Too much of a good thing: Inverter hyper-clipping

In earlier articles we’ve already pointed out that inverter clipping isn’t as significant as most people think, and that in a grid-power-constrained system it may be economically optimal to have a rather large DC-to-AC ratio. But what if there was a situation that resulted in significantly higher (and unexpected) inverter clipping losses of 30% or more? We’ll show you how to understand and avoid these cases of inverter “hyper-clipping.”

What really happens when inverters clip power?

It’s easy to say that the inverter “clips the excess power,” but from a physics point of view, that doesn’t describe what is going on. You can’t just “throw away” power you don’t want—and inverters don’t have air conditioners they can turn on when they need somewhere to send the excess energy. The main tool an inverter has is setting its DC voltage—and this is actually how an inverter is able to drop the system power.

It helps to visualize this issue graphically. A solar array has a power-voltage curve that illustrates the relationship between the operating voltage and the array’s output power. The modules can perform anywhere on the curve, and it’s the inverter’s job to pick the spot on the curve—ideally at the spot that maximizes the power (called the max power point, or MPP).

Figure 1: Typical array power-voltage curve

At the same time, an inverter has a maximum operating power and a voltage range it operates within. We can visualize the inverter’s operating range as a rectangle.

Figure 2: Array power-voltage curve in over-power clipping

When an inverter is in an over-power clipping mode, the array is producing more power than the inverter can handle. The inverter will increase the DC operating voltage, pulling the modules off of their max power point, until the modules’ DC power is within the inverter’s operating range. You can see this as the green point in Figure 2. The inverter protects itself while maintaining maximum power production. The modules end up dissipating the excess power as heat, but as we’ll show at the end of the article, this isn’t a big deal.

However, there is a scenario where this behavior can cause problems. Specifically, look at what happens if the arrays’ power-voltage curve doesn’t intersect the inverter’s operating range. The process we described above (the inverter increasing the operating voltage until the modules’ DC power is within the inverter’s operating range) doesn’t work. Instead, the array will miss the inverter voltage window and trip off—for that period of time, the energy production will be zero. Note that this is by definition happening at a time when the array is at peak production—so just a few times a year can have a serious impact on the array’s energy production!

Figure 3: Array power-voltage curve in over-power and over-voltage condition

So how might this come up? 

The description above is a theoretical framework, but how might this issue come up in an actual system?

There are a few ingredients needed to make this happen: a location with lots of sun (high power) combined with relatively cold temperatures (high voltages), high designed string voltage relative to the inverter’s max operating voltage and a large DC-to-AC ratio.

We can look at the power and temperature properties for a few locations around the US, and it looks like there are a few cities that are at elevated risk for this (again, high irradiance relative to temperature). We’ll use Los Angeles for the analysis here.

Figure 4: Sunlight and temperature by location

We then design a system in Los Angeles with an inverter with a max MPP voltage of 750 V (combined with a 1000 V Voc string), and 1.5 DC/AC ratio.

Figure 5: Loss chart for hyper-clipping simulation

We can see that the clipping losses can be as high as 32%, caused by 15% of operating hours where the array goes into hyper-clipping and trips to zero.

In terms of seasonality, these clipping losses persist for most of the year, with clipping losses above 30% for seven months of the year.

Figure 6: Clipping losses by month

Sensitivity to design choices

It’s worth illustrating how these two factors interact. Note that if we start with a base case of an array with a 1.2 DC-to-AC ratio and an inverter with a wider max voltage of 820 V, then there is no clipping loss. Each factor independently will lead to clipping of 5.7% (for increasing the DC/AC ratio to 1.5), and 0.6% (for dropping the inverter’s voltage to 750 V. But together, the clipping losses jump to 32.4%—approximately five times the sum of the individual effects.

The good news is that HelioScope will properly simulate these losses—so if you are ever at risk of hitting these conditions, you’ll find out before you build the array. And it’s a reminder that inverters aren’t just black boxes that turn DC power into AC power. The nuances of their behavior (including the operating voltage range) can make a big impact on energy yield.

How much heat does this create at the module? 

