wasted and fuel consumption and fuel generator operating time may increase. Avoiding these potential problems requires careful analysis of the implications of battery sizing and fuel generator control strategies in relation to the points mentioned above.1.6.10 Summary of Losses in a Hybrid SystemIn a Hybrid system the various losses under different cases are presented below in the figure 5 and the losses are shown in table 1 below. -89752831807700-561340339626Figure 5 Losses in Hybrid SystemFigure 5 Losses in Hybrid SystemSummary of Losses in Hybrid PV System ( Valid for a.c bus and d.c. bus )Table 2 Summary of Losses in a.c Hybrid SystemCase 1: PV charges battery with standard controller & battery supplies AC loadsCase 2: PV charges battery via MPPT controller & battery supplies AC loadsCase 3: PV is connected to Grid connect Inverter and charges batteries via interactive & batteries supply load Case 4: Generator charges battery & battery supplies AC loads- Current from inverter is specifiedCase 5: Generator supplies AC loads directlyCase 6: PV connected to grid connect inverter and supplies AC loads directly1) Battery columbic efficiency losses when charging (typ~10%)1) Cable losses between the PV array to MPPT (typ <1%)1) Cables losses between the PV array to grid connect inverter (typ <1%)1) Battery columbic efficiency losses when charging (typ~10%)Wh of the loads is supplied directly by generator1) Cables losses between the PV array to grid connect inverter (typ <1%)2) AC interactive inverter efficiency losses (typ~7-12%)2) MPPT efficiency losses (typ~4-5%)2) Grid connect inverter efficiency losses (typ~4-5%)2) AC interactive inverter efficiency losses (typ~7-12%)2) Grid connect inverter efficiency losses (typ~4-5%)3) Cable losses between MPPT and battery (typ <1%)3) Cable losses between grid connect inverter and interactive inverter and battery (typ <1%)4) Battery watt-hour efficiency losses when discharging (typ~20%)4) AC interactive inverter efficiency losses (typ~7-12%) acting as charger5) Cable losses between battery and AC interactive inverter (typ <1%)5) Cable losses between AC interactive inverter and battery (typ <1%)6) AC interactive inverter efficiency losses (typ~7-12%)6) Battery watt-hour efficiency losses (typ~20%)7) Cable losses between battery and AC interactive inverter (typ <1%)8) AC interactive inverter efficiency losses (typ~7-12%)1.7 CABLE SELECTION-ARRAY Figure 6: Double insulated solar d.c. cableCables used within the PV array shall:Be suitable for d.c. application.Have a voltage rating equal to or greater than the PV array maximum voltage determined in table 3.Have a temperature rating according to the application.If exposed to the environment, cables should be UV-resistant, or be protected from UV light by appropriate protection, or installed in UV-insulated conduit,Be water resistant.If exposed to salt environments, cables must be tinned copper, multi stranded conductors to reduce degradation of the cable over time, In all systems operating at voltages above DVC-A, cables shall be selected so as to minimise the risk of earth faults and short-circuits. This is commonly achieved using reinforced or double-insulated cables, particularly for cables that are exposed or laid in metallic tray or conduit. This can also be achieved by reinforcing the wiring. Cables shall be flame retardant as defined in IEC60332-1-2.It is recommended that string cables be flexible (class 5 of IEC60228) to allow for thermal/wind movement of arrays/module.Cables should comply with PV1-F requirements or UL 4703 or VDE-AR-E-2283-4.Note: PV1-F cable requirements may be found in the document TUV 2 PfG 1169/08.2007.Correctly sized cables in an installation will produce the following outcomes:1. There is no excessive voltage drop (which equates to an equivalent power loss) in the cables.2. The current in the cables will not exceed the safe current handling capability of the selected cables known as current carrying capacity (CCC)Selection PV String CablesIf a fault current protection device is located in the string, then the string must be rated to carry at least that current. For example, if the fault current protection device is rated at 8A, then the string will need to be rated at a minimum of 8A.If no fault current protection is provided, then the string cable will be rated as:CCC ≥ 1.25 × ISC MOD × (Number of Strings - 1)Selection of PV Array CablesThe PV array cable should be rated according to:CCC ≥ 1.25 × ISC ARRAY and The cable should have CCC equal to or greater than the rating of the array protection device.There are a large number of other possible system configurations for a PV array, all of which have their own specific requirements. The following explains the requirements of some of the more complicated systems. 1.7.1 Sub-array A sub-array comprises a number of parallel strings of PV modules. The sub-array is installed in parallel with other sub-arrays to form the full array. The effect of this is to decrease the potential fault current through different parts of the system. In this case the following modifications will be necessary. PV Array CablesThe PV array cable should be rated according to:CCC ≥ 1.25 × ISC ARRAY And should have a CCC equal to or greater than the rating of the array protection device.PV Sub-array CablesIf a fault current protection device is located in the sub-array cable, the sub-array cable must have a rating equal to or greater than that of the fault current protection device.If no fault current protection device has been included then the current carrying capacity of the cable must be the greater of:1.25 × (sum of short circuit currents of all other sub‐arrays)or1.25 ×ISC Sub-ArrayPV String CablesIf sub-array fault current protection is used, the string cable rating will be the rated trip current of the sub-array fault current device plus the fault current of the other stings in the sub-array:Itrip-subarray + 1.25 × ISC MOD × (Number of Strings - 1)If no sub-array fault current protection device is used, the string cable rating will be:1.25 × (sum of short circuit currents of all other strings in the array):1.8 CABLE PROTECTION: ArrayAll cables shall be electrically protected from fault currents that could occur. In hybrid systems, the battery bank will produce these fault currents, so that all array cables shall require protection. The array cable will therefore require protection at the controller end of the array cable and this protection will typically be provided as a non-polarised circuit breaker (d.c. rated) that also acts as the array disconnector (refer section 1.12).Sub-array and string cable protection will be required if the current carrying capacity of these cables is less than the current rating of the array cable protection device. However if sub-array and string cable protection is not required due to fault currents from the battery they might still be required because of the currents from the solar modules as detailed below.Each solar module has a maximum reverse current rating, this figure is provided by the manufacturer. If the arrays consists of parallel strings, such that the reverse current flow into a string with a fault is greater than the maximum reverse current for the modules in that string, then protection shall be provided in each string. The protection is to be d.c. rated fuses. Example: The reverse current rating for a module is 15A while the short circuit current is 5.4A. If the array consists of 3 parallel strings and a fault occurs in one string then the potential fault current will come from the other 2 strings, which is only 10.8A (2 x 5.4), and which is less than the reverse current rating so no protection is required. However if the array consists of 4 parallel strings, then the fault current could come from the other 3 strings. This current is 16.2A (3 x 5.4) and is now greater than the reverse current rating of the module. Protection is now required.A formula for determining the maximum number of strings allowed before fuses is required is:Maximum Number of Strings without string protection= Reverse current rating of module/Isc of moduleSo in the above example: Max Number of strings = 15/5.4= 2.77 rounded off to 3.FusesFuses used in PV arrays shall—(a) Be rated for d.c. use;(b) Have a voltage rating equal to or greater than the PV array maximum voltagedetermined via table 3;(c) Be rated to interrupt fault currents from the PV array,; and(d) Be of an overcurrent and short circuit current protective type suitable for PV and complying with IEC 60269-6 (i.e. Type gPV).String ProtectionThe fuses shall have the following current rating:1.5 x Isc of module < Fuse Rating < 2.4 x Isc of moduleSub-Array ProtectionAn array may be broken up into sub-arrays for different reasons; for example, if two sections of the array are installed in separate areas. The need for sub-array overcurrent protection is similar in logic to that for string overcurrent protection – one sub-array could be operating differently from the other sub-arrays owing to shading or earth faults. The use of sub-array protection is to stop