distributed generation in spain

MASTER IN TECHNICAL AND FINANCIAL MANAGEMENT IN THE POWER SECTOR

MASTER THESIS

DISTRIBUTED GENERATION IN SPAIN

AUTHOR: DAVID TREBOLLE TREBOLLE

Madrid, 01/01/2006

Distributed Generation in Spain

Table of Contents

1. Introduction 10

1.1. Reason of thesis 11

1.2. Purpose of thesis 11

1.3. Structure of thesis 12

2. Definition and types of Distributed Generation technologies 13

2.1. Definition 14

2.2. Different types of technologies 17

2.2.1 Gas turbines 18 2.2.2 Microturbines 20 2.2.3 Steam turbines 22 2.2.4 Combined cycles 23 2.2.5 Alternative motors 24 2.2.6 Mini-hydraulics 26 2.2.7 Wind farms 27 2.2.8 Solar 28 2.2.9 Fuel cells 34 2.2.10 Flywheels 37

3. Installed power and distributed generation production in

Spain 40

3.1. Installed power of distributed generation 41

3.2. Distributed generation production in Spain 48

3.3. Potential of renewable energies in peninsular Spain 50

4. Regulations regarding distributed generation in the Spanish

power sector 52

4.1. Period 1998-2004 54

4.1.1 RD 2818/1998 54 4.1.2 RD841/2002 55

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4.2. Period 2004 – Present: 57

4.2.1 RD 436/2004 57 4.2.2 RD 2392/2004 60 4.2.3 RD 2351/2004 60 4.2.4 RD 1454/2005 60

4.3. European regulation 62

5. Impact of DG in grid business. Planning and design 63

5.1. Introduction 64

5.2. Influence of DG in the planning and design of the grid 66

5.2.1 Technical grid connection criteria 66 5.2.2 New investments in the grid 69

6. Impact of DG in grid business. Grid operation and

exploitation 76

6.1. Influence of DG in the operation and exploitation of

the grid 77

6.1.1 Delivery grid 77 6.1.2 MV and LV grid 81

6.2. Influence of DG in losses 81

6.3. Influence of DG in service quality 87

6.3.1 Product quality 87 6.3.2 Continuity of supply 98

6.4. Influence of DG in the voltage profiles 98

6.4.1 Delivery grid 99 6.4.2 MV and LV grid 105

6.5. Influence of DG in the safety of maintenance

personnel 107

7. Influence of DG in short-circuit powers 109

7.1. Transmission 111

7.2. Distribution 111

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7.3. Conclusions 113

8. Influence of DG in ancillary services 115

8.1. Power Frequency Control 116

8.2. Voltage Control - Reactive 128

8.3. Autonomous start-up and island operation 136

9. Impact of DG in the purchases of power from distribution

companies 142

10. Conclusions 145

10.1. Influences of distributed generation in the planning

and design of networks 147

10.2. Influences of distributed generation in the operation

and exploitation of the network 147

10.3. Influences of distributed generation in short-circuit

powers 148

10.4. Influences of distributed generation in ancillary

services 148

10.5. Influences of distributed generation in the purchases

of power from distribution companies 149

11. Bibliography 150

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Table of Figures Figure 2.1.1 Traditional structure of the power sector 14 Figure 2.1.2 New grid layout with presence of DG 17 Figure 2.2.1.1 Elements involved in the Rankine cycle 18 Figure 2.2.1.2 P-V and T-S diagrams of the Rankine cycle 18Figure 2.2.1.3 Gas turbine 19 Figure 2.2.1.4 Characteristics and properties of gas turbines 20Figure 2.2.2.1 80kW Microturbine 20 Figure 2.2.2.2 Characteristics and properties of microturbines 22Figure 2.2.3.1 Steam turbine 22 Figure 2.2.3.2 Characteristics and properties of steam turbines 23Figure 2.2.4.1 Characteristics and properties of combined cycles 24Figure 2.2.5.1 Internal combustion engine 25 Figure 2.2.5.2 Characteristics and properties of alternative 26Figure 2.2.6.1 Characteristics and properties of Mini-hydraulics 27Figure 2.2.7.1 Wind farms 27 Figure 2.2.7.2 Characteristics and properties of Wind farm stations 28Figure 2.2.8.1 Photovoltaic panels 29 Figure 2.2.8.2 Characteristics and properties of photovoltaic power 30Figure 2.2.8.3 Parabolic cylinder collectors 31 Figure 2.2.8.4 Production diagram of solar station with steam

turbine 31 Figure 2.2.8.5 Solar tower and heliostats 32 Figure 2.2.8.6 Diagram of a solar station production process with a

tower and heliostats 33 Figure 2.2.8.7 Parabolic collectors 33 Figure 2.2.8.8 Characteristics and properties of solar heat 34Figure 2.2.9.1 Fuel cells. Operation diagram 35 Figure 2.2.9.2 Characteristics and properties of fuel cells 37Figure 2.2.10.1 Flywheels 38 Figure 2.2.10.2 Operation diagram of a flywheel 38 Figure 3.1.1 Evolution of installed power under special regime in

Spain 42 Figure 3.1.2 Installed DG power by autonomous communities 44Figure 3.1.3 Installed DG power by autonomous communities.

Group A 46 Figure 3.1.4 Installed DG power by autonomous communities.

Group B 46

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Figure 3.1.5 Installed DG power by autonomous communities. Group C 47

Figure 3.1.6 Installed DG power by autonomous communities. Group D 47

Figure 3.2.1 DG Production in GWh. 2003 49 Figure 3.2.2 Renewable production by technology. 2003 49Figure 3.3.1 Potential renewable installed power estimated for

2050 51 Figure 5.2.1.1 Example protection diagram for connecting to the

distribution network 68 Figure 5.2.2.1 Overload of MV grid by degree of penetration of

cogeneration 71 Figure 5.2.2.2 Annual net and load curve load of 220/45kV 72Figure 5.2.2.3 Annual and load curve generator production chart 72Figure 5.2.2.4 Gross annual net and load curve load of 220/45kV

transformer 73 Figure 5.2.2.5 Annual net load and load curve of 132/45kV

transformer 73 Figure 5.2.2.6 Annual and load curve generator production chart 74Figure 5.2.2.7 Annual net and load curve load of 132/45kV 74Figure 6.1.1.1 Delivery grid in Segovia 78 Figure 6.1.1.2 P-V curve. Voltage collapse 79 Figure 6.1.1.3 Delivery grid in Madrid 80 Figure 6.2.1 Cash flow diagrams in the acquisition of energy from

the Spanish pool 82 Figure 6.2.1 U Curves. Losses in distribution networks depending on

degree of penetration of DG 85 Figure 6.2.2 U Curves. Losses in distribution networks depending on

degree of penetration of DG by technology 86 Figure 6.3.1.2 Perturbations corresponding to changes in

characteristics of the voltage wave 88 Figure 6.3.1.3 Voltage gap required in wind farm facilities 90Figure 6.3.1.4 Asynchronous generator 91 Figure 6.3.1.5 Double feed asynchronous generator set 91 Figure 6.3.1.6 Asynchronous generator set with converter in stator 92Figure 6.3.1.7 80% gaps with durations of 400, 1200 and 1300 ms 92Figure 6.3.1.8 Sliding of wind farm generator in 400, 1200 and

1400ms gaps 93 Figure 6.3.1.9 Intensities of direct leg of wind farm generator

before 400, 1200 and 1400ms gaps 94 Figure 6.3.1.10 Intensities of transverse leg of wind farm generator

before 400, 1200 and 1400ms gaps 94

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Figure 6.3.1.11 Blackout after a three-phase failure in the 400kV substation of Loeches 95

6.3.1.12 Evolution of wind farm production delivered in Magallón 96Figure 6.3.1.13 Evolution of 400/220kV transformer load in

Magallon 96 Figure 6.3.1.14 Voltage gap in the Magallon incident 97 Figure 6.3.1.15 Loss of wind farm production due to the incident 97Figure 6.4.1 P-Angle and Q-V relation for a generator set connected

to an infinite network 99 Figure 6.4.1.1 Delivery grid in Segovia 100 Figure 6.4.1.2 Generation of P and Q of cogenerator connected to

substation B 101 Figure 6.4.1.3 Voltage profile in substation B 101 Figure 6.4.1.4 Delivery grid in Leon 102 Figure 6.4.1.5 Generation of P and Q of generator set connected to

substation D 103 Figure 6.4.1.6 Voltage profile of substation D 104 Figure 6.4.1.7 Voltage profiles of substations F and D 104 Figure 6.4.2.1 Voltage profile in MV grids 106 Figure 6.5.1 Five golden rules 108 Figure 7.1 Single wire diagram of a short-circuit 110 Figure 8.1.1 Frequency response in a generation failure 117Figure 8.1.2 Demand profile on the peninsula. 8-12-2005 119Figure 8.1.3 Wind farm production profile on the peninsula. 8-12-

2005 120 Figure 8.1.4 Demand profile on the peninsula. 1-03-2005 121Figure 8.1.5 Wind farm production profile on the peninsula. 1-03-

2005 121 Figure 8.1.6 Interconnection lines from Italy to Europe 123 Figure 8.1.7 Balance of power in Italy on disconnect 124 Figure 8.1.8 Evolution of frequencies in Italy before the Blackout 124Figure 8.1.9 Evolution of frequency in the UCTE after the Italian

disconnect 126 Figure 8.1.10 Evolution of the deviation in the exchange with

France after the Italian disconnect 126 Figure 8.1.11 power balance in Spain after the Italian disconnect 127Figure 8.2.1 Voltage – reactive – control diagram 128 Figure 8.2.2 Voltage profile requirements of the 400kV network

depending on reactive as per OP 7.4 131 Figure 8.2.3 Voltage profile requirements of the 220kV network

depending on reactive as per OP 7.4 131

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Figure 8.2.4 Classification of time periods: peak, valley and flat as per OP 7.4 132

Figure 8.2.5 Power factor requirements at transmission border points – distribution for peak hours as per OP 7.4 132

Figure 8.2.6 Power factor requirements at transmission border points – distribution for valley hours as per OP 7.4 133

Figure 8.2.7 Power factor requirements at transmission border points – distribution for flat hours as per OP 7.4 134

Figure 8.3.1 Zone classification for reposition in the event of zonal or national blackout 137

Figure 8.3.2 Reposition diagram in the event of national blackout 138Figure 8.3.3 Possible future active distribution network diagram 140Figure 8.3.4 Delivery grid in Segovia 141

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Index of Tables Table 3.1.1 Installed power of the various DG technologies 41 Table 3.1.2 Installed DG power by province according to

classification in RD 436/2004 43 Table 3.1.2 Installed DG power by autonomous communities 44 Table 3.1.4 Installed DG power by autonomous community as per

RD 436/2004 45 Table 3.3.1 Potential of renewable installed power estimated for

2050 50 Table 4.1.2.1 Summary of RD841/2002 57 Table 4.2.1.1 Incentive to the compensation of reactive as per RD

436/2004 58 Table 8.1.1 Coverage of demand on blackout in Italy 125 Table 8.1.2 International exchanges in Spain at the time of the

blackout in Italy 125 Table 8.2.1 Incentive to the compensation of reactive as per RD

436/2004 129

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1. Introduction

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1. Introduction

1.1. Reason of thesis

The current map of the Spanish Electricity Sector, result of Act 54/1997, established generation and sale as free competition activities and transmission and distribution as regulated activities. As the price has become a real driver that encourages the activities within a deregulated environment, the fee became the "regulated price" that rewards the activities of the businesses that constitute the so called natural monopolies. Immersed in this scenario, in the last few years, there has been an important increase in the number of Distributed Generation (DG) facilities connected to Distribution, Medium and Low Voltage networks, which we shall refer to as distribution hereinafter. These connections create a series of costs and benefits in these networks, such as increasing or reducing losses, the need to strengthen the capacity of lines and transformation centres in order to provide for new power flows injected by DG or, on the contrary, reduce the investments in network reinforcements (generating points closer to demand reduces energy flows). In a way, these costs and/or benefits should be included in the network access fees. On the other hand, the operation of the distribution network will become increasingly complicated, as the distribution network is no longer considered a radial type grid where power flows go from higher voltages to lower; instead the grids show different behaviour throughout the day as generators connect and disconnect without any kind of control by the operator of the distribution networks. The connection of these generators in the lower levels of the hierarchy changes the scheme, generating a series of technical and regulatory problems. The current Spanish access fee regulation does not add cost for the use of the generation grids. This generates economic inefficiencies, as it does not include costs or benefits contributed by each generator. In addition, there is no transparent method that can be explained in order to calculate access fees. There is no uniformity of criteria in the operation or the connection of distributed generation to the grid.