This description of clipping often raises questions about the module health. Basically, if the inverter isn’t ‘clipping’ excess power but the modules are, then does this damage the module?

To re-state the process described above: During inverter clipping, the modules are working off of their maximum power point. So at a moment when a module wants to produce, say, 320 W, it is only able to deliver 240 W to the inverter. The difference (in the example, 80 W) results in heat at the module. So, how much heat are we talking about?

Here, it helps to think in terms of thermodynamics. Modules are only about 20% efficient at converting sunlight into energy—and the rest, 80%, is largely dissipated as heat. So, say an inverter is clipping 25% of the array’s production (as in the example above). Then in the broader context of the sunlight, the 20% efficient module is only converting 15% of the sunlight’s energy to power, with the resulting energy, 85% of the sunlight, being converted to heat. Compared to the base case (80% of sun’s energy converted to heat) this is an increase of ~6%. Sure, any extra heat isn’t ideal—but any well-made module should have no problem handling that extra heat.

By Paul Grana, co-founder, Folsom Labs

Source: Solar Power World

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FUTURE OF SOLAR PHOTOVOLTAIC Deployment, investment, technology, grid integration and socio-economic aspects – IRENA Nov 2019 – A must read

THE DECARBONISATION OF THE ENERGY SECTOR AND THE REDUCTION OF CARBON EMISSIONS TO LIMIT CLIMATE CHANGE ARE AT THE HEART OF THE INTERNATIONAL RENEWABLE ENERGY AGENCY (IRENA) ENERGY TRANSFORMATION ROADMAPS. These roadmaps examine and provide an ambitious, yet technically and economically feasible, pathway for the deployment of low-carbon technology towards a sustainable and clean energy future. 

IRENA HAS EXPLORED TWO ENERGY DEVELOPMENT OPTIONS TO THE YEAR 2050 AS PART OF THE 2019 EDITION OF ITS GLOBAL ENERGY TRANSFORMATION REPORT. The first is an energy pathway set by current and planned policies (Reference Case). The second is a cleaner climate-resilient pathway based largely on more ambitious, yet achievable, uptake of renewable energy and energy efficiency measures (REmap Case), which limits the rise in global temperature to well below 2 degrees and closer to 1.5 degrees, aligned within the envelope of scenarios presented in the 2018 report of the Intergovernmental Panel on Climate Change (IPCC).

THE PRESENT REPORT OUTLINES THE ROLE OF SOLAR PHOTOVOLTAIC (PV) POWER IN THE TRANSFORMATION OF THE GLOBAL ENERGY SYSTEM BASED ON IRENA’S CLIMATE-RESILIENT PATHWAY (REMAP CASE), specifically the growth in solar PV power deployment that would be needed in the next three decades to achieve the Paris climate goals. 

This report’s findings are summarised as follows:

ACCELERATED DEPLOYMENT OF RENEWABLES, COMBINED WITH DEEP ELECTRIFICATION AND INCREASED ENERGY EFFICIENCY, CAN ACHIEVE OVER 90% OF THE ENERGY-RELATED CARBON DIOXIDE (CO2) EMISSION REDUCTIONS NEEDED BY 2050 TO SET THE WORLD ON AN ENERGY PATHWAY TOWARDS MEETING THE PARIS CLIMATE TARGETS. Among all low-carbon technology options, accelerated deployment of solar PV alone can lead to significant emission reductions of 4.9 gigatonnes of carbon dioxide (Gt CO2) in 2050, representing 21% of the total emission mitigation potential in the energy sector. 

ACHIEVING THE PARIS CLIMATE GOALS WOULD REQUIRE SIGNIFICANT ACCELERATION ACROSS A RANGE OF SECTORS AND TECHNOLOGIES. By 2050 solar PV would represent the second-largest power generation source, just behind wind power and lead the way for the transformation of the global electricity sector. Solar PV would generate a quarter (25%) of total electricity needs globally, becoming one of prominent generations source by 2050

SUCH A TRANSFORMATION IS ONLY POSSIBLE BY SIGNIFICANTLY SCALING UP SOLAR PV CAPACITY IN NEXT THREE DECADES. This entails increasing total solar PV capacity almost sixfold over the next ten years, from a global total of 480 GW in 2018 to 2 840 GW by 2030, and to 8 519 GW by 2050 – an increase of almost eighteen times 2018 levels. 