excessive currents from flowing into a sub-array.Requirements of Sub-array Overcurrent ProtectionSub-array overcurrent protection protects a sub-array made up of a group of strings. It is required if one of the following conditions is met: 1.25 × ISC_ARRAY > Current carrying capacity (CCC) of any sub-array cable, switching and connection device. More than two sub-arrays are present within the array.Sizing the Sub-array Overcurrent ProtectionIf sub-array overcurrent protection is required for a system, the nominal rated current for the overcurrent protection device will be as follows:1.25× ISC_SUB-ARRAY≤ITRIP≤2.4 × ISC_SUB-ARRAYWhere: ISC_SUB-ARRAY= short-circuit current of the sub-array.ITRIP= rated trip current of the fault current protection device.Array Cable ProtectionArray overcurrent protection is designed to protect the entire PV array cabling from external fault currents in the presence of batteries as we have in the Hybrid systems.Sizing the Array Overcurrent ProtectionIf array protection is required, the rated current of the overcurrent protection device will be the following:1.25×ISC_ARRAY ≤ ITRIP≤2.4×ISC_ARRAY Where:ISC_ARRAY= short-circuit current of the array.ITRIP= rated trip current of the overcurrent protection device.1.9 CABLE SELECTION-Voltage Drop Cable losses between the PV array and the controller (standard or MPPT) and battery bank should be as low as practical, consistent with cable size and cost decisions. Cable losses between the inverter and battery should ensure that the inverter does not trip due to low battery voltage when inverter is operating at continuous rating. The following should be applied:Cable losses between the PV array and the battery bank should never exceed 5%Cable losses between the PV array and the controller should never exceed 3%Cable losses between the PV array and the grid connect inverter in an a.c. bus system should never exceed 3%Cable losses between the battery bank and any DC load should never exceed 5%Cable losses between the battery bank and battery inverter should never exceed 5%.The following sizing methods (based on voltage drops) can be used for all types of currently available copper cable.1. Calculating Voltage DropVoltage drop is calculated using Ohm’s law:V=I×RCombining this with the formula for calculating resistance, the voltage drop along a cable is given by:VDROP = 2 × LCABLE ×I × ρA CABLEVoltage drop (in percentage) = VDROP VMAX × 100Where:LCABLE = route length of cable in metres (multiplying by two adjusts for total circuit wire length).I = current in amperes *?.ρ = resistivity of the wire in /m/mm2ACABLE = CSA of cable in mm2.VMAX = maximum line voltage in?volts?.Note:For systems using standard series controller , the ISC current (at STC) should be used andVMAX is equal to the battery nominal voltage.For systems using MPPTs as the controller , the IMP current (at STC) should be used and not the ISC current andVMAX is equal to the MPP voltage of the string or array at STC (VMP_STRING or VMP_ARRAY). For a.c bus systems with grid connect inverters , the IMP current (at STC) should be used and not the ISC current andVMAX is equal to the MPP voltage of the string or array at STC (VMP_STRING or VMP_ARRAY). For voltage drop between the inverter and battery bank: the continuous current (d.c.) of the inverter should be usedVMAX is equal to the battery nominal voltage_). 2.Using Tables - 1Voltage drop in volts per 10 metres of route length of twin cable (using the above formula):Wire size mm?23.257.515AmpsCCC15202545700.50.090.060.040.020.011.00.180.110.070.050.021.50.270.170.110.070.042.00.370.230.150.100.052.50.460.290.180.120.063.00.550.340.220.150.074.00.730.460.290.200.105.00.920.570.370.240.127.51.370.860.550.370.18101.831.140.730.490.24152.751.721.100.730.37202.291.460.980.49251.831.220.61301.460.73401.950.98501.22Notes: Cable size and CCC from Pirelli automotive dataShaded areas indicate that the CCC is exceeded Refer also, to PV module and Inverter manufacturers' recommendations.3.Using Tables - 2Route lengths to produce 5% voltage drop (12V systems) for twin cable ( using the above formula )Maximum Distance in metres to produce 5% voltage drop (12V system) Current (A)1mm21.5mm22.5mm24mm26mm210mm216mm2116.424.64165.698.4163.9262.328.212.320.532.849.282131.135.58.213.721.932.854.687.444.16.110.216.424.641.065.653.34.98.213.119.732.852.562.74.16.810.916.427.343.772.33.55.99.414.123.437.582.03.15.18.212.320.532.891.82.74.67.310.918.229.1101.62.54.16.69.816.426.2111.52.23.76.08.914.923.8121.42.03.45.58.213.721.9131.93.25.07.612.620.2141.82.94.77.011.718.7151.62.74.46.610.917.5161.52.64.16.110.216.4172.43.95.89.615.4182.33.65.59.114.6192.23.55.28.613.8202.03.34.98.213.11.10 Main Battery Cable: Selection and ProtectionOvercurrent protection and the ability to readily isolate a battery bank must be provided.Some inverters are supplied with battery cables already connected while for those not supplied with cable the size should either be determined by the designer or the manufacturers recommendations should be followed. As a minimum, the cable shall be capable of carrying the d.c. current required to provide the continuous power rating of the inverter. Note if the inverter does have a 1/2 hour power rating, this rating figure should be used for determining the minimum cable size. The cable should have a voltage drop less than the maximum allowable voltage drop specified in section 1.9. However inverters have a surge rating. Since the surge only occurs for less than 3 seconds the selected cable is not required to carry that current on a continuous and should not overheat in that time basis however the required surge current rating should be used to determine that the selected cable will not adversely effect the performance of the inverter when it is providing the surge rating. To select the appropriate main battery protection …Obtain Time-Current characteristics for the over current protection to be used.[All manufacturers publish time-current information for their circuit breaker and HRC fuse ranges]Obtain inverter manufacturers dataContinuous power rating (Watts )3 to 10 second surge rating(Watts )Average inverter efficiencyFor each inverter power rating determine the current drawn from the battery bank using …I = Inverter Power Rating ( W ) .(inverter efficiency x nominal battery voltage)NOTE: Allowance for any significant DC demand must be included when sizing the main protectionConsult the Time-Current characteristic to determine the appropriate rating.Since the battery must be capable of being isolated and also cable protection is required a suitable rated d.c. switch fuse as shown in figure 7 is often usedFigure 7: Battery Switch Fuse1.11 PLUGS and SOCKETSPlugs, sockets and connectors shall—Comply with EN 50521;Be protected from contact with live parts in connected and disconnected states (e.g. shrouded);Have a current rating equal to or greater than the current carrying capacity for the circuit to which they are fitted;Be capable of accepting the cable used for the circuit to which they are fitted;Require a deliberate force to separate;Have a temperature rating suitable for their installation location;If multi-polar, be polarized;Comply with Class II for systems operating above DVC-C;If exposed to the environment, be rated for outdoor use, be of a UV-resistant type and be of an IP rating suitable for the location;Be installed in such a way as to minimize strain on the connectors (e.g. supporting the cable on either side of the connector); andBe mated only with those of the same type from the same manufacturer. 1.12DC Switch disconnector at controller D.C. switch disconnector at the controllerIn accordance with IEC/TS 62548 there must be a method to isolate the power from the array at the controller. This switch disconnector shall be load breaking and break all non-earthed poles. However as specified in section 1.9, protection is also required for protecting the array cable from fault currents from the battery bank. Where a controller allows more than one input from the array a switch disconnector shall be installed on each input and these should be located physically beside each other near the controller. Signage should indicate that to operate the PV array all switch disconnectors must be operated together.Note:A switch disconnector not rated for the open circuit d.c.voltage (based on coldest temperature-refer to next section) of the array and 1.25 times the d.c. short circuit current of the array shall not be used as the PV Array Switch-disconnector. To meet the isolation and protection requirements it is recommended that a non-polarised d.c. rated circuit breaker is installed as close as possible to the controller.Voltage LimitsSystem voltage classification has been done as per the DVC as per IEC 62548 standard.Decisive voltage classification (DVC)Limits of working voltage (V)AC voltage (rms)AC voltage (peak)DC voltage (mean)AV ≤ 25V ≤ 35.4V ≤ 60B25 ?V ≤ 50 35.4 ?V ≤ 5060 ?V ≤ 120CV ? 50V ? 71V ? 