1.2. Purpose of thesis

This thesis has been produced in order to analyze the various difficulties that arise in the current distribution framework as a result of DG in the grid, both from a technical and regulatory perspective within the Spanish peninsular electricity system. Extrapeninsular systems will not be reviewed in this thesis.

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The technical and regulatory problems derived from the presence of DG in distribution networks encompass several aspects such as: losses, investments, voltage profiles, service quality, short-circuit power, safety of maintenance personnel, stability, ancillary services and grid operation. This thesis does not aim to provide a technical solution to all technical and regulatory problems that may arise in power grids caused by the presence of DG, but it does provide sufficient information to identify all the problems and the reasons for the current situation. It will describe actual distribution problems within the Spanish power sector and analyze the most important regulatory aspects that in some way have caused most of the inconsistencies in the distribution of the power sector.

1.3. Structure of thesis

This master thesis is broken down into three main areas. Chapter two provides a qualitative description of the various technologies that are being integrated into existing distribution networks. We will also review other technologies of recent appearance but not widespread such as fuel cells or flywheels. Chapter three shows the installed generation power under special regime and its production. Chapter four provides a regulatory revision mentioning the most important aspects that have determined the distributed generation framework and the existing distribution network. Chapter 5 to 9 covers the technical and regulatory impact caused by distributed generation to the distribution activity, considering both its activity as manager and owner of the distribution network, and the activity of the purchasing agent in the still regulated electricity wholesale market. Chapter 10 highlights the most important conclusions of the thesis.

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2. Definition and types of Distributed Generation technologies

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2. Definition and types of Distributed Generation technologies

2.1. Definition

Traditionally, the structure of the power systems presented a highly hierarchical aspect:

Figure 2.1.1 Traditional structure of the power sector Conventional generation connected to the transmission grid and power was transmissioned long distances to the consumption centres. When this power reached the distribution network, the power flow was practically unidirectional due to the radial nature of such grids. Slowly, distributed generation started to connect to networks with a lower voltage than the transmission grid. Initially this type of generation was not of a lobbying nature; it was installed in centres whose activities had a high social repercussion such as hospitals, airports, etc. Thanks to incentives policies based fundamentally on premiums or subsidies, new technologies have been introduced with a clearly different objective than the previous case, involving an important economic incentive.

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Thanks to these policies, wind farm power has increased considerably during the last decade reaching 9500MW installed in the Iberian Peninsula. There is currently an important increase in solar power as a distributed resource thanks to the economic incentive with the current applicable regulation. Today there is no accurate and unique definition of Distributed Generation (DG). Several authors or organizations use similar definitions although they differ in several aspects. Some of the definitions we can find are: • Willis & Scott (Willis and Scott, 2000): These authors define DG as small generators (typically between 15 kW and 10 MW) distributed in the power systems. According to said authors, these generators may be connected to the distribution network (at the facilities of the distribution company or in consumer facilities) or isolated from them. Furthermore, they use the concept of Disperse Generation to refer to very small generators, of the size necessary to feed residential consumption or small businesses (typically between 10 and 250 kW) and connected to the facilities of consumers or isolated from the grids. • Jenkins et al. (Jenkins, 2000): These authors prefer a broad definition without discussing details regarding the size of generators, connection voltage, generation technology, etc. However, they mention some attributes generally associated to DG:

Not planned centrally. Not distributed or programmed centrally. Normally with less than 50 or 100 MW of power.

Usually connected to distribution networks (V ≤ 145 kV). • Ackermann (Ackermann, 2001): These authors propose a definition of DG based on a series of aspects: purpose of DG, location, capacity or size of facility, service area, generation technology, environmental impact, operation mode, ownership and penetration of DG. Only the first two aspects are considered relevant by said authors proposing the following definition: “Distributed Generation is a source of power connected to the distribution network or in the facilities of consumers”. The distinction between the distribution network and the transmission grid has been left subordinated to the legal provisions in each country. Moreover, they propose a classification of DG depending on its size: Micro DG: 1 W < power < 5 kW. Small DG: 5 kW < power < 5 MW. Medium DG: 5 MW < power < 50 MW. Large DG: 50 MW < power < 300 MW • Distributed Generation Coordination Group (DTI/OFGEM Distributed Generation Coordination Group, 2002): this body defines DG as the generation of electricity connected to distribution networks instead of the national high voltage

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grid. This is a very broad definition as it does not distinguish between the size or type of generator, the only differentiating element with traditional generation is the fact they are connected to the distribution network. • International Energy Agency (International Energy Agency, 2002): This body refers to DG as the production of power at consumer facilities or in the facilities of the distribution company, supplying power directly to the distribution network. As can be seen from the aforementioned definitions, almost all authors coincide on a fundamental characteristic of DG: to be connected to distribution networks. The biggest discrepancies arise on the size or power of DG although these are smaller than traditional generators. • Doctoral thesis Distributed Generation: Technical aspects and its regulatory treatment (Mendez Quezada, 2005): Distributed Generation are sources of electricity connected to the distribution network, either directly to said grids or connected through consumer facilities, which in this case may operate in parallel to the grid or in isolation. • Generally and considering the regulatory aspects for the Spanish power sector, we could say that Spain defines distributed generation as the combination of electricity generation systems connected to the distribution networks as a result of their reduced power and location close to consumers. The main characteristics are:

• Connected to the distribution network. • Often a part of the generation is consumed by the same facility and the rest is exported to a distribution network (e.g.: cogeneration) • There is no centralized planning of said generation and is not distributed centrally. • The power of the groups is usually less than 50 MW.

Graphically, we have evolved from the aforementioned traditional scheme to the following type of grid:

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Figure 2.1.2 New grid layout with presence of DG

2.2. Different types of technologies

The following shows the various types of technology employed in generation facilities connected to the distribution network. The most important characteristics of each type will be described including a table with the type of fuel they use, their size in terms of installed power, efficiency, availability, cost of investment, cost of operation and maintenance and the average cost calculated based on average availability, cost of installation, O&M, price of fuel and efficiency. This last cost is the one employed to compare the cost of each technology. We recommend reading the following for further details (Jenkins, 2000; Marnay, 2000; ONSITE SYCOM Energy Corporation, 1999; Penche, 1998 and Willis and Scott, 2000). The emissions analysis is based on (Greene and Hammerschalg, 2000) and (California Alliance for Distributed Energy Resources, 1999) and (Mendez Quezada, 2005). Because the purpose of this thesis is not to describe the state of the art of each type of technology, below are the definitions and most important aspects of each technology: • Gas turbines • Microturbines Possible cogeneration processes • Steam turbines • Combined cycle • Alternative motors • Mini-hydraulics • Wind farms • Solar

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• Fuel cells • Flywheels

2.2.1 Gas turbines

Gas turbines have experienced great progress in the last decades mainly as a result of the aeronautic industry. Thanks to the advances in efficiency and reliability, this technology represents an excellent alternative for DG uses. Gas turbines, sometimes called open cycle gas turbines due to its big combined cycle brother are based on the Rankine Cycle:

Figure 2.2.1.1 Elements involved in the Rankine cycle

Figure 2.2.1.2 P-V and T-S diagrams of the Rankine cycle

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Figure 2.2.1.3 Gas turbine

The heat produced by the turbines offers an excellent option for cogeneration purposes. Turbines respond quickly to changes in demand as they have little inertia. These characteristics make this technology suitable for local power demand and even to work in isolated operation mode feeding part of the distribution network. It can be distributed perfectly and does not generate problems in terms of harmonics or flicker. One of the inconveniences is that its efficiency is more affected depending on the full load percentage it operates at in comparison with other technologies such as alternative motors. Production also depends on the environmental conditions it operates in (pressure, temperature and humidity). For example, the generated power drops as the temperature increases, which increases as the pressure rises. They produce less noise and vibration than the alternative motors but produce a noise typical of turbines, which is difficult to muffle without affecting turbine efficiency. The following is a summary chart with the most important characteristics (Mendez Quezada, 2005):

Turbines

Characteristics Favourable aspects Fuel: Natural gas & Diesel Cogeneration *** Size (MW): > 1MW Dispatch *** Efficiency (PCI) %: 25-40% Island mode *** Emissions (kg/MWh): CO2 545-700 Demand mon *** NOx 1.8-5 Ancillary services *** SO2 0.14-0.18 Black start ***

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CO 0.5-4.5 Unfavourable aspects Availability %: 90-98 Harmonics *** Start-up time: 10 min-1 h Flicker *** Surface (m2/kW): 0.003-0.01 Cost of investment (€/kW): 350-950 O&M (cent/kWh): 0.3-0.5 LEC (cent/kwh)i: 6.4 (4.3-9.8) LEC (pts/kwh)i: 10.7 (7.1-16.3)

Remarks: Its efficiency is largely dependent on the operation point and environmental factors such as pressure and temperature. It produces the characteristic noise of turbines. It is a mature technology.

i: The first value is the average value calculated with availability averages, cost of installation, O&M, price of fuel and efficiency. The values between brackets are values calculated for the entire variation range.

Worse that gas combined cycle *** Very good Approximately the same as gas combined cycle ** Good Better than gas combined cycle * Normal ◊◊ Poor ◊◊◊ Very poor

Figure 2.2.1.4 Characteristics and properties of gas turbines

2.2.2 Microturbines

They are combustion turbines with power in the range of 20-500kW, developed based on blow turbo technology from the automobile industry and small turbo reactors from the aeronautics industry. They consist of a compressor, turbine, heat recovery and generator, normally assembled on a single axis. Its main advantages are the lack of moving parts, its compact size, its great variety of sizes and less noise and emissions than a gas turbine. Its main disadvantage is its high cost. The following picture shows an 80kW microturbine:

Figure 2.2.2.1 80kW Microturbine

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They support two modes of operation:

• With heat recovery, which allows transferring part of the heat from the exhaust fumes to the compressor input, increasing its temperature and allowing a substantial improvement of electrical efficiency of the microturbine, which can reach performance levels around 27-30%. • Without the heat recovery, in cogeneration applications, where the use of the residual heat takes precedence over electricity production. In this case, the electrical efficiency drops to 15-18%, but total performance can be around 80%. Microturbines can be used in various ways: a) As backup energy b) To satisfy peaks in demand c) In hybrid systems with fuel cells d) In hybrid electric vehicles

Micro-turbines Characteristics Favourable aspects

Fuel: Natural gas, propane & Diesel

Cogeneration **

Size (MW): 20-500MW Dispatch *** Efficiency (PCI) %: 20-30 Island mode *** Emissions (kg/MWh): CO2 590-800 Demand mon *** NOx 0.09-0.64 Ancillary services ** SO2 Negligible Black start *** CO 0.14-0.82 Unfavourable aspects Availability %: 90-98 Harmonics ◊◊i

Start-up time: 60 Flicker ◊ Surface (m2/kW): 0.025-0.065 Cost of investment (€/kW): 700-1,000 O&M (cent/kWh): 0.5-1 LEC (cent/kwh)ii: 8.6 (6.0-12.5) LEC (pts/kwh)ii: 14.3 (10.0-20.7)

Remarks: This technology is not very efficient and still under development.

i: New types of investors tend to minimize this problem. ii: The first value is the average value calculated with availability averages, cost of installation, O&M, price of fuel and efficiency. The values between brackets are values calculated for the entire variation range.


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Figure 2.2.2.2 Characteristics and properties of microturbines

2.2.3 Steam turbines

In this technology, the fuel is used to produce heat, which is used to generate steam. The steam is used in the turbines to produce electricity. This technology can be used with a great variety of fuels including natural gas, Diesel, solid urban waste and biomass resources (agricultural waste or energy cultivation for the generation of electricity).

Figure 2.2.3.1 Steam turbine This technology, typical of conventional stations, is justifiable in DG under cogeneration applications (when fossil fuels are used) or as renewable generation. In the case of biomass, it can mainly be obtained from forest or agricultural waste and energy cultivation. Forest or agricultural waste was obtained as a subproduct of other activities such as pruning of olive trees or vineyards, cereal straw such as wheat and barley, wood transformation process, olive industry waste, cleaning of hills, etc. Energy cultivations are dedicated exclusively to the production of biomass in order to generate electricity. It uses species of great energy potential and rapid growth such as the thistle and eucalyptus. This technology presents similar characteristics of large size generator stations. They do not present problems with harmonics or flicker and can be perfectly programmed. Their technical characteristics allow them to operate in isolation mode. If biomass is used as fuel, it has the inconvenience that it requires large areas of land to obtain sufficient biomass and the use of monocultivations can lead to the deterioration of the land.