THE SOLAR PV INDUSTRY WOULD NEED TO BE PREPARED FOR SUCH A SIGNIFICANT GROWTH IN THE MARKET OVER THE NEXT THREE DECADES. In annual growth terms, an almost threefold rise in yearly solar PV capacity additions is needed by 2030 (to 270 GW per year) and a fourfold rise by 2050 (to 372 GW per year), compared to current levels (94 GW added in 2018). 

Thanks to its modular and distributed nature, solar PV technology is being adapted to a wide range of off-grid applications and to local conditions. In the last decade (2008–18), the globally installed capacity of off-grid solar PV has grown more than tenfold, from roughly 0.25 GW in 2008, to almost 3 GW in 2018. Off-grid solar PV is a key technology for achieving full energy access and achieving the Sustainable Development Goals. 

AT A REGIONAL LEVEL, ASIA IS EXPECTED TO DRIVE THE WAVE OF SOLAR PV CAPACITY INSTALLATIONS, BEING THE WORLD LEADERS IN SOLAR PV ENERGY. Asia (mostly China) would continue to dominate solar PV power in terms of total installed capacity, with a share of more than 50% by 2050, followed by North America (20%) and Europe (10%). 

SCALING UP SOLAR PV ENERGY INVESTMENT IS CRITICAL TO ACCELERATING THE GROWTH OF INSTALLATIONS OVER THE COMING DECADES. Globally this would imply a 68% increase in average annual solar PV investment from now until 2050 (to USD 192 billion/yr). Solar PV investment stood at USD 114 billion/ yr in 2018.

INCREASING ECONOMIES OF SCALE AND FURTHER TECHNOLOGICAL IMPROVEMENTS WILL CONTINUE TO REDUCE THE COSTS OF SOLAR PV. Globally, the total installation cost of solar PV projects would continue to decline in the next three decades. This would make solar PV highly competitive in many markets, with the average falling in the range of USD 340 to 834 per kilowatt (kW) by 2030 and USD 165 to 481/kW by 2050, compared to the average of USD 1 210/kW in 2018. 

The levelised cost of electricity (LCOE) for solar PV is already competitive compared to all fossil fuel generation sources and is set to decline further as installed costs and performance continue to improve. Globally, the LCOE for solar PV will continue to fall from an average of USD 0.085 per kilowatt-hour (kWh) in 2018 to between USD 0.02 to 0.08/kWh by 2030 and between USD 0.014 to 0.05/kWh by 2050. 

THE SOLAR PV INDUSTRY IS A FAST-EVOLVING INDUSTRY, CHANGING RAPIDLY THANKS TO INNOVATIONS ALONG THE ENTIRE VALUE CHAIN AND FURTHER RAPID COSTS REDUCTIONS ARE FORESEEN. First- generation technologies remain the principal driver of solar industry development and still hold the majority of the market value. Tandem and perovskite technologies also offer interesting perspectives, albeit in the longer term several barriers still need to be overcome. The emergence of new cell architectures has enabled higher efficiency levels. In particular, the most important market shift in cell architecture has resulted from bifacial cells and modules, driven by the increased adoption of advanced cell architecture, such as passive emitter and rear cell (PERC), and by its compatibility with other emerging innovations, such as half-cut cells and others.

TAKING ADVANTAGE OF FAST-GROWING SOLAR PV CAPACITY ACROSS THE GLOBE, SEVERAL RESEARCH PROJECTS AND PROTOTYPES ARE ONGOING TO STIMULATE FUTURE MARKET GROWTH BY EXPLORING INNOVATIVE SOLAR TECHNOLOGIES AT THE APPLICATION LEVEL. One example is building-integrated photovoltaic (BIPV) solar panels. BIPV solutions offer several advantages, such as multifunctionality (they can be adapted to a variety of surfaces), cost-efficiency (savings on roofing material, labour/construction, refurbishment and renovation costs), versatility and design flexibility in size, shape and colour.