120PV Array Maximum VoltageThe PV Array Maximum voltage can be calculated using the minimum expected temperature at a site and the temperature coefficient of a module. This calculation was completed earlier the worked example when calculating the maximum number of modules that can be connected in a string. If the temperature coefficients are not available, the PV Array Maximum voltage can be determined by using the below table containing the temperature ranges and multiplication factors.Table 3: Voltage correction factors for crystalline and multi-crystalline silicon PV modulesLowest expected operating temperature (degrees Celsius)Correction factor24 to 20 1.0219 to 151.0414 to 101.069 to 51.084 to 0 1.10-1 to -51.12-6 to -101.14-11 to -151.16-16 to -201.18-21 to -251.20-26 to -301.21-31 to -351.23-36 to -401.25Part 2: System Installation The performance of a reliable installation that fulfils a customer’s expectations requires both careful design and correct installation practice. Compliance with relevant Health and Safety regulations is necessary.2.1STANDARDS for INSTALLATIONSystem installs should follow any standards that are typically applied in the country or region where the solar installation will occur. The following are the relevant standards for Kenya. These standards are often updated and amended so the latest version should always be applied.The following Kenyan standards are applicable:KS 1672Glossary of terms and symbols for solar photovoltaic power generationKS 1673-1:2003Solar photovoltaic power systems-design, installation, operation, monitoring and maintenance-code of practice .Part 1:General PV KS 1673-2Generic specification for solar photovoltaic systems – system design, installation, operations, monitoring and maintenanceKS 1674Crystalline silicon terrestrial photovoltaic (PV) modules – design qualification and type approval KS 1675 Thin-film terrestrial photovoltaic (PV) modules – design qualification and type approvalKS 1676 Terrestrial photovoltaic (:PV) power generating systems – general and guideKS 1677Procedures for temperature and irradiance corrections to measured I-V characteristics of crystalline silicon photovoltaic devicesKS 1678Photovoltaic devicesKS 1679 UV test for photovoltaic (PV) modulesKS 1680 Overvoltage protection for photovoltaic (PV) power generating systems – guideKS 1681Characteristic parameters of hybrid photovoltaic systemsKS 1682 Salt mist corrosion testing of photovoltaic (PV) modulesKS 1683Rating of direct coupled photovoltaic (PV) pumping systemsKS 1684 Susceptibility of a photovoltaic (PV) module to accidental impact damage (resistance to impact test)KS 1685Photovoltaic system performance monitoring – guidelines for measurement, data exchange and analysisKS 1686 Analytical expression for daily solar profilesKS 1709-1:2009Batteries for use in photovoltaic power systems - Specification Part 1: General requirements.KS 1709-2:2009Batteries for use in photovoltaic power systems - Specification Part 2: Modified lead acid batteries KS 1709-4:2009Batteries for use in photovoltaic power systems - Specification Part 4: Recommended practice for sizing lead acid batteries for photovoltaic (PV) systems.KS IEC TS 62257-8-1:2007 Recommendations for small renewable energy and hybrid systems for rural electrification - Part 8-1: Selection of batteries and battery management systems for stand-alone electrification systems - Specific case of automotive flooded lead-acid batteries available in developing countriesKS IEC 61727 Photovoltaic (PV) systems - Characteristics of the utility interface KS IEC 62446:2009 Grid connected photovoltaic systems - Minimum requirements for system documentation, commissioning tests and inspection KS IEC 60904-1 Photovoltaic devices - Part 1: Measurement of photovoltaic current-voltage characteristics KS IEC 62093:2005 Balance-of-system components for photovoltaic systems - Design qualification natural environments.KS IEC 62124:2004 Photovoltaic (PV) stand-alone systems - Design verification.KS IEC 62116:2008 Test procedure of islanding prevention measures for utility-interconnected photovoltaic invertersKS IEC 61683:1999 Photovoltaic systems - Power conditioners - Procedure for measuring efficiencyKS IEC 62109-1:2010 Safety of power converters for use in photovoltaic power systems Part 1: General requirementsKS IEC 62109-2:2011 Safety of power converters for use in photovoltaic power systems Part 2: Particular requirements for inverters*being considered for adoptionThe following international standards (IEC) are applicable:IEC 60364-5Wiring rulesIEC 62548Photovoltaic (PV) arrays – design requirementsIEC 62305Protection against lightningIEC 61730.1Photovoltaic module safety qualification : requirements for constructionIEC 61730.2Photovoltaic module safety qualification : requirements for testingIEC 61215 Crystalline silicon terrestrial photovoltaic (PV) modules – Design qualification and type approvalIEC 61646 Thin-film terrestrial photovoltaic (PV) modules - Design qualification and type approvalIEC 61427-1* Secondary cells and batteries for renewable energy storage - General requirements and methods of test - Part 1: Photovoltaic off-grid applicationIEC 61427-2* Secondary cells and batteries for Renewable Energy Storage - General Requirements and methods of test - Part 2: On-grid application.IEC 61724* Photovoltaic system performance monitoring - Guidelines for measurement, data exchange and analysisIEC 61702* Rating of direct coupled photovoltaic (PV) pumping systems application.IEC/TS 62548Photovoltaic (PV) arrays – design requirementsIEC 62894* Photovoltaic inverters - Data sheet and name plate *being considered for adoptionVOLTAGE LIMITSSystem voltage classification has been done as per the DVC as per IEC 62548 standard.Decisive voltage classification (DVC)Limits of working voltage (V)AC voltage (rms)AC voltage (peak)DC voltage (mean)AV ≤ 25V ≤ 35.4V ≤ 60B25 ?V ≤ 50 35.4 ?V ≤ 5060 ?V ≤ 120CV ? 50V ? 71V ? 1202.2DOCUMENTATIONAll complex systems require a user manual for the customer. Hybrid PV systems are no different.The documentation for system installation that must be provided is …List of equipment supplied.Shutdown and isolation procedure for emergency and maintenance.Engineering certificate for wind and mechanical loadingInstaller/designer declaration of compliance with wind and mechanical loadingOperating instructionsMaintenance procedure and missioning sheet and installation checklist.Warranty information.System connection diagram (as installed).System performance estimateEquipment manufacturers documentation Array frame engineering certificateArray frame installation declaration andHandbooks for all equipment supplied.2.3 PV MODULESPV modules shall comply with the requirements of IEC 61730-1 and IEC 61730-2, or EN 61730-1 and EN 61730-2, or UL Standard 1703.2.4 PV ARRAYThe installation of the PV Array shall be in accordance with IEC/TS62548.ORIENTATION AND TILTIn hybrid systems the solar array is generally mounted:“Flat” on the roof (that is parallel to the slope of the roof) OR On an array frame that is tilted to fix the array at a preferred angle (usually for flat roofs or ground mounted) ORModules that are electrically in the same string must be all in the same orientation.For best year-round performance a fixed PV array should be mounted facing true north ( 10°) in the parts of Kenya that are in the southern hemisphere, and true south ( 10°) in the parts of Kenya that are in the northern hemisphere at an inclination equal to the latitude angle or at an angle that will produce the best annual average performance taking into consideration: seasonal cloud patterns, local shading and environmental factors. In the tropics this could vary due to the sun being both north and south at different times of the year. Note: A minimum tilt of 10° is recommended to take advantage of self-cleaning during rain periods.Horizontally mounted arrays will require additional maintenance [cleaning].For locations between the latitudes of 10° South and 10°North, the array should be tilted at a minimum of 10 degrees.73850529210LATITUDE ANGLEe.g. for MOMBASA ( Lat 4o S )True NORTHPV Module00LATITUDE ANGLEe.g. for MOMBASA ( Lat 4o S )True NORTHPV Module48196599695True SouthPV ModuleLATITUDE ANGLEe.g. for LODWAR ( Lat 3o N)00True SouthPV ModuleLATITUDE ANGLEe.g. for LODWAR ( Lat 3o N)The optimum tilt angle would be approximately 4° for Mombasa and 3° for Lodwar. However, to account for self-cleaning, the tilt angle of both should be around 10°.If the array is “flat” on the roof (that is parallel to the slope of the roof) or integrated into the building fabric, the array will often not be at the preferred (optimum) tilt angle and in many situations will not be facing due north or due south.Annex 3 provides PSH data on the following sites:Mombasa (Latitude 04°03′S Longitude 39°40′E?)Nairobi (Latitude 01°17' S' Longitude 36°49' E)Wajir (Latitude 01° 45' N Longitude 40°03 E)Lodwar (Latitude 03°07'N, Longitude 35°36'E)Annex 4 provides a diagram showing estimated tilt and orientation losses for a location with a latitude of 1°N. Using these figures will provide the system designer/installer with information on the expected output of a system (with respect to the maximum possible output) when it is located on a roof that is not facing true north (for the southern hemisphere) or south (for the northern hemisphere), or at an inclination equal to the latitude angle. The designer can then use the peak sun hour data for their particular location to determine the expected peak sun hours at the orientation and tilt angles for the system to be installed. ROOF MOUNTINGIf the modules use crystalline cells then it is preferable to allow sufficient space below the array (> 50mm or 2 inches) for ventilation cooling. This will be subject to the constraints of the customer or architect.It is important to allow sufficient clearance to facilitate self cleaning of the roof to prevent the build up of leaves and other debris.If fauna are a problem in the vicinity of the installation then consideration should be given to how to prevent them gaining access under the array.