Steam turbines

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Characteristics Favourable aspects Fuel: Biomass (can also

use natural gas, diesel, SUW, etc.)

Cogeneration **

Size (MW): > 5 Dispatch *** Efficiency (PCI) %: 20-30 Island mode *** Emissions (kg/MWh)i: CO2 0 – 1,000 Demand mon *** NOx 0.15-3 Ancillary services *** SO2 Less than 0.15 Black start *** CO 1-4 Unfavourable aspects Availability %: 90 Harmonics *** Surface (m2/kW): Flicker *** Cost of investment (€/kW): 1,500-3,000 O&M (cent/kWh): 0.8-1 LEC (cent/kwh)ii: 9.1 (6.9-12.0) LEC (pts/kwh)ii: 15.2 (11.5-20.0)

Remarks: It is a mature generation technology

i: The behaviour of emissions depends on the type of fuel used. The values presented in the table correspond to biomass. If renewable biomass is used, the CO2 levels can be considered zero as in this case CO2 issued on burning is absorbed during growth. ii: The first value is the average value calculated with availability averages, cost of installation, O&M, price of fuel and efficiency. The values between brackets are values calculated for the entire variation range.


Figure 2.2.3.2 Characteristics and properties of steam turbines

2.2.4 Combined cycles

Combined cycles integrate one or more turbines with a water steam cycle. Heat recovered from the turbines is used as part of the steam cycle, achieving high levels of efficiency. Today, this technology is only used in DG for large scale cogeneration applications thanks to its efficiency and low cost of installation and generation. Combined cycle is defined as the thermo-dynamic coupling of two different thermo-dynamic cycles: one that operates at high temperature and another at low temperature. Residual heat of the high cycle is used as a contribution of heat to the low temperature cycle. The most frequent combined cycles are combined gas-steam cycles, i.e.: with an open cycle gas turbine as the high temperature cycle (Brayton) and a steam turbine cycle (Rankine) as the low temperature cycle. The fluids employed are water and air due to its abundance, simple replacement and easy operation.

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This technology presents similar characteristics of large size generator stations. They do not present problems with harmonics or flicker and can be perfectly programmed. Its technical characteristics allow them to operate in isolation mode.

The following is a summary chart of this technology (Mendez Quezada, 2005):

Combined cycle Characteristics Favourable aspects

Fuel: Mainly natural gas Cogeneration ** Size (MW): > 20 Dispatch *** Efficiency (PCI) %: 40-60 Island mode *** Emissions (kg/MWh)i: CO2 320-400 Demand mon *** NOx 0.05-0.40 Ancillary services *** SO2 Negligible Black start *** CO 0.02-0.45 Unfavourable aspects Availability %: 90-98 Harmonics *** Surface (m2/kW): Flicker *** Cost of investment (€/kW): 350-700 O&M (cent/kWh): 0.2-0.5 LEC (cent/kwh)ii: 4.7 (2.9-6.4) LEC (pts/kwh)ii: 7.8 (4.8-10.6)

Remarks: It is a mature generation technology

i: Emission symbols have not been included as this technology has been considered the reference for comparing other technologies. ii: The first value is the average value calculated with availability averages, cost of installation, O&M, price of fuel and efficiency. The values between brackets are values calculated for the entire variation range.

*** Very good ** Good * Normal ◊◊ Poor ◊◊◊ Very poor

Figure 2.2.4.1 Characteristics and properties of combined cycles

2.2.5 Alternative motors

Alternative motors are the ones that typically have been called internal combustion engines.

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Figure 2.2.5.1 Internal combustion engine

This is the most used technology, with a broad range of powers. Its main use is as support in the event of a blackout. Its primary advantage is its rapid response, and the disadvantages are high noise levels, high cost of operation and maintenance and high NOx emissions. There are two types of engines, natural gas and diesel engines. The energy efficiency of these engines is around 30-45%, with expectations of reaching 50% in 2010. The following table summarizes the most important characteristics (Mendez Quezada, 2005):

Alternative motors Characteristics Favourable aspects

Fuel: Biomass (can also use natural gas, diesel, SUW, etc.)

Cogeneration **

Size (MW): 0.05-5 Dispatch *** Efficiency (PCI i) %: 30-45 Island mode *** Emissions (kg/MWh): CO2 590-800 Demand mon *** NOx 4.5-18.6 Ancillary services *** SO2 0.18-1.36 Black start *** CO 0.18-4 Unfavourable aspects Availability %: 90-95 Harmonics ** Start-up time (s): 10 Flicker ** Surface (m2/kW): 0.003-0.03 Cost of investment (€/kW): 350-550 O&M (cent/kWh): 1-1.5 LEC (cent/kwh)ii: 10.3 (4.7-19.1) LEC (pts/kwh)ii: 17.1 (7.7-31.8)

Remarks: This type of technology has high levels of emissions and noise. It is a mature technology

i: PCI (Lower Calorific Value): Heat produced during combustion without including heat from water steam generated during combustion and released into the atmosphere through the exhaust conduit. ii: The first value is the average value calculated with availability averages, cost of installation, O&M, price of fuel and efficiency. The values between brackets are values calculated for the entire variation range.

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Figure 2.2.5.2 Characteristics and properties of alternative

2.2.6 Mini-hydraulics

A mini-hydraulic generator is a turbine connected to an electricity generator and all the necessary structures such as channels and dams to regulate river flow. This technology turns kinetic energy from water into electricity. Kinetic energy depends on volume and the height difference between the upper level of water in the dam and the turbine level. The energy performance of this technology is around 80%. There are three types of mini hydraulic generation technologies: • Flowing (little height difference, much volume, Franklin turbines and little possibility of regulating output power). • Medium height • High height (high difference in height, little volume easily regulated and Pelton turbines). A hydraulic plant supports fast start-up, which turns it into a technology suitable to adapt to demand variations. In addition, the possibility of installing pump groups in order to increase water during periods of low electricity price periods to later turbine it during high price periods, offers a weapon against the price risk.

Mini hydraulics

Characteristics Favourable aspects Fuel: Water Cogeneration ◊◊◊ Size (MW): 0.1-10 Dispatch ◊◊ Efficiency (PCI) %: 75-0’ Island mode ◊◊◊ Emissions (kg/MWh): CO2 0 Demand mon ◊◊◊ NOx 0 Ancillary services ◊◊◊ SO2 0 Black start ◊i

CO 0 Unfavourable aspects Equivalent hours (j): 2,500-3,500 Harmonics ◊ Surface (m2/kW)ii: 1-1,000 Flicker ◊ Cost of investment (€/kW): 1,500-4,000 O&M (cent/kWh): 0.8-1.9 LEC (cent/kwh)iii: 8.7 (4.0-15.5) LEC (pts/kwh)iii: 14.5 (6.7-25.8)

Remarks: Its growth potential is limited as most jumps are already being used. It is a mature technology.

26


i: Depends on the availability of a hydraulic resource at the time. ii: Includes the area of the entire facility. Source: (Eberhard et al, 2000). iii: The first value is the average value calculated with availability averages, cost of installation, O&M, price of fuel and efficiency. The values between brackets are values calculated for the entire variation range.


Figure 2.2.6.1 Characteristics and properties of Mini-hydraulics

2.2.7 Wind farms

Technology that uses wind farm energy and transforms it into electricity. The power of these units is currently ranges from 30 kW to more than 2MW. It is a relatively mature technology, reaching reliability levels of around 97%.

Figure 2.2.7.1 Wind farms

There are two mechanical blade energy transformation technologies; one based on a synchronous generator and the other with an asynchronous generator. The current trend focuses on asynchronous generators controlled by pulse converters (double feed generators). This allows regulating output voltage by modifying consumption or generation of reactive energy. This option is very useful when the generator set is connected to weak grids, where a strong power injection can increase voltage at the connection point to values above tolerable ranges. In addition, the construction of blades with the possibility of varying their angle allows regulating the generated active power.

27


The main disadvantage of this technology is the difficulty of predicting generated power, due to “unforeseeable” variations in wind. Another problem is known as the flicker effect due to the passing of the blades in front of the post that supports the generator, which causes small and repetitive voltage variations. Below is the summary table (Mendez Quezada, 2005):

Wind farms

Characteristics Favourable aspects Fuel: Wind Cogeneration ◊◊◊ Size (MW)i: > 5 Dispatch ◊◊◊ Efficiency (PCI) %: 15-30 Island mode ◊◊◊ Emissions (kg/MWh): CO2 0 Demand mon ◊◊◊ NOx 0 Ancillary services ◊◊ SO2 0 Black start ◊◊◊ CO 0 Unfavourable aspects Equivalent hours (h): 2,000-2,500 Harmonics ◊◊ Coverage surface (m2/kW): 1.9-2.6 Flicker ◊◊ Surface (m2/kW)ii: 60-330 Cost of investment (€/kW): 750-1,500 O&M (cent/kWh): 1.5-2 LEC (cent/kwh)iii: 5.8 (3.6-8.5) LEC (pts/kwh)iii: 9.6 (6.0-14.2)

Remarks: New wind farm technologies try to minimize some of the most unfavourable aspects. This technology has reached a considerable level of maturity but can still develop further.

i: Size refers to wind farms and not individual generators ii: Includes the area of the entire facility. Source: (Eberhard et al, 2000). iii: The first value is the average value calculated with availability averages, cost of installation, O&M, price of fuel and efficiency. The values between brackets are values calculated for the entire variation range.


Figure 2.2.7.2 Characteristics and properties of Wind farm stations

2.2.8 Solar

Solar Photovoltaic:

Technology that turns solar energy into electricity. The energy performance achieved today is around 25%.

28


Figure 2.2.8.1 Photovoltaic panels Photovoltaic generation systems can be divided into three segments: • Isolated operation: Isolated operation is used in areas that do not have

access to the distribution network and require the use of batteries and a load regulator.

• Hybrid operation involves connecting photovoltaic panels in parallel with another source of generation, such as a diesel engine or a wind farm generator.

• Connected in parallel with the grid: consumption feeds either from photovoltaic panels or the grid, switching through an inverter. This solution offers the advantage of not requiring a battery or load regulator, which reduces losses and the required investment.

It is a highly intensive technology in terms of capital (cost of 5000-7000 euros/kW) but does not require any fuels. The advantages are that it does not require maintenance and can feed consumptions away from distribution networks. The following is a summary chart with the most important characteristics (Mendez Quezada, 2005):

Solar photovoltaic Characteristics Favourable aspects

Fuel: Solar radiation Cogeneration ◊◊◊ Size (MW)i: 1-500 Dispatch ◊◊◊ Efficiency (PCI) %: 10-20 Island mode ◊◊◊ Emissions (kg/MWh): CO2 0 Demand mon ◊◊◊ NOx 0 Ancillary services ◊◊◊ SO2 0 Black start ◊◊◊ CO 0 Unfavourable aspects Equivalent hours (h): 1,100-1,500 Harmonics ◊◊

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Surface (m2/kW): 7.5-20 Flicker ◊◊ Cost of investment (€/kW): 5,000-7,000 O&M (cent/kWh): 40-50 LEC (cent/kwh)i: 37.4 (26.9-51.7) LEC (pts/kwh)i: 62.2 (44.8-86.0)

Remarks: Some of these aspects can be improved if combined with storage systems. It is a technology that is still under development.



Figure 2.2.8.2 Characteristics and properties of photovoltaic power

Solar heat: This technology is still under development but represents an interesting alternative. The basic concept of this technology is that the heat obtained by concentrating solar radiation is used to heat a fluid and then produce steam suitable for use in a conventional steam turbine. Generally, the fluids used are molten salts as they support higher operating temperatures. There are mainly three types of electricity generation using solar heat technology: • Cylinder-parabolic collectors: This scheme involves cylindrical-parabolic mirrors to concentrate solar radiation in a tube located along the core of the collector. The tube contains the fluid to be heated and can reach temperatures close to 400ºC. Figure 3 shows a diagram of this kind of collector. The fluid that is heated is taken to heat exchanges to produce steam and drive the turbine. These systems are provided with a movement mechanism that allows tracking the sun in order to improve efficiency. This movement can be on one axis (vertical or horizontal) or both.