Solar panels have improved substantially in their efficiency and power output over the last few decades. In 2018, the efficiency of multi-crystalline PV reached 17%, while that of mono-crystalline reached 18%. This positive trend is expected to continue through to 2030. Yet, as the global PV market increases, so will the need to prevent the degradation of panels and manage the volume of decommissioned PV panels leading to circular economy practises. This includes innovative and alternative ways to reduce material use and module degradation, and opportunities to reuse and recycle PV panels at the end of their lifetime.

TECHNOLOGICAL SOLUTIONS AS WELL AS ENABLING MARKET CONDITIONS ARE ESSENTIAL TO PREPARE FUTURE POWER GRIDS TO INTEGRATE RISING SHARES OF SOLAR PV. To effectively manage large-scale variable renewable energy sources, flexibility must be harnessed in all sectors of the energy system, from power generation to transmission and distribution systems, storage (both electrical and thermal) and, increasingly, flexible demand (demand-side management and sector coupling). Some countries, particularly in Europe, have achieved much higher shares in 2017: the VRE share in Denmark reached 53%, in South Australia 48%, and in Lithuania, Ireland, Spain and Germany over 20%. Globally, to integrate 60% variable renewable generation (of which 25% from solar PV) by 2050, average annual investments in grids, generation adequacy and some flexibility measures (storage) would need to rise by more than one-quarter to USD 374 billion/year, compared to investments made in electricity networks and battery storage in 2018 (USD 297 billion/year). 

INNOVATIVE BUSINESS MODELS AND COST COMPETITIVENESS OF SOLAR PV ARE DRIVING THE REDUCTIONS IN SYSTEM PRICES. The deployment of rooftop solar PV systems has increased significantly in recent years, in great measure thanks to supporting policies, such as net metering and fiscal incentives- which in some markets make PV more attractive from an economic point of view than buying electricity from the grid- PV-hybrid minigrid, virtual power plants and utility PPA. The competitiveness of distributed solar power is clearly evident amid rising deployment in large markets, such as Brazil, China, Germany and Mexico, however important differences remain between countries, which highlight the further improvement potential.

IF ACCOMPANIED BY SOUND POLICIES, THE TRANSFORMATION CAN BRING SOCIO-ECONOMIC BENEFITS. The solar industry would employ more than 18 million people by 2050 (of which 14 million would be employed by solar PV) four times more than the 2018 jobs total of 4.4 million (3.6 million – solar PV). To maximise outcomes of the energy transition, however, a holistic policy framework is needed. Deployment policies will need to co-ordinate and harmonise with integration and enabling policies. Under the enabling policy umbrella, particular focus is needed on industrial, financial, education and skills policies to maximise the transition benefits. Education and skills policies can help equip the workforce with adequate skills and would increase opportunities for local employment. Similarly, sound industrial policies that build upon domestic supply chains can enable income and employment growth by leveraging existing economic activities in support of solar PV industry development.

UNLEASHING THE MASSIVE POTENTIAL OF SOLAR PV IS CRUCIAL TO ACHIEVE CLIMATE TARGETS. This is only possible by mitigating the current barriers at different scales (policy; market and economic; technology; regulatory, political and social). Grid integration and grid flexibility, economies of scale, access to finance, lack of standards and quality measures, consumer awareness are among the key barriers that could hinder the deployment of solar PV capacities in the next three decades. Mitigating the existing barriers immediately, through a range of supportive policies and implementation measures including innovative business models, financial instruments is vital to boost future deployment of solar PV capacities to enable the transition to a low-carbon, sustainable energy future.