(see cable protection)All supports, brackets, screws and other metal parts should be of similar material or stainless steel to minimise corrosion. If dissimilar metals (based on their galvanic rating) are used then the two surfaces of the metals should be separated by using rubber washes or similar.Where timber is used it must be suitable for long-term external use and fixed so that trapped moisture cannot cause corrosion of the roof and/or rotting of the timber. The expected replacement time should be stated in the system documentation.Any roof penetrations must be suitably sealed and waterproof for the expected life of the system. If this is not possible then this must be detailed in Maintenance TimetableAll fixings must ensure structural security when subject to the highest wind speeds for the region and local terrain - This may require specific tests of the fixing/substrate combination on that roof.The installer shall ensure that the array frame that they install has applicable engineering certificates verifying that the frame meets wind loadings for that particular location. The installer must follow the array frame suppliers/manufacturers recommendations when mounting the array to the roof support structure to ensure that the array structure still meets wind loading certification. All external wiring must be protected from UV and mechanical damage in such a manner that it will last the life of the system.(See cable Protection).FREE STANDING PV ARRAYS These must be wind rated in accordance with relevant wind loading standardsPOLE MOUNTED PV ARRAYS For small solar home systems the array could be mounted on a pole. These must be wind rated in accordance with relevant wind loading standards2.5 OUTDOOR MOUNTED COMBINER BOXESArrays that require string, sub-array or array protection should use a string and/or array combiner box to house the system protection and to interconnect the strings and/or sub-arrays. A combiner box can also be used when there is no overcurrent protection required, as it can provide protection for cable interconnections.The array and/or sub-array combiner box must have an appropriate IP rating for its location: a minimum IP rating of 54 plus UV resistance for outdoor equipment. The manufacturer’s instructions will outline the process for maintaining the IP rating. For example, all cable entries into the combiner box should be through the bottom to prevent water ingress.Installers may be tempted to drill holes into the box for drainage or ventilation. However, drilling holes into the box will void the IP rating and so should never be done.Figure 8: Outside combiner boxNote: Ensure that the combiner box does not shade the array.2.6 PV ARRAY SWITCH DISCONNECTORThe switch-disconnector ( recommended to be a double pole non-polarised d.c. circuit breaker) used should have an appropriate IP rating for its location. However the controller is typically located under cover and hence so will the PV array disconnector.The switch disconnector should be located beside the controller.2.7CONTROLLER INSTALLATIONThe controller can be located anywhere between the array and the battery bank however it is often located near the battery bank.The controller should be:Installed in a dust free environmentInstalled in a location that minimises the controller being in excessive temperatures due to the outside ambient temperatureThe controllers' heat sink must be clear of any obstacles to facilitate cooling of the inverter. The manufacturers recommended clearances must be followed.Since controllers often have screens or Leds providing information to the end user consideration should be given to its location so that it is easily accessible by the system owner.2.8INVERTER INSTALLATIONThe inverter should be:Installed as close as possible to the battery bank to minimise voltage drop.Installed in a dust free environmentInstalled in a location that minimises the inverter being in excessive temperatures due to the outside ambient temperatureMechanically supported where it is mountedSince inverters often have screens or LED’s providing information to the end user, consideration should be given to its location so that it is easily accessible by the system owner.The inverter’s heat sink must be clear of any obstacles to facilitate cooling of the inverter. The manufacturers recommended clearances must be followed.2.9 BATTERY INSTALLATIONAll batteries should be installed in a dedicated enclosure. The enclosure could be a dedicated battery room, a battery box just for the batteries or if installed within a large room or shed than the enclosure could be a fenced off area,Even the single battery small solar home systems should have the battery installed in a dedicated enclosure.Please refer to figures 9 through to 12 for examples of battery enclosure requirements.The main considerations for the battery enclosure are …A minimum horizontal separation of 500 mm shall be provided between the battery and all other equipment from 100 mm below battery terminals except where there is a solid separation barrier.If a battery is separately enclosed in a battery box with no other equipment installed in the box there is no need for 500 mm clearance from the battery to the walls of the battery box.Socket-outlets shall not be installed in the battery enclosure.Where the battery enclosure is part of a larger room (e.g. the battery enclosure is a fenced off area in a larger room), all socket-outlets shall be located at least 1800 mm from the battery enclosure and a minimum of 100 mm below the top of the battery or any battery vent, if within 5 m of the battery enclosure.No equipment shall be placed above the batteries or battery enclosure except for non-metallic battery maintenance equipment.A purpose-built equipment enclosure may be installed above a purpose built battery enclosure where all of the following apply:A sealed (valve regulated) battery is installed in the battery enclosure.A gas proof horizontal barrier is in place between the battery enclosure and the equipment enclosure.The battery and equipment enclosures are accessed separately (e.g. via separate doors).The ventilation paths for the battery enclosure and the equipment enclosure are specifically designed to minimize the possibility of air exhausted from the battery enclosure entering the air inlets on the equipment enclosureIt should not be in located in direct sunlight.Extreme ambient temperatures should be avoided because low temperatures decrease battery capacity and high temperatures shorten battery lifeIt must be safe, with restricted access ( ie. prevent children easily accessing the batteries )All equipment must be readily accessible for maintenanceIt must have adequate ventilationIt should be vermin proofExhaust air shall not pass over other electrical devices.Battery enclosures should be designed to prevent formation of gas pockets.Ventilation outlets should be at the highest level of battery enclosure.The ventilation inlets should be at a low level in the battery enclosure. They should not be higher than the top of the battery cells.To ensure airflow does not pass the battery, the ventilation inlets and outlets should be on opposite sides of the enclosure however figure 14 shows what to do if this is not possible.The supporting surface of the enclosure should have adequate structural strength to support the battery bank weight and its support structure.The enclosure should be resistant to the effects of electrolyte, either by the selection of materials used or by appropriate coatings. Provision should be made for the containment of any spilled electrolyte. Acid resistant trays in which the batteries sit should be capable of holding electrolyte equal to the capacity of at least one cell of the battery bank. Any enclosure doors should allow unobstructed exitThe main safety considerations are …Explosion due to a spark in the presence of hydrogen build upExcessive currents caused by battery shortsLeakage of battery acid from battery cellsPersonal safety in the presence of acidTo negate the risk of explosion there must be no opportunity for hydrogen to build up. This requires adequate ventilation with no possibility of spark