30


Figure 2.2.8.3 Parabolic cylinder collectors

A possible scheme of production with steam turbine would be:

Figure 2.2.8.4 Production diagram of solar station with steam turbine

• Central tower or heliostats: This scheme involves a large number of flat mirrors, known as heliostats, to concentrate solar radiation in a central receiver located in the upper part of

31


the tower. The number of mirrors involved is normally hundreds or even thousands. The mirrors tend to be large in size in order to minimize the number of solar radiation directing and tracking mechanisms. Two tanks are used to store the fluid: one “cold” and another “hot”. The “cold” tank stores the fluid at around 300ºC, which is pumped to the central receiver where it reaches temperatures of around 560ºC. From there it is pumped to the “hot” tank, where it is stored for subsequent use in steam production. The current designs offer storage times between 3 to 13 hours, reaching an annual availability of up to 65%.

The following shows a diagram of the process and a photo of a solar station with central tower and heliostats:

Figure 2.2.8.5 Solar tower and heliostats

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Figure 2.2.8.6 Diagram of a solar station production process with a tower and heliostats

• Parabolic disks: This scheme involves mirrors in the form of parabolic dishes to concentrate solar radiation in a receiver located in the focus of the mirror. The fluid in the receiver is heated to around 750ºC and can be used to generate steam or, in the event of a gas, used directly in a Stirling type motor located in the receiver. The Stirling motor is similar in operation to a two-stroke internal combustion engine but the fundamental difference is that the heat source is external. The parabolic dish system is the one that provides greatest concentration of solar radiation due to its two dimensional parabolic section. This enables reaching greater operating temperatures and therefore greater efficiency.

Figure 2.2.8.7 Parabolic collectors

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The following is a summary chart with the most important characteristics (Mendez Quezada, 2005):

Solar heat

Characteristics Favourable aspects Fuel: Solar radiation Cogeneration ◊◊ Size (MW)i: 5-100 Dispatch ** Efficiency (PCI) %: 10-20 Island mode ** Emissions (kg/MWh): CO2 0 Demand mon ** NOx 0 Ancillary services ** SO2 0 Black start ◊ CO 0 Unfavourable aspects Equivalent hours (h): 2,000-2,500 Harmonics ** Surface (m2/kW): 7.5-15 Flicker ** Cost of investment (€/kW): 2,500-3,800 O&M (cent/kWh): 2 LEC (cent/kwh)i: 13.2 (9.6-17.7) LEC (pts/kwh)i: 22.0 (16.0-29.5)

Remarks: A technology in research phase. Requires large areas of land install the mirrors.



Figure 2.2.8.8 Characteristics and properties of solar heat

2.2.9 Fuel cells

Device capable of converting chemical energy directly into electricity. They are based on a chemical reaction based on Hydrogen and Oxygen to generate water, heat and electricity. Its operation is similar to a conventional battery, with two electrodes and an electrolyte that conducts ions. Fuel (hydrogen) reaches the anode, where it loses, thanks to the help of a catalyst that reacts with the electrode, an electron. Hence the resulting H+ ion starts its migration through the electrolyte to the cathode, where it combines with oxygen to form water and generate heat in an exothermic reaction. The advantages are great energy efficiency (35-50%), no contribution to the greenhouse effect and allowing greater safety of supply.

34


Contrary to the batteries, where the “fuel” is internal (and therefore need to be recharged periodically), the cell is fed from an external source. In this sense the fuel cell can operate in continuous and uninterrupted mode. The basic fuel for the cell is hydrogen. Normally some kind of fossil fuel is converted in order to contribute this fuel, which is generally natural gas.

Figure 2.2.9.1 Fuel cells. Operation diagram The main characteristics are: • Anode: fuel electrode, that supplies a common interface for the fuel and electrolyte, promotes the catalytic reaction to oxidize the fuel and drives the electrons from the reaction place to the external circuit, or to a current collection, which in turn drives the electrons to the external circuit. • Cathode: electrode of oxidant, which provides a common interface for the oxygen and electrolyte, catalyzes the reduction reaction and drives the electrons from the external circuit to the place of the oxygen reaction. • Electrolyte: medium to transmission one of the species (cations or anions) that participate in the fuel and oxidant electrode reactions, though it must be conductive in order to avoid short-circuits in the system. On the other part, it plays an important role in the separation of fuel and oxidizer

35


gases, which is achieved through the retention of the electrolyte in the pores of a matrix. The capillarity force of the electrolyte within the pores allows the matrix to separate gases even under differential pressure situations. • Two pole plate: Its function is to separate individual cells and connect them in sequence, hence creating the fuel cell. They include gas channels to introduce reacting gases in the porous electrodes and to extract the resulting and inert gases. The basic unit of a cell can generate a current that is proportional to the surface of electrodes and “standard” voltage of 1.2V. These basic units are piled in order to find the desired levels of voltage and power and form what is called a “stack”. There are different types of cells, which vary depending on the nature of the electrolyte being used: • Direct Methanol Cells: The fuel used is a mixture of methanol and water, not explosive and of easy storage. The oxygen required for its operation is drawn from the atmosphere, which enters the cell through diffusion and convection processes. They are characterized by the ability to quickly change their output power, adapting to changes in demand. • Liquid oxygen cells: The electrolyte is a porous solid consisting of steel oxides. It operates at temperatures around 900-1000 ºC. They can be used in high power applications, including large scale power generation stations. Several tests have been performed with 125kW prototypes. The electrical efficiency can reach up to 60%. • Molten carbonate cells: the electrolyte is a mixture of lithium carbonates, sodium and potassium, in a ceramic matrix. It operates at a temperature range of 650-700 ºC, temperatures that create a molten conductive mixture suitable for the carbonated ions. They offer high fuel-electricity efficiencies and the possibility of using carbon-based fuels. • Phosphoric acid cells: It uses highly concentrated (98%) phosphoric acid (HPO3) as its electrolyte, held in a carbon silicon matrix. It operates at a temperature between 150-200 ºC, range in which the ionic conductivity of the phosphoric acid works best. It is the most developed cell on a commercial level and is used in multiple applications such as clinics, hospitals and hotels. Phosphoric acid fuel cells generate electricity with

36


efficiency greater than 40% and close to 85%; steam produced can be used in cogeneration. Today, the cost of a commercial fuel cell is around 1600-3500 euros/kW. In the case of hydrogen based cells, the need to establish an infrastructure to handle it, although technically possible, creates added difficulties to its cost. Cells will only become economically viable when the hydrogen production becomes cheaper.

Fuel cells

Characteristics Favourable aspects Fuel: Hydrogen, natural

gas, propane Cogeneration ***i

Size (MW)i: 20kW-2MW Dispatch *** Efficiency (PCI) %: 30-50 Island mode ** Emissions (kg/MWh): CO2 360-630 Demand mon ** NOx < to 0.023 Ancillary services ◊◊ SO2 0 Black start ◊◊ CO 0.005-0.055 Unfavourable aspects Availability %: Greater than 95 Harmonics ◊◊ii

Start-up time: 3-48 h Flicker ◊ Surface (m2/kW): 0.06-0.11 Cost of investment (€/kW): 1,600-3,500 O&M (cent/kWh): 1.5-2 LEC (cent/kwh)iii: 8.5 (6.0-12.1) LEC (pts/kwh)iii: 14.2 (10.0-20.1)

Remarks: A technology in research phase. Requires large areas of land install the mirrors.

i: Depends on fuel cell type. ii: New types of investors tend to minimize this problem. iii: The first value is the average value calculated with availability averages, cost of installation, O&M, price of fuel and efficiency. The values between brackets are values calculated for the entire variation range.


Figure 2.2.9.2 Characteristics and properties of fuel cells

2.2.10 Flywheels

An emerging technology with little practical use today is the flywheel. The objective of this kind of technology involves providing an amount of energy during a relatively short period of time; they could play a very important role in the primary regulation of frequency-power control. The basic layout of a flywheel would be:

37


Figure 2.2.10.1 Flywheels

The operation diagram of the flywheel is as follows:

Figure 2.2.10.2 Operation diagram of a flywheel The application uses of this technology could be: For transmission: a) Voltage support

- Important voltage drops (more than one train passing through a point on the grid) - may generate excessive transmission losses (RI2) - Energy storage system suitably sized and placed can overcome these problems - when trains accelerate, the storage system provides energy to the grid (increase grid voltage and reducing demand) - During low demand periods, the storage system is recharged

b) Regenerative braking

38


- Brake energy is returned to the grid - If there is no load that absorbs this energy, for example, a train accelerating, or an energy storage system, this energy is wasted - A system with a suitably sized flywheel is capable of absorbing and returning system energy as required. Example: 200kW, 14MJ (4 kWhr)

c) Additional power - As the systems are expanded, new technologies are developed and the number of passengers increase, the grid at the substation may need to be updated. - Increasing an existing substation may not be possible - The compact and modular nature of a flywheel offers a flexible alternative to these matters.

d) Maintenance programs - Maintenance routines and the need to repair substations and related equipment has become a difficult task in congested metro systems: Increase in voyages and demand for shorter journeys makes it difficult to isolate substations while providing suitable voltage and operation of the system. - Under these situations, and as a temporary solution, a storage system based on flywheels enables performing maintenance work, while the flywheel maintains the required voltage level in the grid.

For a suitable power management: a) Normalize consumption

- During low consumption periods, energy is stored in flywheels. - At peak times, power is returned to the grid.

b) Result - Reduction of losses in transmission and distribution - Greater maximization of an existing substation. Lower consumption peaks.

39


3. Installed power and distributed generation production in Spain

40


3. Installed power and distributed generation in Spain

This section describes the evolution of installed distributed generation power in Spain, as per UNESA data, production based on data provided by CNE and a possible estimate for 2050 of renewable energy that could be installed on the peninsula.

3.1. Installed power of distributed generation

First, we shall show the installed power since 1990 to 2004, according to data provided by UNESA, considering the following types of technology: Cogeneration, Wind farm, Hydraulic, Waste, Biomass, Waste treatment and Solar.

AÑO / P.Instalada (MW)

COGENERACIÓN EÓLICA HIDRÁULICA RESIDUOS BIOMASA TRAT.RESIDUOS SOLAR Total

1990 356 2 640 43 1.0421991 597 3 754 52 1 1.4071992 648 33 796 82 24 1.5821993 1.150 34 856 87 24 2.1511994 1.441 41 940 158 26 1,0 2.6051995 1.759 98 998 201 40 1,0 3.0971996 2.350 227 1.058 247 40 1,0 3.9221997 2.728 420 1.107 247 41 1,0 4.5431998 3.734 884 1.240 292 68 1,1 6.2181999 4.256 1.674 1.377 311 77 29 1,1 7.7262000 5.015 2.289 1.407 294 127 82 1,4 9.2132001 5.429 3.501 1.499 404 197 159 3,2 11.1902002 5.663 5.059 1.532 416 321 327 6,8 13.3172003 5.745 6.320 1.602 423 421 423 10,8 14.9332004 5.869 8.203 1.641 540 433 468 21,1 17.154

Table 3.1.1 Installed power of the various DG technologies

41


Graphically: Evolucion de potencia instalada en el régimen especial en España

1.0421.407 1.582

2.151

0

2.000

4.000

6.000

8.000

10.000

12.000

14.000

16.000

18.000

1990 1991 1992 1993

MW

COGENERACIÓN H

Figure 3.1.1 Evolution As can be seen, the Dfarm energy, reaching 9second although its groAccording to new econan important increase in Considering the regulatdisplays the installed p2005:

la

2.6053.097

3.9224.543

6.218

7.726

9.213

11.190

13.317

14.933

17.154

1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

IDRÁULICA RESIDUOS EÓLICA BIOMASA TRAT.RESIDUOS SOLAR Total

of installed power under special regime in Spain

G technologies that have increased most in Spain is wind 300MW of installed power at the end of 2005. Biomass is

wth has stabilized in recent years. omic incentives, it seems that solar energy will experience upcoming years.

ory division in RD 436/2004, the following summary table ower in kW in each Spanish province updated as at 1-10-

42


Table 3.1.2 Installed DG power by province according to classification in RD 436/2004

43


44

Grouping the installed power by kW by autonomous communities, you get:

Andalucía 942.602Aragón 1.557.989Asturias 280.932Baleares 9.835Canarias 47.306Cantabria 54.653Castilla La Mancha 1.997.908Castilla y León 1.844.812Cataluña 510.287Comunidad Valenciana 381.723Extremadura 20.632Galicia 2.250.821la Rioja 461.416Madrid 244.494Navarra 868.602País Vasco 286.748Región de Murcia 249.538Total 12.010.299

Potencia instalada (kW)