Click here for the full doc

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LAZARD’S LEVELIZED COST OF STORAGE ANALYSIS – 2019

Table of Contents

  1. I  INTRODUCTION 1
  2. II  LAZARD’S LEVELIZED COST OF STORAGE ANALYSIS V5.0 2
  3. III  ENERGY STORAGE VALUE SNAPSHOT ANALYSIS 8
  4. IV  SUMMARY OF KEY FINDINGS 10

APPENDIX

  1. A  Supplementary LCOS Analysis Materials 11
  2. B  Supplementary Value Snapshot Materials
    1. 1  Landscape of Energy Storage Revenue Potential 15
    2. 2  Value Snapshot Supporting Materials 20
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MNRE allows no capping on DC capacity enabling

ADVISORY/ CLARIFICATION
Sub: Advisory / Clarification w.r.t. D.C. Capacity of Solar PV Power Plants

MNRE has received representations from various Solar Developers/ Solar Developer Associations that recently few States have raised questions and concerns around globally adopted practice of installing additional DC capacity, over and above the nameplate / contracted AC capacity, with the objective of meeting the committed Capacity Utilisation Factor (CUF) in Power Purchase Agreements (PPAs) / Power Supply Agreements (PSAs).

(2). It has further been stated that the State Governments feel that installation of such additional capacity serves as a medium for additional revenue generation for the developers and that such additional DC capacity cannot be allowed.

The issue has been examined in the Ministry of New & Renewable Energy (MNRE), is noted that:

As per the present bidding practice, the procurer, whether State Government Agencies/ DISCOMS or Central Government entities like SECl/ NTPC, invite bids from solar power developers for setting up solar PV power plant of a certain capacity (MW). The capacity won by the successful bidder (solar PV power developer), on signing of Power Purchase Agreement (PPA) becomes the “Contracted Capacity”, which is the capacity (MW) in AC terms, allocated for supply by that bidder.

Along with ‘Contracted Capacity’, the PPA also provides for a range of energy supply based on Capacity Utilisation Factor (CUF). While the procurer is not obligated to buy energy beyond this range, the developer is liable for penal charges for supply of energy less than the minimum committed energy or minimum committed Capacity Utilisation Factor (CUF).

Thus, the PPAs define the relationship between the Solar Developers and the procurer in terms of AC capacity, and range of energy supply based on CUF, with procurement obligation within this range.

The requirement of designing and installation of additional DC panels may emanate from the contractual need to supply the committed energy and does not cast any obligation on the procurer to buy generation in excess of the contracted energy range.

The procurer, without getting into the design and installation of solar capacity on the DC side, should only ensure that the AC capacity of the solar PV power plant set up by the developer corresponds with the contracted AC capacity and that, at no point, the power (MW) scheduled from the solar PV power plant, is in excess of the contracted AC capacity.

Accordingly, all concerned are hereby advised that:

As long as the solar PV power plant is in accordance with the contracted AC capacity and meets the range of energy supply based on Capacity Utilisation Factor (CUF) requirements, the design and installation of solar capacity on the DC side should be left to the generator / developer.

Even if the installed DC capacity (MWp) [expressed as the sum of the nominal DC rating (Wp) of all the individual solar PV modules installed] in a solar PV power plant, is in excess of the value of the contracted AC capacity (MW), it is not violation of PPA or PSA, as long as the AC capacity of the solar PV power plant set up by the developer corresponds with the contracted AC capacity and that, at no point, the power (MW) scheduled from the solar PV power plant is in excess of the contracted AC capacity, unless there is any specific clause in the PPA restricting such D.C. capacity.

The contracting party is not obliged to buy any power in excess of the contracted quantum. There is provision of penalty in case the supply falls short of the contracted quantity.

As per law, the setting up of generation capacity is an unlicensed activity and therefore any person is entitled to set up any capacity which he desires to set up, and sell power to any entity which may want to buy it.

This issues with the approval of Hon’ble Minister (Power & NRE).