ignition.Figure 9: Battery installed in a dedicated equipment room showing clearances from equipmentFigure 10: Battery enclosure within a room where the battery enclosure is vented outside the buildingFigure11: Battery enclosure with equipment enclosure immediately adjacentFigure12: Battery enclosure with the intake and outlet vents on the same wall2.10VENTILATION OF BATTERIESVentilation must be provided. The minimum area required for natural ventilation for both inlet and outlet apertures (for wet lead acid batteries) are given by …A = 100qv cm?Where qv is the minimum exhaust ventilation rate in litres per second = 0.006 x n x Iandn = the number of battery cellsI = the charging rate in amperes For vented wet lead acid batteries the charging rate in amperes is the maximum output rating of the largest charging source or the rating of its output fuse or circuit breaker. Where two parallel battery banks are used, the charging rate is halved.For valve regulated (sealed) batteries the charging rate I in the ventilation formula is 0.5A per 100Ah at the 3h rate (C3)of discharge of battery capacity for lead acid batteries.e.g. battery has C3 rating of 500Ah therefore the charge current used in ventilation formula is :(500Ah/100Ah) x 0.5A = 2.5ANote; This is based on the charger (either solar controller or separate grid power battery charger) has an automatic overvoltage cut-off. If not maximum change current must be used. Best practice is to provide input ventilation vents below the level of battery and the output vents on the opposite side of the batteries, as high as possible in the enclosure to prevent hydrogen build up.2.11PREVENTING SPARK IGNITION SOURCES NEAR BATTERIESElectrical equipment or storage for other equipment should not be mounted above the battery bank.Connection or disconnection of any equipment at the battery terminals must not occur where there is any possibility of the presence of any hydrogen build up.Battery charging equipment should be hard wired - do not use a temporary connection.Battery terminals should be shrouded to prevent inadvertent short circuits.Ensure sufficient clearance between battery terminals and metal walls (or insulate using non-metallic sheet)Maximise separation between battery terminalsUse insulated tools during any battery workBattery fusing preferably should not be in the same enclosure as the battery bank but if they are then they should be either a minimum of 500mm away from the batteries or 100mm below the top of the batteries. Another method to keep the fuse separate from the battery bank is to place a vertical partition between the batteries and the fuse, thereby keeping the fuse as close to the batteries as possible but isolated from any hydrogen build up. In any case the main battery fusing should be located below the battery vents. (Normally below the top of the batteries).2.12PREVENTING EXCESSIVE CURRENT FROM BATTERIES Battery shorts are prevented by shrouding terminals and ensuring safe separation between live terminals.Battery shorts are controlled by using appropriate circuit protection.Overcurrent protection is to be provided in each battery output conductor except where one side of the battery bank is earthed (ground), in which case only the unearthed (ungrounded) conductor requires overcurrent protection.Normal practice is to either fuse the positive and earth (ground) the negative or fuse all conductors.2.13 BATTERY SAFETY AND WARNING SIGNSA “Battery Explosion Warning" sign must be mounted so that it is clearly visible on approach to the battery bank. An "ELECTROLYTE SAFETY" sign should be mounted adjacent to the battery bank.2.14 GENERATOR INSTALLATIONThe fuel fired generator should be installed in a separate room or shed that only contains the gen-set and ancillary equipment such as controller, fuel tank etc. The following is a number of major bustion and Cooling Air SupplyAir is essential both for the combustion and the cooling process. As a rule of thumb, cooling requires six to eight times as much air as combustion. Air intake and exhaust vents should be located to permit smooth air flow over the set. The air should be as cool as possible at the time it reaches the air cleaner. In excessively dusty conditions, additional intake filtration may be required. Cooling fans/vents should not face the predominant windy directions so as to minimise the ingress of dust and dirt.Fuel SupplyDepending on the size of the generator, the fuel tank may be a small gravity feed unit, a base mounted unit, an external day tank or an underground tank. Fuel storage should comply with any local regulations.ExhaustIf the flow of exhaust gases is restricted, back pressure will restrict the power output of the engine. The exhaust pipe should be of adequate diameter for the length, and if bends are to be included they should be of long radius. If the exhaust pipe is mounted to a fixed structure, a flexible fitting must be included to isolate the line from engine vibration.Because heat derates an engine, those exhaust components adjacent to the generating set should be lagged with heat resistant material.Mechanical and Exhaust NoiseNoise from the generator comprises both exhaust noise and general mechanical noise. To attenuate mechanical noise, it will be necessary to insulate the interior of the gen-set room with a sound retardant material. It is common to fit noise attenuating louvers to the air intakes and outlets.Exhaust noise can be attenuated by fitting a silencer, or muffler. The degree of attenuation depends on the standard (and cost) of the silencer. The direction at which exhaust is discharged will also affect noise levels. Battery SystemThe starting battery must have sufficient capacity to crank the engine under cold start conditions, and to attempt multiple starts if required.Ancillary Electrical EquipmentElectrical installation must be carried out by a licensed electrician. A circuit breaker will be required, and instruments, both for the 12/24 Volt system and for the 415/240 Volt system should be fitted.FoundationThe foundation is generally a concrete slab, capable of at least 1000 psi, and typically three times the mass of the set.2.15CABLE INSTALLATIONAll cables shall be installed in a neat and tidy manner and in accordance with IEC 60364-5.All cables used in the installation should be securely fixed in place to minimise any movement of the cable. Where the cables could be damaged then there should be suitable mechanical protection of the cables.Where the presence of fauna is expected to constitute a hazard, either the wiring system shall be selected accordingly, or special protective measures shall be adopted. All conduits exposed to sunlight must be suitably UV rated. Not all corrugated conduits are UV rated so if using corrugated conduit ensure that it is UV rated.Plastic cable ties are not suitable for cables in exposed situations and should not be used as the primary means of support unless they have a lifetime greater to or equal to the expected life of the system. Connection of a.c.. and d.c.. components in the same enclosure should be segregated.d.c.. wiring shall not be placed in a.c. switchboards.To avoid conductive loops the positive and negative cables of an array shall be run in parallel.Figure13: Avoiding the conductive loop between the positive and negative cablesWhen the array mounted on a roof, the solar module interconnect cables must be supported clear of the roof surface to prevent debris build up or damage to insulation.The installer shall ensure that all module connectors used are waterproof and connected securely to avoid the possibility of a loose connection. Only connectors of the same type from the same manufacturer are to be mated at a connection point.All unprotected and unearthed battery cables:not exceeding 2 m in length;used for the connection of a battery terminal and the battery overcurrent device; andcontained in a battery box, battery room or in a fenced off area specifically allocated for batteriesdo not require additional mechanical protection.For battery cables exceeding 2 m, the cables shall be protected by PVC conduit or equivalent protection.If the unprotected cable between the battery terminals and battery overcurrent device leave the battery box, battery room or in a fenced off area they shall be mechanically protected by PVC conduit or equivalent.2.16WIRING OF ARRAYS WITH VOLTAGE ABOVE DVC-AA dangerous situation occurs when the person installing the system is able to come in contact with the positive and negative outputs of the solar array or sub-array when the output voltage is above DVC-AMost hybrid systems use approved solar modules which are connected using double insulated leads with polarised shrouded plug and socket connections. Therefore the dangerous situation is only likely to occur for systems using MPPT's at:The PV Array switch-disconnector before the controller for systems; ANDThe sub-array and array junction boxes (if used). To prevent the possibility of an installer coming in contact with live wires on systems using MPPT's and voltage is above DCV-A it is recommended practice