Table 3.1.3 Installed DG power by autonomous communities

Potencia in talada por comunidad autónoma

Castilla y León 15,4%

Madrid2,0%

Navarra7,2% País Vasco

2,4%

Región de Murcia2,1% Aragón

13,0%

Castilla La Mancha16,6%

Galicia18,7%

Comunidad Valenciana3,2%

Extremadura0,2%

Cataluña4,2%

la Rioja3,8%

Andalucía7,8%

Cantabria0,5%

Canarias0,4%

Baleares0,1%

Asturias2,3%

s

Figure 3.1.2 Installed DG power by autonomous communities


The autonomous community with greatest amount of installed power under special regime is Galicia with 18.7%, followed by Castilla La Mancha 16.6%, Castilla & Leon 15.4% and Aragon 13%. The previous autonomous communities present high installed power levels thanks to wind farm generation, which is the technology that experienced most increase. Grouped by category and autonomous community:

Potencia instalada (kW)

y (%)

Andalucía 39.174 4,5% 536.788 5,9% 22.896 13,7% 343.744 19,2%Aragón 25.667 2,9% 1.364.359 14,9% 10.234 6,1% 154.380 8,6%Asturias 12.888 1,5% 236.561 2,6% 23.440 14,0% 8.043 0,5%Baleares 6.094 0,7% 3.741 0,0% 0 0,0% 0 0,0%Canarias 8.648 1,0% 38.658 0,4% 0 0,0% 0 0,0%Cantabria 0 0,0% 51.653 0,6% 0 0,0% 0 0,0%Castilla La Mancha 71.713 8,2% 1.766.545 19,3% 0 0,0% 159.645 8,9%Castilla y León 55.145 6,3% 1.484.098 16,2% 0 0,0% 300.739 16,8%Cataluña 115.477 13,3% 173.457 1,9% 5.200 3,1% 216.116 12,1%Comunidad Valenciana 192.124 22,0% 57.411 0,6% 38.839 23,2% 93.349 5,2%Extremadura 0 0,0% 9.001 0,1% 0 0,0% 11.631 0,7%Galicia 100.656 11,6% 1.915.201 20,9% 66.883 39,9% 142.482 8,0%la Rioja 6.716 0,8% 426.119 4,7% 0 0,0% 28.581 1,6%Madrid 128.188 14,7% 39.077 0,4% 0 0,0% 77.228 4,3%Navarra 33.047 3,8% 810.653 8,9% 0 0,0% 23.346 1,3%País Vasco 66.597 7,6% 120.458 1,3% 0 0,0% 99.445 5,6%Región de Murcia 9.250 1,1% 113.232 1,2% 0 0,0% 127.056 7,1%Total 871.384 100% 9.147.013 100% 167.492 100% 1.785.785 100%

grupo dGrupo a Grupo b Grupo c

Table 3.1.4 Installed DG power by autonomous communities as per RD 436/2004

Graphically:

45


Potencia instalada por comunidad autónomaGrupo a


Asturias1,5% Baleares

0,7%

Canarias1,0%

Cantabria0,0%

Andalucía4,5%

la Rioja0,8%

Cataluña13,3%Extremadura

0,0%

Comunidad Valenciana

22,0%Galicia11,6%


Aragón2,9%

Región de Murcia1,1%

País Vasco7,6%

Navarra3,8%

Madrid14,7%

Figure 3.1.3 Installed DG power by autonomous communities. Group A

Potencia instalada por comunidad autónomaGrupo b

Madrid0,4%

Navarra8,9%

País Vasco1,3%


Aragón14,9%


Galicia20,9%


0,6% Extremadura0,1%

Cataluña1,9%

la Rioja4,7%

Andalucía5,9%

Cantabria0,6%

Canarias0,4%

Baleares0,0%

Asturias2,6%


Figure 3.1.4 Installed DG power by autonomous communities. Group B

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Potencia instalada por comunidad autónomaGrupo c


Asturias14,0%

Baleares0,0%

Canarias0,0%

Cantabria0,0%

Andalucía13,7%

la Rioja0,0%

Cataluña3,1%

Extremadura0,0% Comunidad

Valenciana23,2%

Galicia39,9%


Aragón6,1%


País Vasco0,0%

Navarra0,0%

Madrid0,0%

Figure 3.1.5 Installed DG power by autonomous communities. Group C

Potencia instalada por comunidad autónomaGrupo d

Madrid4,3%

Navarra1,3%

País Vasco5,6%


Aragón8,6%


Galicia8,0%


5,2%

Extremadura0,7%

Cataluña12,1%

la Rioja1,6%

Andalucía19,2%

Cantabria0,0%

Canarias0,0%

Baleares0,0%

Asturias0,5%


Figure 3.1.6 Installed DG power by autonomous communities. Group D

47


Finally, a comparative table with the evolution of installed power from 1998 to 2003 with regards to the 2011 infrastructure plan is provided below:

13.0

6.202

934

00

2.3801.5461.51514489

3.000

361187,8

0

2000

4000

6000

8000

10000

12000

14000

Biomasa Fotovoltaica Minihidráulica Eólica

Potencia instalada en 1998, potencia instalada a finales de 2003 y Objetivos del

Plan de Infraestructuras (2002-2011)(MW)

Primera columnaSegunda columnaTercera columna

– Elaboración del Plan de Fomento ERs: 1998– Potencia instalada a finales de 2003

– Plan de Infraestructuras: 2011

Figure 3.1.7 Installed power in 1998. Installed power at the end of 2003. Objectives of the infrastructure plan (2002-2011)

3.2. Distributed generation production in Spain

According to CNE data, the production of renewable energies at the end of 2003 was 17,197 GWh, which represented 7.27% of total production.

48


Graphically:

Intercambios Int. 1.2760,51%

Energías Renovables

17.1977,27%

Residuos 3.7181,57% Hidráulica

38.52316,38%

Gas Natural 18.6827,91%

Carbón 72.56230,88%

Cogeneración 16.8647,15 %

Fuel-Oil4.2421,78%

Nuclear 61.84826,06%

Figure 3.2.1 DG Production in GWh. 2003 Breaking down renewable production into the most important technologies:

0

2 . 0 0 0

4 . 0 0 0

6 . 0 0 0

8 . 0 0 0

1 0 . 0 0 0

1 2 . 0 0 0

E ó l i c a 1 1 . 0 3 0H i d r á u l i c a 4 . 8 0 1B i o m a s a 1 . 3 5 8F o t o v o l t a i c a 8

Figure 3.2.2 Renewable production by technology. 2003 Renewable energies invested a total of 1,500 million euros in 2003 and revenue a total 1,050 million euros.

49


This means that the renewable energies provided electricity to 4,776,000 families, avoided the emission of 16,509,000 tonnes of CO2 and avoided importing

ble energies in peninsular Spain

ace, 2005), the estimate power demand for 2050 will be 1,525 TWh/year, which is equal to 109

1,478,000 tonnes of oil.

3.3. Potential of renewa

According to a report produced by Greenpeace (Greenpe

kWh/working day. Spain would have the following potential in terms of renewable installed power and production:

Potencial GDPotencia instalada

(GW)Producción (TWh/año)

Geotérmica 2,48 19,53Hidráulica 18,8 37,61Biomasa 19,46 141,16Olas 84,4 296Eólica marina 164,76 334Fotovoltaica 1202,9 1951,5Solar Térmica 2739 9897Chimenea Solar 324,3 836,2Eólica terrestre 915 2285

Table 3.3.1 Potential of renewable installed power estimated for 2050

The n or distribution restrictions, etc.

ewable energy resources.

roduction could reach 5,798TWh/year, which would represent a coverage margin of 10.4 times

production. First would be solar heat, followed by wind farm and

table above does not include technical, regulatory, transmissio

However the goal is to calculate the size of possible energy potential in the peninsula considering the ren The maximum installed renewable energy p1demand. Summarizing potential production, the following chart shows the breakdown of renewablephotovoltaic.

50


Figure 3.3.1 Potential renewable installed power estimated for 2050

51


4. Regulations regarding distributed generation in the Spanish power sector

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4. Regulations regarding distributed generation in the Spanish power sector

This section provides a summary of existing legislation in the Spanish power sector that has configured the existing DG regulatory framework and its relation with distribution. First, we shall enumerate the main Acts and Royal Decrees in chronological order that directly or indirectly reference the various aspects of DG: • Government Order, September 5, 1985, which “establishes administrative and

technical standards for the operation and connection to power grids of hydroelectrical power stations of up to 5,000 kVA and autogeneration power stations”

• RD 2366/1994 “regarding the production of electricity by hydraulic power

stations" • Act 54/1997, which “regulates activities destined to the supply of electricity,

consisting of its generation, transmission, distribution, sale and intracommunitary and international exchange, as well as the economic and technical management of the power system”

• RD 2818/1998, December 23, “production of electricity by facilities supplied

by renewable resources or sources of energy, waste and cogeneration” • RD Act 6/2000, June 26, which “approves urgent measures for intensifying

competition in goods markets and services (deregulation of the electricity sector)”

• RD 1663/2000, September 29, regarding the “connection of photovoltaic

facilities to the LV grid” • RD 1995/2000, December 1, “regulation of the transmission, distribution, sale,

supply activities as well as the procedures for authorizing electricity facilities [Official State Gazette 2000] ”

• RD 1664/2001, October 26, regarding “access fees to electricity transmission

and distribution networks” • RD 841/2002, August 2, which “regulates the involvement and participation of

electricity production facilities under special regime in the production market, as well as certain obligations to report on their production forecast and the acquisition of their produced electricity by resellers”

• RD 1432/2002, December 27, which “establishes the methodology for the

approval or modification of the average or reference electricity tariff and

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modifies some sections of Royal Decree 2017/1997, December 26, whereby organizing and regulating the procedure for settling transmission and distribution costs as well as the sale at a tariff, of permanent system costs and diversification costs and safety in supply”

• RD 436/2004, March 12, which “establishes the methodology for updating and

systematizing the legal and economic regime of the electricity production activity under special regime”

• RD 2351/2004, December 23, which “modifies the procedure for resolving

technical restrictions and other regulations of the electricity market” • RD 1454/2005, December 2, which “modifies certain provisions regarding the

electricity sector”.

The most important change on a regulatory level that in some way has led us to the current situation started with Act 54/1997, which introduced market schemes in activities such as generation and sale and maintained the transmission and distribution as regulated markets due to their connotation as natural monopolies. From the distributed generation perspective, Act 54 introduced regulations for generation under special regime for facilities with an installed power less than 50MW, with a remunerative and regulatory nature different to generation stations participating in the wholesale market pool. After Act 54/1997, there are two clearly differentiated periods. On one hand, the one initiated by RD 2818/1998, effective from 1998 to 2004, and on the other RD 436/2004, which is still in effect:

4.1. Period 1998-2004

4.1.1 RD 2818/1998

We could say that RD 2818/1998 is the regulatory development of Act 54/1997 focused on the production of electricity by facilities supplied with renewable energy sources, waste and cogeneration. Said decree abolishes the existing regulation to that date (RD2366/1994), although it remained in effect for the facilities that were under the protection of said RD. RD 2818/1998 provided an additional premium, different for each technology, at the average wholesale market pool price for all generation stations that operated under the special production regime.

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However, some technologies such as solar, wind farm, geothermal, waves, tides as well as hot and dry rocks had the option to perceive a fixed price. However, such fixed price was not very different from the previous case as its calculation was performed based on the expected wholesale market price plus the aforementioned premium. Although in RD 2818/1998 references the possibility of participating in the wholesale market under special regime, the reality was considerably different as the economic incentives were insufficient, although there were additional costs.

4.1.2 RD841/2002

Although with RD 841/2002, which regulated and developed sections 16, 17 and 18 of RD Act 6/2000, the goal was precisely to obtain greater integration of generation under special regime in the wholesale market, obtaining in this case a premium and greater remuneration by guaranteeing power to fulfil its income per market. The possibility of adding its production in order to enter the market was enabled; it even proposed the possibility of participating in operation markets (solutions to technical restrictions, diversion of generation – consumption and ancillary services). However, this forced facilities based on renewable energies to associate with another type of more predictable technology in order to provide this service. Therefore, the need for agents to combine a technology mix in their portfolio was created to provide this service, which implied an entry barrier to satisfy the service. On the other hand, RD 841/2002 developed a series of aspects that had been formulated in RD Act 6/2000: • The requirement of certain facilities to enter the market, presenting proposals for the sale of energy, and perceiving in return the price resulting from the offer system, plus an amount in terms of power guarantee (Section 17 RD Act 6/2000 and Act 54/1997). • The requirement for certain facilities not attending the market to notify of its time schedule to the distribution company, providing in certain cases for penalties in the event of deviations that might occur (Section 18 RD Act 6/2000). • New forms of engagement of resellers with producers under special regime and external agents (Section 21 RD Act 6/2000).