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CEEW – Demystifying India’s rooftop solar policies – A state-level analysis Issue Brief | November 2019


The difference between net metering and gross metering
In the net metering mechanism, the electricity generated by the RTS system is consumed by the user and any excess electricity is injected into the grid. In case the consumer requires more power than what
is produced by the RTS system, they can import the balance from the grid. At the end of the settlement period, the consumer is only charged for the ‘net’ energy utilised – the difference between the energy produced through the RTS system and the energy consumed over
the billing period. A bi-directional meter is used to measure the net electricity consumption of the system.
In case of gross metering, the total electricity generated by the solar system is injected into the grid, and the consumer imports electricity from the grid for consumption. At the end of the settlement period, the consumer is compensated for the electricity exported to the grid at the Feed-in-Tariff (FiT) rate determined by the State Electricity Regulatory Commission.

Glossary

  • Sanctioned load/contracted load – Sanctioned load is the maximum demand which is to be supplied by the discom to the consumer as indicated in the agreement between them. It is denoted in kW, kVA, or HP.
  • Distribution transformer (DT) capacity – A distribution transformer is a step-down transformer which is used for electric power distribution. DT capacity is the maximum load that can be put on a transformer within voltage limits by the electricity-generating consumers.
  • Surplus generation – It is the difference in electric power exported from the RTS plant and imported from the grid. It is denoted in kW, kVA, or HP.
  • Cap on export with respect to consumption – It is the limitation put on the export of electricity to the transformer with respect to the consumer’s total consumption.
  • Billing period – The time period for which regular electricity bills are prepared for the consumers by the discom.
  • Settlement period – The time period within which consumers should be compensated for the surplus energy injected into the grid if it has not yet been settled in the billing period.
  • Range allowed – This is the approved minimum and maximum capacity of the rooftop solar system which can be installed by an eligible consumer.
  • Average power purchase cost (APPC) rate – The weighted average pooled price at which the discom purchased electricity from its energy suppliers, except those based on renewable sources, including its self-electricity generation cost in the previous year.
  • Feed-in tariff (FiT) – The payment made in proportion to the power generated to consumers who generated electricity from renewable sources and provided it to the grid.
  • Group-net metering – An arrangement whereby the surplus energy which is generated from a renewable source and fed into the grid through net metering is adjusted within the same discom’s area of supply in more than one electricity service connection(s) of the same consumer.
  • Virtual-net metering – An arrangement in which the entire energy which is generated from a renewable source is exported to the grid through a net meter or gross meter, and the exported energy is adjusted within the same discom’s area of supply in more than one electricity service connection(s) of the participating consumer.
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Maharashtra State Electricity Transmission Draft Regulations – Oct 2019

Salient features of Draft MERC Rooftop RE Regulations 2019

  •   Banked energy – excess than consumed in same TOD slot wherever applicable
  •   1 MW capacity limit – but not for net billing
  •   Can be owned by consumer, third party or discom
  •   Generic tariff – RE tariff
  •   Net billing introduced
  •   Net metering only to residential consumers – all others under net billing
  •   Limit of 40% of DTR for both types – discom can allow higher
  •   Limited by CD or SL – 100%
  •   With or without battery
  •   BTM system can be installed only with prior intimation to discom – format provided
  •   BTM systems can have additional fixed / demand / any other charges if discom proposes andMERC accepts
  •   BTM systems without prior intimation will be charged at twice these rates
  •   Generation meter to be procured by consumer at his own cost – maintained by discom
  •   Check meter for > 20 kW systems
  •   Check meter for generation meter under net billing arrangement shall be by discom
  •   Both agreements annexed – can be modified by discom in line with regulations – 20 yearsNet Metering:
  •   Under net metering only 300 units per month can be used to settle or carry forward – excess generated units than 300 units shall be paid for by discom at generic tariff as per RE tariff regulation
  •   Excess at the end of year – also at generic tariff of RE for that year
  •   Exempted from wheeling, banking, CSS, transmission charges and surchargesNet billing:
  •   Can be connected on consumer side or discom side of the meter
  •   Entire energy to be sold to discom
  •   Consumer has to procure net meter if connection is on consumer side
  •   Tariff in agreement (for the year when system commissioned) constant for 20 years
  •   Monthly bill to consumer after deducting total generation multiplied by tariff as per PPA
  •   Generic tariff for RTPV will be with assumptions – 400 Lakh per MW capital cost, 19% CUFand 5% degradation per year – al other financial parameters shall be as per earlier years tariff calculations
  • By Arvind Karandikar