that one of the interconnect cables of each string (as shown in Figure 14) is left disconnected until all the wiring is complete between the array and the inverter. Only after all switch-disconnectors and other hard wired connections are completed should the interconnect of the array be connected.Figure14: Disconnected interconnect cable2.17 WIRING FROM ARRAYS WITH VOLTAGES ABOVE DVC-A TO PV ARRAY SWITCH-DISCONNECTOR NEAR CONTROLLERThe PV array cable shall be clearly identified as d.c. solar cable to ensure that it cannot be mistaken for a.c. cable.Between the array and the controller single core double insulated solar cable is used. This cable is similar to that used for interconnecting the solar modules in the array.PV d.c. cables between the array and the inverter shall be installed in conduit to reduce the risk of short circuit.2.18EARTHING OF ARRAY FRAMES (PROTECTIVE EARTH/GROUND)For systems with a voltage above DVC-A all non-electrical conductive parts of the system, such as the module frames and the mounting system, shall be equipotentially bonded. It is important to use appropriate methods for equipotential bonding, with consideration given to the potential of galvanic corrosion between galvanically dissimilar metals. Earth conductors should be in close proximity to the main PV array positive and negative conductors. The earth conductor shall pass in close proximity to the Inverter and then follow the output conductors of the Inverter, where possible, to avoid electrical interference generated by the inverter propagating to other parts of the system. The bonding earth should be connected to the main earth conductor without interrupting the conductor. That is one module can be removed without affecting the protective bonding of other modules in the array.There are two ways of doing this with:Specifically designed stainless steel washers that penetrate the non-conductive coating of aluminum frames and bond solar PV modules to the mounting structure and thereby create an electrical path to earth.(See figure 15 and 16).By using a lug on each module and then use earth wire that is continuous (no daisy chaining) between the modules.(Refer figure 17).All earth connections to the mounting rail should be sprayed with corrosion-resistant paint to protect the connection from corrosion from the weather.Figure15: Stainless steel earthing washersFigure16: Earthing washer (WEEB) under the mid-clampFigure17: Earth lugs used for earthing the modules.The earth bonding cable shall be a minimum of 4 mm2 unless it is also required for lightning protection and then it shall be a minimum of 16 mm2 (Refer Figure 9 of IEC TS 62548 for further information)2.19 SIGNAGEAll circuits, protective devices, switches and terminals shall be suitably labelled and all signs and labels shall be suitably affixed and durableThere should be a sign on the switchboard stating what is the maximum d.c.. array short circuit current and array open circuit voltage from the system.Any junctions boxes used between the array and the inverter should have a sign “Solar d.c..” on the cover. All d.c junction boxes shall carry a warning label indicating that active parts inside the boxes are fed from a PV array and may still be live after isolation from the PV inverter and public supplyA single line wiring diagram shall be displayed on siteEmergency shutdown procedures shall be displayed on siteA “Battery Explosion Warning" sign must be mounted so that it is clearly visible on approach to the battery bank. An "ELECTROLYTE SAFETY" sign should be mounted adjacent to the battery bank.2.20 COMMISSIONINGIncluded with this guideline is an installation checklist (Annex 1) which can be used by the installer when they have completed the installation to ensure they have met these guidelines.The commissioning checklist provided (Annex 2) with these guidelines shall be completed by the installer. A copy shall be provided to the customer in the system documentation and a copy retained by the installer.Part 3: System MaintenanceA hybrid system that has been correctly installed and commissioned should operate with minimal intervention, however a PV system and batteries does need regular inspection and maintenance to ensure that it is operating efficiently, find any problems and to maximise its lifetime. The suggested system maintenance can be broken down into three components: PV array maintenance, inverter maintenance and balance of system maintenance.3.1 PV Array Maintenance The PV modules and the mounting system should be inspected every 12?months. The modules should be cleaned of any dirt or debris and any vegetation shading the array should be trimmed.Visual InspectionThe modules should be checked annually for any visible defects, such as module yellowing, micro-fractures and hot spots (Figure 18).Figure 18 - : a) A yellowed module, b) micro-fractures in a module and c)?a module hotspot.Mounting System InspectionThe mounting system should be checked annually to make sure that the modules are securely mounted and the mounting system is suitably attached to the roof. The mounting system should also be checked for any cracks, corrosion or signs of weakening.Module CleaningThe modules may need to be cleaned manually if they are installed in a dusty area, if there has been a prolonged period without rain or if they were installed at a small tilt angle (less than 10°). This Some principles for cleaning PV modules are as follows:PV modules should be cleaned using only water: no detergents, solvents, caustic solutions or acid wash should be used.Abrasive materials should not be used to clean the modules; a soft broom can be used to remove loose debris and gently scrub away harder soiling, such as bird droppings.Leaf matter or animal nests should be gently cleared from beneath the array.Avoid hosing or brushing any electrical cable junctions, combiner boxes, disconnectors, etc.The module manufacturer may provide instructions on recommended cleaning practices for their modules.Vegetation ManagementAny vegetation that is shading the modules should be trimmed back. This is especially relevant for ground-mounted arrays, as they tend to be closer to the ground and surrounded by vegetation. Grazing animals could be kept around a ground-mounted array to keep vegetation levels down.3.2 Controller MaintenanceInverters require very little ongoing maintenance:Keep the unit clean to minimise the possibility of dust ingress. Clean the controller housing when required.Ensure the unit is free of insects and spiders.Ensure all electrical connections and cabling are kept clean and tight. It is recommended that the system owner checks the controller' display every couple of days to check that the PV system is working correctly.3.3 Battery BankThe batteries are the most maintenance intensive component in a hybrid power system. Please remember that batteries are dangerous so ensure that all tools are suitable for undertaking maintenance and that the room is well ventilated and that there is no build-up of hydrogen before entering the room.The following maintenance should be undertaken at reasonable intervals. Battery maintenance should be undertaken at least every 6 months with the following exceptions:After the initial installation, it is recommended that the Specific Gravity readings (for wet lead acid battery installations) are taken monthly to ensure that the system is charging the batteries adequately. Once the customer is satisfied then this could be undertaken along with all the other maintenance.Some wet lead acid batteries might require that the electrolyte level is checked monthly or quarterly.Battery Bank maintenance should include:Read and record electrolyte density - specific gravity (flooded batteries)Check and record cell voltageCheck electrolyte level, top up where necessary - record water usageCheck all battery connections and cable terminations for security and corrosionCheck for mechanical damage to battery cells or casesClean batteries and battery areaA sample of a maintenance log sheet is shown in Table 4.Table 3: Example Battery Log SheetDateDateDateDateBattery VoltageAmbient TemperatureCell 1S GElectrolyte Temperature Corrected SGCell Volts……Cell xS GElectrolyte Temperature Corrected SGCell VoltsInterconnections OK?Battery Cases OK?Comments3.4 Inverter Maintenance (Battery and Grid Connected)Inverters require very little ongoing maintenance:Keep the unit clean to minimise the possibility of dust ingress. Clean the inverter housing and air filters when required.Ensure the unit is free of insects and spiders.Ensure all electrical connections and cabling are kept clean and tight.3.5 Balance of System MaintenanceThe balance of system equipment should be inspected annually to ensure that everything is mechanically secure and there are no signs of damage. The inspection should cover:Cables and cable clipsConduitEarth connectionsDisconnectorsCircuit breakers and fusesSignage.In addition, disconnection devices and circuit breakers should be checked for correct operation and system signage should be checked for visibility.During the inspection, the