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• Furthermore, RD 841/2002 regulated the rights and obligations when accessing the market of facilities encompassed in RD 2818/1998 and RD 2366/1994. With regards to market supply, RD 841/2002 stated the following: • P ≥50 MW: mandatory supply to the wholesale market. The proposal must be presented as an independent unit, under the same conditions as the ordinary regime. Normally they would subcontract the sales management of their supply. • P ≤50 MW: supply to the optional market. Present themselves directly as independent units or through a selling agent (producers, self producers and resellers), who can represent all facilities under special conditions it represents. The supply shall be performed for each scheduled period for the excess energy provided. They participate under the same conditions as the other producing agents under ordinary regime. • P < 5MW: supply the optional market under certain conditions. If they wish to enter the market, they must do so through a selling agent, who shall combine all the units it represents in its supply. A summary table is provided below with the most significant aspects of this RD 841/2002:

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Table 4.1.2.1 Summary of RD841/2002

4.2. Period 2004 – Present:

4.2.1 RD 436/2004

This period starts the publication of RD436/2004, which is in effect at present. This RD initiates a long lasting, objective and transparent period as it maximizes the stability provided by the methodology of an average reference tariff (Tarifa Media de Referencia – TMR) in RD 1432/2002.

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RD 436/2004 repeals RD 2818/1998 and RD 841/2002 although it provided for a transition period during which RD 841/2002 shall coexist until January 1, 2007. Basically this RD consists of two alternatives in terms of remuneration of generation: • On one hand, generation cannot access the market and obtain a constant amount for each kWh produced. Its evolution is connected to the evolution of the average or reference tariff (TMR) as its value is set as a percentage of such tariffs. The price received (percentage of TMR) varies depending on technology and the years since putting the facilities into service. The TMR is calculated each year and is used in order to determine consumption tariffs. • On the other hand, any facilities that need to access the market shall do so under the same rights and obligations as the rest of generators. In practice, this is not the case with regards to the ancillary services market and solutions to restrictions as will be discussed in the next chapter. The only option of the DG, as already mentioned, consists in combining offers to technically provide the service. In this case, the remuneration is based on perceiving the market price plus a premium and incentive for participating in the market. Both the premium and the incentive are indexes to the TMR in the same way as the fixed price of the previous option. Regardless of the chosen option, there is a complement in return for compensating reactive, which shall depend on the type of period and power factor, determined by the following table:

Table 4.2.1.1 Incentive to the compensation of reactive as per RD 436/2004

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According to the classification of generation under special regime in RD 436/2004, technologies are divided by the primary energy used, the production technologies involved and the energy performances achieved:

• Group a):

Cogeneration and other forms of energy associated to non electrical activities. If the installed power is under 25MW, 30% of its electricity production shall be for self-consumption and 50% in the event of more than 50MW.

Group a.1): Facilities that include a cogeneration station Group a.1.1): 95% of primary energy used is Natural Gas. Group a.1.2): rest. Group a.2): Facilities that include station that uses residual energies resulting from any activity not destined to produce electricity.

• Group b): Facilities that use any of the non consumable renewable energies as the primary source of energy. Group b.1): solar power. Group b.1.1): Solar Photovoltaic Group b.1.2): Solar heat Group b.2): Wind farm power Group b.2.1): located on land Group b.2.2): located at sea Group b.3): facilities whose energy source involves tides, geothermal, ocean heat, hot and dry rocks and sea currents. Group b.4): hydroelectric stations with an installed power not greater than 10MW. Group b.5): hydroelectric stations with an installed power greater than 10MW and not greater than 50MW. Group b.6): biomass from energy cultivations, forest developments, agricultural activities, etc. Group b.7): biomass from manure, biofuel, agricultural or livestock waste, waste water treatment sludge, etc. Group b.8): biomass from the agricultural and forest sector or a combination of the two.

• Group c):

Facilities that use waste as primary source of energy with energy valuation not included in group b. Group c.1): Solid urban waste Group c.2): other waste not specified above

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Group c.3): Facilities that use waste as fuel whenever they do not represent 50% of the primary energy used.

For groups b and c, the primary fuel shall be at least 70% of the primary energy used. In the case of group b.8, this percentage would be 90%

• Group d):

Facilities with installed power not greater than 25MW that use cogeneration for processing and reducing waste in the agricultural, livestock and services sectors. Group d.1): Pork operation waste from surplus areas. Group d.2): sludge reduction and processing. Group d.3): any not included in d.1 and d.2.

4.2.2 RD 2392/2004

Real Decreto 2392/2004, which establishes the electricity rates for 2005, modified the 2004 TMR in RD436/2004, established the price for verifying photovoltaic facilities and modified the incentives defined in RD436/2004 for cogeneration.

4.2.3 RD 2351/2004

Real Decreto 2351/2004 (Ministry of Industry, Tourism and Commerce, 2004), which modifies the procedure for resolving restrictions and other regulations of the electricity market as well as the treatment to the consumption of fuels in solar heat stations provided in RD 43672004; modified the calculation for updating premiums in RD 436/2004 for cogeneration and the production of energy using waste and delayed the requirement for providing estimates and the imposition of penalties for deviations as per RD 436/2004 until January 1, 2006.

4.2.4 RD 1454/2005

Very recently the Ministry of Economy approved RD 1454 (Ministry of Economy, 2005), which modified certain provisions regarding the electricity sector. This RD modified RD 1955/2000 in order to forbid the new cascading distribution, preserving the requirement for the existing distributor in the area to extend the grid. Furthermore, it also modified it to avoid uncertainties regarding the new capacity to be installed. • It added a new paragraph to the end of 1 in section 60 with the following wording: “The right of access of distributors to the grids of other distributors shall be limited to the existing distributors and the cases in which an increase of interconnection capacity is required in order to

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http://www.cener.com/cener/imagenes/archivos/RD2392_2004_tarifa_2005.pdf

http://www.cener.com/cener/imagenes/archivos/Rd 2351 restricciones t�cnicas pdf.pdf


support an increase in demand in the area based on the minimum system cost criterion”. This modification is important as it (at last) involves the competition of new distribution networks by establishing territorial franchises. • It adds an additional twelfth provision. Procedure for authorizing small generation facilities of generation facilities connected to distribution networks. “The administrations competent of authorizing production facilities shall ensure the authorization procedures of small generation facilities of less than 50 MW or generation facilities connected to distribution networks consider their limited size and possible impact”. • Chapter III adds a new section 59 titled guarantees for processing the transmission grid access request for new production facilities under special regime. It specifies that “in the case of production facilities under special regime, the requestor shall present, before performing the transmission grid access request, a copy from the General Depository to the General Directorate of Energy and Mining Policy confirming it has provided a guarantee worth 2% of the installation's budget. The presentation of this copy by the system operator shall be mandatory in order to initiate access procedures and connection to the transmission grid. RD 436/2004, March 12, was modified in order to rationalize the incentive for cogenerations with an installed power greater than 50 MW and to define aspects of the Royal Decree in order to facilitate the invoicing of power transferred and its admission in the activity settlement and regulated costs system. • paragraphs 6 and 7 were added to section 28, with the following wording: “6. The National Energy Commission shall be responsible for executing the corresponding sanctioning procedures in the event of non compliance with the provisions in previous paragraphs. 7. It establishes the obligation for all facilities under special regime with power greater than 10 MW to be associated to a control centre that will act as the system operator mediator, transmitting instructions to the various owners of said facilities or its representatives, in order to guarantee the reliability of the electricity system at all times". • First additional provision modifies the remuneration provided to cogeneration facilities that use liquid oil derivatives as fuel, under the scope of transition provisions one and two of Royal Decree 436/2004, March 12.

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4.3. European regulation

The most significant aspects with regards to the promotion of electricity generated from renewable energy sources in the internal electricity market are defined in European Directive 2001/77/EC del Parlamento Europeo y del Consejo, de 27 de septiembre de 2001, regarding the promotion of electricity generated from renewable energy sources in the internal electricity market. On the other hand, Directive 2004/8/CE del Parlamento Europeo y del Consejo, de 11 de febrero de 2004, regarding the promotion of cogeneration based on demand of useful heat in the internal energy market modifies Directive 92/42/EC.

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http://www.cne.es/pdf/legislacion/Directiva2001_77CE.pdf

http://www.cne.es/pdf/legislacion/Directiva2001_77CE.pdf

http://www.cne.es/pdf/legislacion/Directiva2004_8_cogeneracion.pdf

http://www.cne.es/pdf/legislacion/Directiva2004_8_cogeneracion.pdf


5. Impact of DG in grid business. Planning and design

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5.1. Introduction

As already discussed in the first chapters, DG modifies the traditional hierarchical structure of grids, where power flowed from concentrated conventional production centres to end users. The energy flowed in radial form and unidirectionally in the distribution networks from higher to lower voltages. With the arrival of DG, these traditional concepts are disappearing. The impacts produced by DG are fundamentally due to the modification suffered by power flows, considering both the magnitude and direction. The purpose of this chapter is to analyze various real situations where the distributed generation takes on a special relevant role from the distributor perspective as a power carrier. For confidentiality purposes, the names of substations and cogeneration plants referenced in this document have been removed. A technical and regulatory analysis shall be performed for each aspect considered. The goal is to identify the state of the art and difficulties the distributor faces when tackling these matters. In addition, we have tried to differentiate two aspects of distribution, considering the most important aspects involved, such as the transmission of power from transmission grid border points to the end user, and the purchasing of energy for consumers included in the regulated market (comprehensive tariff customers). Considering the activity of distribution as transmission of energy (in charge of providing power to the users and therefore have the necessary grid - RD1955), the most relevant aspects to be analyzed are:

• Investments in the grid • Losses • Operation and exploitation of the grid • Voltage profiles • Quality of supply • Short-circuit power • Ancillary services • Safety of maintenance personnel

On the other hand and considering the distribution as purchasing agent in the energy production market due to its comprehensive tariff customers, we shall analyze the impact of distributed generation in the management of said activity. Although the transmission grid can be monitored and remotely controlled throughout, there are three highly differentiated areas that must be considered

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when it comes to analyzing the aforementioned relevant aspects. This chapter performs continuous references to said areas and discusses the difficulties caused by DG for each one of them. The three areas of distribution are: • Distribution grid – observable areas: the observable areas are the grids where the distributor has practically real time control, both in terms of monitoring and operation. These grids are what has typically been called “distribution”. Grids that connect to the transmission grid with the LV grid. Typically they cover voltage levels of 132, 66, 45 and 33 kV. They are controlled by SCADA (System Control Supervisory and Data Acquisition) systems and therefore the distributor company is aware of any incident and/or event that occurs in the grid in real time. Delivery grids have many “similarities” with the transmission grids as they are typically meshed (although not always) with a high degree of robustness. In fact, in many areas, the system operator needs to know the status of said grids as it has a direct repercussion on the transmission grid (such as the 132 and 66 kV in Galicia or the 132 kV in Andalusia). • MV grid – areas “semi-monitored”: areas that the distributor has a high degree of monitoring but not its operation in real time. These grids refer to those that connect to the delivery grid with transformer centres (TC). The SCADA systems of these grids are limited to the positions or line headers of MV substations (depending on type of substation and distribution company). The MV line header in general, includes monitoring of measurement, dispatch and viewing of the break status of its dispatch elements. The MV positions include what is commonly referred to as “MV line header”. There may be other intermediate remote controlled circuit breakers, which include despatching and signalling of break status but not measurement. This means that the last measurement monitored in real time today available to the distributor is the header of the MV substation. This does not mean there are measures of other kinds such as meters, mass meters, etc. but these are instruments that do not report in real time with regards to the distribution network activities. Although delivery grids are more or less MV meshed grids, they operate in star form and are typically of 15 or 20 kV (legislation defines MV grids between 1 and 36 kV). • LV Grid – Areas not monitored: areas that the distributor does not monitor or have remote operation in real time. It does not have measurements in real time and any type of information received from these grids is decoupled from real time (for example power cuts are detected through the claims made by customers to the

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distribution company when they suffer some kind of incident: power cuts, brief interruptions, low voltages, etc.). This kind of grid, same as MV are operated in star form and the ones that connect MV grids with the end user at LV. Typically they are 400V three-phase grids.