Click Below for the full draft

page1image15518336
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FLOATING SOLAR HANDBOOK FOR PRACTITIONERS – 2019, Solar Energy Research Institute of Singapore (SERIS) at the National University of Singapore (NUS)

EXECUTIVE SUMMARY 1 

Site identification 1

Energy yield analysis 3
Engineering design 3
Financial and legal considerations 3 Environmental and social considerations Procurement and construction 4

Testing and commissioning Operations and maintenance Conclusions and next steps

  1. 1  INTRODUCTION 11
    1. 1.1  Why is this handbook needed? 11
    2. 1.2  Market trends for floating solar 11
    3. 1.3  Key phases of a floating solar project
  2. 2  SITE IDENTIFICATION 17

2.1 Introduction 17

  1. 2.2  Solar irradiance and climate conditions 18
  2. 2.3  Bathymetry and water body characteristics 19
  3. 2.4  Soil investigations and water analysis 21
  4. 2.5  Shading, soiling, and environmental considerations 22
  5. 2.6  Accessibility, grid infrastructure, and power availability 22
  6. 2.7  Other site conditions 23
  7. 2.8  Summary for selecting a water body 23

3 ENERGY YIELD ANALYSIS 27

  1. 3.1  Introduction 27
  2. 3.2  Solar resource and irradiance in the plane of solar modules 27
  3. 3.3  Shading losses 28
  4. 3.4  Soiling 29
  5. 3.5  Temperature-dependent losses 29
  6. 3.6  Water surface albedo 30
  7. 3.7  Mismatch losses 30
  8. 3.8  Cabling losses 32
  9. 3.9  Efficiency losses of the inverter 32
  10. 3.10  Long-term degradation rates 32

CONTENTS • iii

iv •

FLOATING SOLAR HANDBOOK FOR PRACTITIONERS

  1. 4  ENGINEERING DESIGN 35
    1. 4.1  Introduction 35
    2. 4.2  Floating structures and platforms 35
    3. 4.3  Anchoring and mooring systems 39
    4. 4.4  PV modules 45
    5. 4.5  Cable management on water 49
    6. 4.6  Electrical safety 49
    7. 4.7  Checklists for plant design 53
  2. 5  FINANCIAL AND LEGAL CONSIDERATIONS 57
    1. 5.1  Overview 57
    2. 5.2  Risk analysis 57
    3. 5.3  Economic and financial analysis 61
    4. 5.4  Licenses, permits, and authorizations 62
    5. 5.5  Country case studies 64
    6. 5.6  Conclusion 68
  3. 6  ENVIRONMENTAL AND SOCIAL CONSIDERATIONS 73
    1. 6.1  Overview, scope, and methodology 73
    2. 6.2  Managing effects specific to floating solar photovoltaic systems 74
    3. 6.3  Permitting, mitigation measures, performance indicators, and monitoring 86
  4. 7  PROCUREMENT AND CONSTRUCTION 93 7.1 Overview 93
    1. 7.2  Managing procurement activities 93
    2. 7.3  Managing construction activities 95
    3. 7.4  Checklist for procurement and construction 102
  5. 8  FIELD TESTING AND COMMISSIONING 105
    1. 8.1  Overview 105
    2. 8.2  Solar PV modules and inverters 105
    3. 8.3  Floats and anchoring 105
    4. 8.4  Safety labelling 106
    5. 8.5  Surge/lightning protection 106
    6. 8.6  DC electrical system 107
    7. 8.7  AC electrical system 108
    8. 8.8  Acceptance tests 109
  6. 9  OPERATIONS AND MAINTENANCE 113
    1. 9.1  Overview 113
    2. 9.2  O&M approach and activities 113
    3. 9.3  Warranties and performance guarantees 129
    4. 9.4  Operations and maintenance checklist 131

ANNEXES 133

  1. Floating PV module failure modes and testing recommendations 133
  2. Costs of floating solar 139
  3. Nonexhaustive list of FPV system suppliers as of December 2018 143

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