system’s battery voltage and array current should be measured and recorded.It is recommended that all module string connections and all other connections on the DC cables between the array, the controller, the grid connect inverter and the batteries and the batteries to the battery inverter are visually inspected for damage and loose connections. If possible, it is advisable to use a thermal imaging (i.e. infrared) camera for undertaking part of this inspection. In large systems where there are multiple combiner boxes, taking a thermal image of each junction box could help find loose connections before they become a safety issue.3.6 Fuel Generator maintenancePlease note that major manufacturers also provide useful information on maintenance.In a Hybrid PV system where the fuel generator is used regularly, then the fuel generator is usually the component requiring the most maintenance. The maintenance schedule should be provided by the manufacturer and is dependent on the number of operating hours. A sample maintenance schedule for a generator is as follows (always consult the manufacturer’s handbook):Change Oil every 100h (modifications for extended running can extend this)Change air, oil and fuel filter every 250hEngine Overhaul 5,000hReplacement of engine 20,000hIf the fuel generator is water cooled, then hoses and coolant will require changing periodically.A sample of a generator log book is shown in Table 4 (Note: Tick when changed).Table 4: Example Generator Log SheetDateFuel generator Total Hours RunOil ChangedFuel FilterOil FilterAir FilterCommentsAnnex 1: System Installation ChecklistItem NoType of ItemNoRequiredDetailsOKPV module 1PV Module - Model XYZ-902Series combination of modules3Parallel combination of modules4Solar Mounting structure5Hardware for connecting module to frame6Hardware for connecting frame to roof (if required)Solar Controller7Cable between module & solar regulator8Conduit9Fastening hardware for cable/conduit10Solar Regulator - Model ABC-4011Hardware for fastening controller to wall12Fuse/Circuit breaker between solar module/controllerBatteries13Batteries - Model BBB 40014Timber (if battery floor mounted)15Battery racks/stands (if required)16Battery Box (if required)17Coverings for terminals (if required)18Cable between controller and battery19Lugs or fasteners for cable connection to battery20Battery fusing21Adequate Battery enclosure is providedInverter 22Inverter - Model INV-5000P23Inverter Power rating (Continuous , ? minute and Surge)24Transformer / Transformerless25Cable between batteries and inverter26Cable between charger and batteries27Lights for shed/battery room28Light Switches29Cable between controllers/batteries and lights30Fastening hardware for lights/switches31Fastening hardware for lighting cable32Installation Tools (recommend technician prepares a list)Fuel Generator33Type of fuel generator (petrol, diesel, ethanol, biodiesel, LPG)34Capacity (KVA)35Expected Run timeCompulsory Safety Equipment:33Safety Goggles34Leather Gloves35Water Washing bottle36Bicarbonate Soda37Water Bucket____________________________Authorisation I, …………………………………… acknowledge that the following system has been installed to the standards indicated by these guidelines Name of the person for whom the system was installed: ……………………………………………………………………………Location of system: ……………………………………………………………………………Signed: …………………………………………………………………Date: …../…../….. Licence/Qualification number: ………………………………………… Attach a separate sheet detailing any departuresAnnex 2: Testing and Commissioning ChecklistTO BE DEVELOPED.Annex 3: Table showing Peak Sun hours for various sites and tilt anglesLocationPeak Sunlight Hours (kWh/m?/day)MombasaJanFebMarAprMayJunJulAugSepOctNovDecAnnual AverageLatitude: 4°03′ South 0° Tilt?5.715.985.625.094.534.444.534.805.395.485.475.545.21Longitude: 39°40′ E?ast4° Tilt?5.796.025.625.144.624.564.644.875.415.505.535.635.2719° Tilt?5.895.995.425.194.824.854.904.995.315.415.585.765.34NairobiJanFebMarAprMayJunJulAugSepOctNovDecAnnual AverageLatitude: 1°17′ South 0° Tilt?6.336.776.575.765.295.055.165.486.296.055.515.985.85Longitude: 36°49′ East?1° Tilt?6.366.796.585.775.325.085.205.506.296.065.536.015.8716° Tilt?6.646.886.425.855.615.465.545.676.206.065.696.306.02WajirJanFebMarAprMayJunJulAugSepOctNovDecAnnual AverageLatitude: 1°45′ North 0° Tilt?6.046.436.095.545.384.944.965.315.795.415.025.365.52Longitude: 40°03′ East?1° Tilt?6.086.466.105.555.404.964.985.325.795.435.045.405.5416° Tilt?6.526.686.025.545.555.165.145.375.655.505.295.815.68LodwarJanFebMarAprMayJunJulAugSepOctNovDecAnnual AverageLatitude: 03°07′ North 0° Tilt?6.116.506.315.725.715.585.636.086.535.995.615.805.96Longitude: 35°36′ East?3° Tilt?6.246.596.335.745.765.655.696.126.536.045.715.946.0318° Tilt?6.706.816.235.675.875.845.856.146.296.136.036.436.16Annex 4: Tilt and Orientation diagram for 1°N.NW (315)?320325330335340345350355N (0)510152025303540?NE (45)?%LOSS??????????90???????????5%310?????????80?????????50?10%305?????????70?????????55?15%300?????????60?????????60?20%295?????????50?????????65?25%290?????????40?????????70?30%285?????????30?????????75?35%280?????????20?????????80?40%275?????????10?????????85?45%W (270)9080706050403020100102030405060708090E (90)?50%265?????????10?????????95?55%260?????????20?????????100?60%255?????????30?????????105??250?????????40?????????110??245?????????50?????????115??240?????????60?????????120??235?????????70?????????125??230?????????80?????????130????????????90????????????SW (225)?220215210205200195190185S (180)175170165160155150145140?SE (135)??68580008064500Annex 5: System Design A sample load assessment for a village with 20 households, a primary school, an elementary school, a healthcare centre, a teacher/health worker accommodation. The following the load assessment for the site has been done below-: BuildingsApplianceNo.Power (W)Usage Time (h)Energy (Wh)Primary School Lighting - Primary School172082720Computer - Primary School10400832000Security Lighting - Primary School16012720Elementary School Lighting - Elementary School6208960Security Lighting - Elementary School16012720Healthcare centreLighting - Healthcare Centre122081920Vaccine Fridge - Healthcare Centre2120122880Computer - Healthcare Centre140083200UHF Radio - Healthcare Centre120120Security Lighting - Healthcare Centre16012720Fan 1508400Teachers/Health Worker Accommodation GPO823059200Lighting242083840Typical load per house (20 such houses)GPO202301255200Lighting 402043200Fan205088000125700Table 5: AC Load (energy) AssessmentThe sample load profile for the site is also available to us and has been obtained by logging the data over a year.TimeEnergy Usage (Wh)Peak Demand (VA)Midnight to 1am387581291am to 2am380085512am to 3am382596423am to 4am397597144am to 5am387593385am to 6am4500107076am to 7am4700102797am to 8am4850125938am to 9am400088809am to 10am47871160110am to 11am4025992611am to noon36008213Noon to 1pm6500136581pm to 2pm8073162792pm to 3pm8500146413pm to 4pm8525152294pm to 5pm8300158205pm to 6pm6100120976pm to 7pm6250124247pm to 8pm6400121018pm to 9pm484095349pm to 10pm4250946710pm to 11pm4250741811pm to midnight39007010TOTAL125700The Peak Sun hrs (PSH) for the site is displayed in following table:PSH for site with optimal array tiltMonth(kWh/m?)Jan5.07Feb5.49Mar5.28Apr5.15May5.15June5.10July4.99Aug4.81Sep4.66Oct4.78Nov4.53Dec4.41Avg4.95The selected module for the system will have the following specifications (Used for AC Bus system):Rated Power (Pmax)? 175W Warranted minimum power 170W Voltage at Pmax (Vmp) 35.4V Current at Pmax (Imp) 4.9A Short circuit current (Isc) 5.5A Open circuit voltage (Voc) 44.5V Temperature coefficient of Isc (0.065±0.015)%/?CTemperature coefficient of Voc (160±20)mV/?CTemperature coefficient of Pmax (0.5±0.05)%/?CNOCT? 