5.2. Influence of DG in the planning and design of the grid

For the distributor this point is perhaps one of the most important and of greatest repercussion today. This subject is today covered in many different ways (Iannucci, 2003), (Welch, 2000), (Wright and Formby, 2000), (Shirley, 2001), (Lasseter and Piagi, 2000), (Dugan, 2000), (Celli and Pilo, 2001) and (Mendez Quezada, 2005). However all these surveys do not consider the social function carried out distribution companies, as electricity is a top commodity and it is very difficult to quantify in economic terms the power not supplied; it is unacceptable both on a social level and in regulations, as a distributor, to assume demand cannot be covered or even that the size of grids may not cover all requirements. There are two fundamental aspects from the investment perspective as a distributor: • How are new generation facilities that wish to connect to the grid accommodated, and what are the criteria to be adopted for it? • What new grid needs to be built considering the generation included in the distribution network? Distributors are continuously asking themselves and reformulating these questions due to the dynamic nature of their grids and the changing and unpredictable behaviour caused by the installed distributed generation.

5.2.1 Technical grid connection criteria

When new generation facilities connect or ask for a connection to the distribution network, there are two very important perspectives for there to be a perfect synergy between distribution and generation. On one hand, the distribution would like to have a regulatory framework with efficient location signs to minimize losses an maximize investments. In addition, generation facilities would like a clear standard with regards to criteria and location to connect to the grid, as well as a clear regulation of costs in the cases when the connection involves a reinforcement of the grid. With regards to technical grid connection criteria, because there is no clear regulation on the matter, distribution companies have defined their own criteria, which usually involves the following considerations:

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• With regards to economic conditions, typically the generating facility shall cover all expenses such as preliminary studies, expansion or modification of existing facilities, new grid for connections, etc. (Chapter 2, section 8, RD 2366/1994) • The voltage level of the grid it will connect to is decided on the power to be installed. For example: facilities with an installed power less than 100kVA are typically connected to LV and those of more than 15MVA to grids of at least 132kV. • Voltage variation ranges shall not exceed a certain +V at the point where the generator is connected. Logically this depends on the size of the generator and short-circuit power at the point it will connect to (grid robustness). • With regards to the connection form, this shall depend on if the connection is overhead or underground and voltage level it connects to. Logically, the requirements increase as the voltage level they connect increases, as the installed powers are greater and the repercussion on the grid can be more significant. These types of connection can vary on requirements; for example, from a T junction with MV isolator to the entrance and exit with remote control circuit breakers in higher voltages. • With regards to the power factor, this aspect is encouraged in RD 436/2004 as already mentioned in section 3.2, hence normally the generator takes care of it. Prior to this decree, the power factor was made to be as close to the unit as possible. • Typically due to grid requirements, a minimum evacuation capacity is required, which is usually quantified as a percentage of nominal line or transformer capacity. (paragraph d, section 20, RD 2818/1998). • On other occasions, the power to connect at a node must not exceed a certain percentage of the node’s short-circuit power. Another very important aspect when it comes to connecting new generation facilities to the grid is the normalization and rationalization of protection criteria of each generator and its coordination with the protections of the distribution network. The existing regulations in terms of technical connection criteria from the protection perspective does not detail the conditions in which they must be fulfilled. Only the government order of 1985 states that generation facilities shall disconnect from the grid in the event of a blackout.

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Subsequent RD do not provide further details, hence each distribution company has had to internally define the technical protection conditions, which created uncertainty and lack of transparency to the DG facing different requirements depending on the distribution company it would connect to. Only RD 1663/2000 (Ministry of Economy, 2000b) states in paragraph 2, section 8 that photovoltaic facilities of up to 100kVA connected to the LV grid shall disconnect when they detect lack of power in the supply. In general, the following aspects are considered: • A standard layout of a specific facility could be as follows. Obviously this depends on each installation:

Red de Distribución

Figure 5.2.1.1 Example protection diagram for connecting to the distribution network

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With regards to current transformers, a series of minimum technical requirements shall be made. • With regards to installed protections, we should differentiate between the protections specific to the facilities, which are typically provided by the customer and protections of the interconnection with the distributor. The latter are the ones the distributor supervises for a proper integration and coordination of the installation with the grid. The problem resides in that the protections of the facilities are usually more restrictive than the interconnection, hence the installation is connected and disconnected in certain situations without any control from the distributor. This aspect shall be reviewed further below in the quality and operation sections (6.3 and 6.1 respectively).

The main function of protections in interconnections is to protect the grid from the DG and the DG from the grid. Therefore, the protections shall detect internal defects in the generator or defects in the grid that may affect the generator. This second case is the most complicated becacuse the unjustified disconnect as a result of any kind of external incident should be avoided whenever possible.

5.2.2 New investments in the grid

Each year the distribution company shall review the question: how much will my demand grow in future years? Logically, investments must be made in accordance with the forecast and growth estimate, which shall be sufficient to support the growth in demand and guarantee the continuity in the supply even in failure situations (criteria n-1). The problem faced by distributors today is that they must decide between: invest to cover net demand (gross demand – distributed generation) or, invest to cover gross demand. If opting for the first criterion, the generator facility may decide not to generate (discharge, breakdown, not economically profitable ...), which may result in an overload or even power cut because it cannot satisfy all the demand. Because the generation company does not have operational control over these facilities in the same way as the system operator under normal regime, it is forced to take conservative decisions and not take distributed generation into account to perform its investments. On the other hand, because of the development of DG and the positive adaptation of certain distributed generation profiles to demand profiles

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(Mendez Quezada, 2005), the distribution company could consider whether to build the grid or build generation when planning investments. Today, this is practically impossible. Firstly, the separation of activities usually required in the existing regulatory schemes, prevents an agent that executes regulated activities (distribution) from executing non regulated activities (generation). This presents distributors from owning DG in some countries, and specifically in Spain. Second, in general, there are no regulatory mechanisms that enable the distributor, even though not owning the DG, to provide the necessary location signals as to include DG in the planning of its networks. Today, the development of DG is completely independent from the execution of distribution networks and does not normally receive a location signal. There are surveys (Mendez Quezada, 2005) that have reviewed the subject of MV investments from the perspective if distributed generation delays investments that a distribution company must perform. The survey has considered the maximum admissible capacity of the grid elements, losses and admissible voltage drops as investment decision factors. The biggest contribution of the survey is that various analysis have been made using different generation profiles for the various demand profiles at MV header positions based on the type of technology and their degree of penetration in the grid. In order not to make the document too extended, we shall review the results of cogeneration in the analysis:

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Figure 5.2.2.1 Overload of MV grid by degree of penetration of cogeneration The previous chart shows the increase experienced by the degree of overload in the facilities depending on the penetration of distributed generation in the distribution network. The X axis shows what has been called probability of overload, which is defined as the number of hours in which there is overload as a percentage of total hours per year. The Y coordinate shows the degree of penetration of DG that is defined as the ratio between installed DG power and supplier capacity. The colour curves represent different demand scenarios for which a survey has been performed, between the base scenario and a 200% increase in demand. The chart shows that DG has shown to have the ability to delay investments and, in general, the increase in penetration of DG reduces the probability of overloads at the feed. However, if the increase in penetration of DG reaches excessive values, this behaviour may be reversed, which may require additional investments. This survey does not consider if the feeder is capable of supplying demand in the event of n-1 failures, which if it includes the distributor, or even in the event of failures that can cause a disconnect of generation connected to its feeder, incapacitating it to satisfy demand. And as already mentioned in previous sections, the solution does not involve an economic valuation between the savings of not investing vs. the cost of failing to meet quality levels in the event of cuts, due to not satisfying demand. It is also necessary to analyze the image and social repercussion these cuts may have on the distribution company. We must not forget the social function of a power company. • With regards to the delivery network, we shall analyze a real case that happened to the Madrid distribution network in 2004. There is a distribution zone that is powered by a 120MVA 220/45kV transformer. Net power demand that the transformer experienced during 2004 was:

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Figure 5.2.2.2 Annual net and load curve load of 220/45kV In the case of the chart on the left above, the X coordinate shows apparent demand power in MVA and the Y coordinates show the different months of the year. The chart above on the right shows the load duration curve. The chart shows that for the winter peak the transformer is at rated power (120MVA). The problem of this situation is that as part of the demand experienced by said transformer there is a cogenerator that is netting part of demand supplied by the transformer, which is being unloaded. The following shows the production of said generator during 2004 and its load duration curve:

Figure 5.2.2.3 Annual and load curve generator production chart During winter peak of the 220/45kV transformer, the generator was producing 24 MVA. Transformer demand without generation is displayed below:

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Figure 5.2.2.4 Gross annual net and load curve load of 220/45kV transformer This is a typical situation experienced by distribution, and as can be seen, in the event of a transformer failure of lack of generation, it could have flows of 140 MVA, which represents a 16% overload. Therefore, the distribution company is forced to plan for a second 220/45kV transformer in the area to correct a possible overload problem in the event of a generation failure. • Another case is the network of Castilla La Mancha, which has a 30MVA 132/45kV transformer that supports a demand in an area that includes a generator, similar to the aforementioned case in Madrid. The following chart shows the net demand experienced by the 132/45kV transformer during 2002 and its load duration curve:

Figure 5.2.2.5 Annual net load and load curve of 132/45kV transformer

Production of the generator during 2002 and its load duration curve:

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Figure 5.2.2.6 Annual and load curve generator production chart

Considering real demand (gross demand) at the transformer, without considering generation, the result would be:

Figure 5.2.2.7 Annual net and load curve load of 132/45kV

Once again, without generation, the transformer is above its rated power. Therefore a second 30MVA 132/45kV transformer was put into service in 2003 to relieve the overload of the first transformer. In conclusion, due to the existing regulatory framework, distribution companies are forced to plan not including distributed generation in its grid. A regulatory change could be made to encourage the presence of this kind of generation during zonal demand peaks. It could be made through a payment for guaranteeing power, encouraging availability of the power station and penalizing it in the event it is not available during zonal demand peaks. Another possibility would be to allow the distributor, as operator of the distribution network, to request said power stations to produce in the event of technical restrictions in the network in the same way as the transmission grid On this second possibility, there should be a market of technical

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restrictions for the distribution, where the distributor is responsible for its management.

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6. Impact of DG in grid business. Grid operation and exploitation

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6. Influence of DG in the operation and exploitation of the grid

6.1. Influence of DG in the operation and exploitation of the grid

The operation and exploitation of the grid defines optimum grid exploitation seeking the best compromise bearing in mind the following: • Overloads • Voltage levels • Minimization of losses • Continuity of supply and/or failures n-1 • Reposition times • Protections Because many of them have been reviewed or will be discussed in other sections, such as for example overloads in the investments section (5.2.2), losses (6.2) and voltage levels (6.4), this section will review the aspects of supply continuity, reposition times, protections and failures n-1 in detail. Many of them are related and therefore will show several different cases that encompass all of them In the distribution network operation, it is necessary to consider (as already mentioned) the differences between the delivery grid, the MV grid and the LV grid. This section will analyze the impact of DG on the delivery grid in greater detail together with some aspects of the MV grid. With regards to the LV grid, we will not show real cases that have been documented, as it is an unmonitored grid, although we will discuss the most relevant aspects.

6.1.1 Delivery grid

The blackout phenomenon, which is often associated to the transmission grid has always appeared in the distribution network. As transmission depends on the generation location with regards to consumption, the degree of meshing of the grid and reactive compensation elements, voltage drops in the distribution network are typically due to highly radial structures that cause major blackouts. Although, this kind of situations are not found under normal operations, it is relatively normal to find n-1 failures. This phenomenon has a very important effect on continuity of supply and/or product quality. We shall now analyze the blackout phenomenon in the event of n-1 failures, which could occur in a delivery grid in Segovia.