47±2?CMaximum series fuse rating 15A Maximum system voltage 600VBattery types available: ModelC1C3C5C10C1004 OPzV 2401081511752002405 OPzV 3001351892192503006 OPzV 3601622272633003605 OPzV 4001802522923504006 OPzV 5002253153654205007 OPzV 6002703784384906006 OPzV 7203244545266007208 OPzV 96043260570180096010 OPzV 12005407568761000120012 OPzV 140063088210221200140012 OPzV 1700765107112411500170016 OPzV 23001035144916792000230020 OPzV 29001305182721172500290024 OPzV 350015752205255530003500DC bus system Key design parameter-:System DC voltage is 120 VController rating is 120 V @ 50ADirt derating = 0.95Battery coulombic efficiency = 90%Inverter efficiency while supplying loads = 95.5%Battery Daily depth of discharge = 50%Fuel Generator operates between 5pm to 11 pm every nightContinuous inverter charging current 125 AThree-phase DC bus inverter being used.When PV charges the batteries via a standard controller and battery supplies AC loads Total Load = 125700Wh per day. (From table 5 above)Inverter efficiency is 95.5% therefore load as supplied by the batteries = 125700/0.955= 131624WhLoad in Ah = 131624/120 = 1097 AhBattery Efficiency = 90%Ah required from PV array= 1097/0.9 = 1219 AhCurrent at 28V and NOCT is 5.2A (Note: If you can’t determine this from I-V curves then you can select a current ? way between Isc and Imp )Manufacturer’s tolerance factor = 170/175=0.97Dirt = 0.95Derated output of module = 5.2 x 0.97 x 0.95 = 4.79Output in Ah from each string = 4.41 x 4.79 = 21.13 Number of strings required = 1219/21.13 = 57.69 We can round down to 57 we are looking at worst month.Number of modules in string = 120/24 = 5Total number of modules –285 therefore rating of array – 175 x 285 = 49,875 WNow the controller allows 50A maximum. The module has Isc of 5.5A so maximum number of strings per controller = 50/5.5 = 9Number of controllers required 57/9 = 6.33Therefore 7 controllers would be required.Selecting Battery Bank ConfigurationBattery bank’s daily depth of discharge is 50%. So we now have to choose a suitable configuration for the battery bank. We know the load is 1097 Ah. So at a depth of discharge of 50% we would need 2 x 1097 = 2194 Ah battery capacity at C10.Battery capacity of 2500 Ah would be suitable (20 OPzV2900—2500Ah each).Number of batteries in each string = 120/ 2 = 60.Total number of batteries = 60When the generator supplies to load directlyAmount of load energy that will be supplied directly by the generator, from 5pm to 11 pm every night = 32090WhAC load energy supplied by the batteries = 125700Wh – 32090Wh = 93610WhWith an inverter efficiency of 95.5%, the load as seen by the battery is 93610 / 0.955 = 98020.9WhLoad in Ah = 98020.9 / 120 = 816.8 AhTherefore with 50% depth of discharge per day, we would need a battery with capacity 2 x 816.8 = 1633.7 AhThis should be the C10 capacity.One string with 60 x 16 OPzV 2300 batteries would be sufficient.Adding batteries to the systemThe continuous current from each inverter when charging is 125 A. With one bank of batteries the total charge current the batteries will take is 200 A, while the inverters will provide 125 A. One inverter would be recommended in order to handle the current requirements.Therefore in over 6 hours the battery would receive 6 x 125 A = 750 Ah from charging. Based on 90% energy efficiency the battery bank will be able to meet loads via the inverter as big as 0.9 * 750 = 675 Ah.At 95.5% inverter efficiency, the load energy that will be directly supplied from the battery through the inverter (from the charging from generator or inverter) is 675 x 0.955 = 644.625 AhThis represents: 644.625 x 120 = 77355 WhHow much energy would be provided to the solar array based on the above?At this point, the generator supplies 32090 Wh, and the batteries provide 77355 Wh from charging by the generator/inverter. The PV array must then supply: 125700 – 32090 – 77355 = 16255WhThe inverter efficiency of 95.5% then requires the energy from the batteries to be: 16255 / 0.955 = 17020.9WhThe battery bank, at 120V, then represents: 17020.9 / 120 = 141.8 AhWith a coulombic efficiency of 90%, the required battery array Ah is = 157.55 AhThe current at 28V is not provided, but with the Imp is 4.9 A and the Isc is 5.4 A, we can assume it is the halfway point: 5.2 A.Accounting for manufacturer tolerances, = 170 W module minimum / 175 W rated power = 0.97And assuming that the site is not too dusty or dirty, we take 0.95 for dirt derating.The derated current is then: 5.2 x 0.97 x 0.95 = 4.799 AOutput in Ah from each string = 4.41 (worst PSH month for the location) x 4.799 = 21.16 AhNumber of strings required =157.55 / 21.16= 7.445 Rounded down = 7 stringsNumber of modules in string = 120V / 24V = 5 modulesTotal number of modules 7 x 5 =35 Therefore the array rating is = 175 x 35= 6125 WThe controller can only handle 50 A maximum. With Isc 5.5 A in the module, the maximum number of strings is = 50 / 5.5 = 9 strings.Number of controllers required = 7 / 9 = 0.77 = 1 controllers required.AC bus system designKey design parameter-:System DC voltage is 48 VDirt derating = 0.95Battery Columbic efficiency = 90%Inverter efficiency while supplying loads and charging batteries = 96%Battery Daily depth of discharge = 50%Fuel Generator operates between 5pm to 11 pm every nightContinuous inverter charging current 100 ABattery watthr efficiency is 80%Using the data specified above, the system will be going to be supplied by an AC bus system. The system will consist of 3 SMA Sunny Island, 6 kVA inverters (Based on the maximum KVA demand of 16.279 KVA as per the load profile). These will be placed one for each phase (3 phases total). The inverters have an efficiency of 96%, both when providing AC power to the loads and as a battery charger.The batteries will be selected from the Sonnenschein range of batteries. The watthr efficiency is 80%. Assume dirt derating is 0.95.When the generator supplies to load directlyThe generator operates from 5 pm to 11 pm every night. The load energy that is supplied directly by the generator, as calculated earlier, is: 32090 WhScenario: Adding batteries to the systemAssume all the load energy not supplied by generator is supplied by a battery bank which has a daily depth of discharge of 50%. The AC load energy supplied by the batteries: 125700 – 32090 = 93610 WhThe load seen at the battery at an inverter efficiency of 96% = 97510.4 WhLoad in Ah = 97510.4 Wh / 48 V= 2031.47 AhConsidering a depth of discharge rate of 50%, 2031.47 x 2 =4062.9 Ah.Looking at the Sonnenchein battery capacities table (Table 2), for a 4062.9 Ah, you can have at a minimum 2 batteries of 2500 Ah each in parallel.It is important that when selecting battery banks that if possible, so that the battery bank required is large enough, that you ensure all the charge current from the inverters is used.There are several ways to combine the batteries.1. One Battery Bank of 1500Ah capacity on each of the three Sunny Island inverters. 2. One Battery bank of 2500Ah capacity on two Sunny Island inverters. (Not recommended as this would mean an imbalance and also one of the SI inverter may not function in the absence of a battery bank).sIt is important that when selecting battery banks that if possible (that is battery bank required is large enough) ensure all the charge current from the inverters are used.Number of batteries in a string = 48/2 = 24Total number of batteries = 72 (1 string of 1500 Ah on each Sunny Island inverter).Maximum charge current that the batteries can accept and whether the inverters can supply that continuous charge currentThe maximum charge current the battery bank will accept is:The 4500Ah battery bank (total) would allow for 450A of charging. There are 3 inverters with maximum continuous charge of 300A (100A each). So batteries can take maximum charge current.Load Energy supplied directly by the generator through charging the batteries via the inverterThe inverter provides a continuous current whilst charging of 420A. Therefore over 6 hours, the battery will take: 6 x 300 = 1800 Ah from charging.At a 90% coulombic efficiency, the energy out of the battery to the inverter will be 0.90 x 1800 = 1620 Ah At 96% inverter efficiency, the load energy that would be directly supplied from the charging from the generator/inverter is = 1555.2 AhWith a voltage of 48 V, this represents 1555.2 x 48 = 74649.6WhSolar array addition to the AC bus systemEnergy supplied by PV for the above caseFrom earlier, the energy provided by generator from 5 to 11 pm is 32090Wh, the batteries provide The PV array therefore must supply: 125700 – 32090 – 74649.6 = 18960.4Wh When 60% of the energy that comes from the array will go to the loads directly, while the other 40% required will come from the solar array charging the batteriesAssume the following:Cable losses when the array is providing load energy via the batteries: 3%When providing load energy directly from PV : 2%From earlier, manufacturer tolerance derating is 0.97, dirt derating is 0.95, and the rated module power is 175 W. We assume that the maximum effective cell temperature for this site is 70 degrees Centigrade.Temperature derating is 1 – (0.005 x (70-25)) = 0.775Effective Module Power Pmod= 175 x 0.97 x 0.775 x 0.95 = 124.99 WTaking into consideration the lowest performing month in terms of PSH: Energy from each module from: EPV = Pmod x Htilt = 124.99 x 4.41 = 551.15WhTotal subsystem losses from PV to load = PV-to-load efficiency x PV-to-inverter efficiency = 0.98 X 0.96 = 0.94The total subsystem loss from PV to load through the batteries is then: PV-thru-battery-to-load efficiency x PV-to-inverter efficiency x inverter-to-battery efficiency x battery efficiency x inverter efficiency = 0.97 x 0.96 x 0.96 x 0.8 x 0.96 = 0.687The energy in the AC system is then: Eac = Epv-ac + Ebatt-acWhere: Epv-ac = 0.60 x 18960.4 = 11376.24Whand, Ebatt-ac = 0.40 x 18960.4 = 7584.16WhTotal number of modules: N = Npv-ac + Nbatt-acWhere: Npv-ac = (Epv-ac) / (Pmod x Htilt x subsystem loss PV-to-load) = 11376.24 / (124.99 x 4.41 x 0.94) = 21.965 and, Nbatt-ac = (Ebatt-ac) / (Pmod x Htilt x subsystem loss PV-thru-battery-to-load) = 7584.16 /(124.99 x 4.41 x 0.687) = 20.027 Total Number of modules are = 21.965 +20.027 = 41.992 Let us round this up to the nearest multiple of 3, which are 42 modules.We can choose 3 Sunny boy 3000TL inverters with 14 modules on each inverter. ................
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