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I

T1 T2

T3T1

T1

T1 T2

T

1

∼

J

T1

T1

5

5

15

5 5

5 5

15MW

4MW

1.5MW

D

∼B

H

G

F

C

5

T2A

∼

Trafo 132/45

E

Red de 132kV

Trafo 132/45

Figure 6.1.1.1 Delivery grid in Segovia

In the chart above the red area represents the 45kV grid and the blue area the 132kV grid. Each box represents a substation and the outbound arrows represent the transformation to 15kV of 45/15kV transformers to cover the entire MV of each substation. A typical problem presented in this zone is defined by the failure of the 132/45kV transformer in substation E. In this case all the demand should be supplied from the 132/45kV transformer in substation A. This involves how power flows through the circuit A-B at 45kV; hence the voltage reaching B may drop below 45kV depending on the existing demand in the area. In this case, the role of generation connected to substation B is key. Because blackouts that occur if any of the generator protections trigger are too restrictive, the generator may also disconnect from the grid at the same time causing a collapse in voltages, which shall arise in the event of a trigger caused by overcurrent in the A-B circuit. If the generator remains connected to the grid, the flows through the A-B line drop and voltage levels remain at reasonable levels. The following is a diagram with P-V curves explaining the phenomenon:

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Pos fault situation with generation Voltages

Pre fault grid

Figure 6.1.1.2 P-V curve. Voltage collapse

As we will discuss under product quality, blackouts are both a problem for the transmission grid and distribution network (section 6.3.1). That is why it is very important for the protections of each cogenerator to be agreed with the distribution company in order to minimize this kind of impact on the grid. As will be discussed in section 6.3, the only applicable legislation dates back to 1985, which recommended immediate disconnect in the event of blackouts; this should be changed.

Demand (MW)

Voltage collapse

Red ante fallo del trafo 132/45kV de la subestación E

Pre-fault situation without generation 46.5kV

43V

Pos fault situation withou generation

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Another similar example can occur in the delivery grid in Madrid:

Cliente

T2

T2

T1

T1 T2

T1

25

25

15

15

15 15

Cliente

~ 22MW

E

B

D

F

A

Red de 132kV

C

Figure 6.1.1.3 Delivery grid in Madrid In the chart above the green area represents the 45kV delivery grid and the blue red area the 132kV grid. The boxes represent substations and the arrows are 45/15kV transformers. In this ring, the role played by the generator connected to substation D is fundamental. In the event of failure in the A-B circuit or A-F circuit, all demand is satisfied through A-F or A-B circuits respectively. Again the role played by the protections is fundamental because if the generator disconnects due to the failure of either circuit, the remaining circuit feeding the ring triggers by overcurrent as it is not capable of supporting the full load. Therefore, in this case it would not be a blackout as in the case of Segovia, but lack of capacity. If the generator remains connected, there would be no loss of supply to the demand on the right. This case again shows us the impact of DG on the continuity of supply to the distribution network. In conclusion, due to the existing regulatory framework, the distribution company is forced to condition its grid without having active elements in its grid such as DG. In the event of a blackout, a possible solution would involve enabling the distributor to control these stations in an environment of technical restrictions in the distribution network. Under this new framework, DG would receive a premium for providing this service and the distributor would save money fitting the grid to avoid what happens today.

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6.1.2 MV and LV grid

DG has less impact in the MV and LV operation with regards to continuity of supply and/or failures n-1, reposition times, protections and overloads. Due to radial nature of these grids, the disconnection of power from the header would imply the disconnect of the DG downstream, due to technical criteria (impossibility with all certainty for DG to support the load as there is insufficient generation and does have power-frequency control elements) and due to regulations (regulations does not allow these generators to work in isolated mode, and according to Order 1985, they should disconnect from the grid in the event of blackout). Reposition times are not affected because in this case, demand depends on the distribution network. The involvement of DG is not required to return MV or LV. With regards to overloads, there are no critical points that overload the LV or MV grid in the event of lack of generation, as the grid was designed to operate without this generation. However, at the growth rate of generation facilities connected to MV and LV grids, this situation could change. Other aspects such as losses, voltage profiles and isolated mode operation will be analyzed in greater detail in sections 6.2, 6.4 and 8.3 respectively.

6.2. Influence of DG in losses

1. Definitions In order to supply electricity from a generator to consumption points, it is necessary to go through a series of devices that comprise the grid. The energy generated at large size generator stations must first pass through the transmission grid and later through the distribution network before it reaches the end user. Passing of power through the various elements of a grid (wires, transformers or any other device) implies losses. Depending on the part of the electrical system where the losses occur, these can be classified in transmission losses or distribution losses. Losses are unavoidable in any electrical system. These losses can be classified in two categories: • Fixed losses (losses on idle): These losses do not depend on demand or power flow at the feeder. They are due to Foucault currents and hysteresis cycles caused by excitation currents present in transformers and electrical machines in general. This category also includes losses caused by the crown effect. The crown effect is due to ionization of air near the conductor, as its where the electric field has its highest values. If voltage variations are ignored, which is reasonable in the case of transmission and delivery grids, fixed losses can be considered constant at all times of the year. Hence they are called fixed losses.

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• Variable losses (losses on load): This kind of losses refers to losses caused by the Joule effect and are related to the currents in the grids. The magnitude of these losses is proportional to the square of current travelling through the grid, and therefore varies depending on demand. Losses can be seen as an additional necessary operating cost to move energy from its point of generation to where it is consumed. It would be desirable to minimize these losses as much as possible but this involves investments in the grid, which is comparable to the cost of losses themselves. Depending on how the cost of losses are distributed among the various agents of an electricity system, some agents may be interested in reducing this cost. Typically, losses in the transmission grid are between 1-2%, losses in the distribution network between 4-6% and MV and LV between 7-10%. 2. Standards and regulation The most important aspects with regards to handling losses are described in RD 1955/2000. Since 1998, Spain has what is called a wholesale market or electricity production market (pool). The pool is where generators go to sell electricity while the distributors, resellers and consumers exercising their conditions as qualified, go to purchase the necessary energy to satisfy demand. Qualified consumers can go directly to the pool or through a reseller. Graphically we can see which are the currency flows included in such market as well as the various participants included and the relation between them (J. Rivier, T. Gomez, V. Mendez, 2001).

Figure 6.2.1 Cash flow diagrams in the acquisition of energy from the Spanish pool

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The purchasing agents pay for the corresponding power in the pool with the best estimate of net demand they will have to satisfy. Net, because the distributor must estimate both demand of its grid and generation in it, which is not sold in the market. However, this subject shall be reviewed with greater detail in section 9. All purchases are made power station busbars, i.e.: power is purchased on the border boundaries of generators participating in the wholesale market. This is done in order to transfer power measured at the point of connection of the consumer to power station busbars. In the case of qualified consumers, both in medium and high voltage, directly or through a reseller, they are assigned a standard coefficient depending on the access fee they have engaged. The standard loss coefficients are defined by the public sector and published each year in Royal Decree that establishes the tariffs. Losses are paid in full by consumers and have no incentives at the generation location and consumption to minimize them. RD 1955/2000 in its fourth transitory provision states that “1. Temporarily, at least until January 1, 2002, losses in the transmission grid shall be applied to electricity consumers through the use of loss coefficients published each year in regulations. 2. The system operator, after six months of this Royal Decree coming into effect, regardless of any affection it may represent for settling with agents, shall calculate and publish the loss factors of each node and the hourly loss amount, using the methodology defined in chapter VI of Title II, after the coming into effect of this Royal Decree.” Calculations of loss factors (marginal losses) are currently calculated for all 400kV and 220kV nodes. However the cost assignment and/or payment responsibility to generation have not been put into practice. Under this scheme, distribution has a clear incentive to reduce losses as the standard losses of their grid are recognized during the purchase, however the distributor pays actual losses. There is a distortion in the assignment of losses in the transmission because distributors assign losses in the pool after deducting standard losses of qualified customers connected to the transmission grid. No one has incentives to reduce such losses and distributors are affected by something they cannot control (J. Rivier, T. Gomez, V. Mendez, 2001). The presence of generators under special regime connected to the distribution networks can initially generate a profit for distributors as losses avoided in the transmission grid. However, this generation could increase or reduce losses in the distribution network itself, hence the final result for the distributor could be positive or negative. 3. Impact of distributed generation on losses The impact that distributed generation may have on the distribution network from the losses perspective is highly varied. In general, the impact of DG on losses depends on several factors (Mendez Quezada, 2005):

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• The location of DG on the distribution network • Topology and structure of the grid • The degree of penetration of DG in the grid • The demand profile of the grid • The type of DG, as its production profile depends on its technology The aforementioned factors are described below: a) The location of DG in the distribution network and its topology These two factors are highly interrelated. The location of generation is very important from the losses perspectives as, the closer to the consumption locations, the greater is the reduction in losses. Again, as in previous sections, the effect on losses depends on if they are delivery grids or MV or LV grids. Because the first are generally meshed, it depends on the flow distribution in the mesh to calculate the impact of losses. In MV and LV grids, it seems obvious that the effect of losses is not the same if the generator is connected next to the feeder or closer to end users. b) Degree of penetration The degree of penetration is another very important factor. Approximating the degree of penetration with losses using mathematical formulas generates a U shaped curve. This means that connecting DG in the case of grids without generation implies a reduction in losses. However as production increases, there is a point where losses can increase due to excess generation. The latter occurs for example with wind farm generation where the flow has been inverted and is injected in the transmission grid, increasing losses in the distribution network. c) Profile of demand and production of generation The penetration of DG shows us U shaped curves in losses. However their shape depends on the type of DG production profile compared to the demand profile. Lower losses are associated to generation profiles that best adapt to demand profiles.

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Figure 6.2.1 U Curves. Losses in distribution networks depending on degree of penetration of DG The two most important characteristics of U shaped curves are what in the previous chart has been called “stretching” and “gap”. Stretching gives us an index of the degree of penetration in the grid before another increase in losses. The gap provides an idea of the reduction of losses caused by a technology in the grid it connects to. Impact analysis have been made with technologies such as cogeneration, photovoltaic, wind farm and generation with production in base (Mendez Quezada, 2005).

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The effect is displayed in the following chart:

Figure 6.2.2 U Curves. Losses in distribution networks depending on degree of penetration of DG by technology Where penetration has been called:

100feederat Power Engaged

PowerDG Installedn(%)Penetratio ⋅=

The chart above differentiates cogeneration as type 1 and type 2. Type 1 is when the production profile is similar to conventional demands, with peaks in the morning and afternoon, while type 2 has a production profile with night time peaks. If we analyze the gap by type of technology, we can see that generation with greatest reduction in losses is the one with constant production, followed by cogeneration, wind farm and photovoltaic.

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With regards to stretching, the technology with greatest growth potential without increasing losses for high production levels is cogeneration, followed by generation on base, wind farms and finally photovoltaic.

6.3. Influence of DG in service quality

In general terms, it can be stated that the transmission grid is the guarantor of stability and system safety while the distribution network is the guarantor of service quality perceived by customers. More than 90% of cuts suffered by customers or end users are due to the distribution network, which is logical, as these grids are less meshed than the transmission grid and the majority of customers are connected to them. The service quality, in the electricity context, is the combination of technical and commercial characteristics inherent to electricity supply, whose existence conditions the fulfilment of the contractual obligation and applicable regulatory requirements. Service quality encompasses commercial quality or customer service and the technical quality of supply. Commercial quality is basically the quality perceived by the customer with regards to the power company. Service quality in customer support is not related to any of the technical supply aspects, but to the relation between the distributor or reseller company and the customer. It is configured by the combination of information, advice, engagement, communication and claims activities. It is obvious that distributed generation has little influence in this kind of quality. Hence, this section will review the influence of distributed generation in the technical quality of supply. The quality of supply, in turn, involves the product quality and continuity of supply.

6.3.1 Product quality

1. Definitions The product received by customers is the voltage wave. Therefore, product quality consists of all perturbations that affect the most fundamental characteristics of the voltage wave: • Frequency • Amplitude • Wave shape • Symmetry of the three-phase system The most characteristic phenomenon or perturbations included in product quality are: variations in frequency, harmonics, rapid and slow voltage

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variations (flicker), voltage fluctuations, blackouts and brief interruptions, impulses and transitory overcurrents as well as unbalances and asymmetries. Graphically they can be summarized into the following schemes (T. Gomez, 2004-5b) and (J.M. López Sánchez, 2002):

Perturbations corresponding to changes of characteristics Characteristics of voltage wave Name Description Frequency Frequency

variation Variations of frequency with regards to rated 50Hz

Slow voltage variations

Service voltage variations with regards rated voltage, during more than 10 seconds

Rapid voltage variations

Variations in effective voltage values (up to 10%) between two contiguous levels, maintaining each one of them during more than 30 ms They appear, both sporadically and repetitively and regularly (rectangular towers of equal amplitude) or not A specific example of repetitive variations is caused by the flicker effect

Voltage gaps ad brief interruptions

Sudden drops (between 10% and 100%) of the effective voltage level, followed by a re-establishing after a period of time ranging from 10 ms to several seconds

Amplitude

Voltage impulses Sudden variations of the instant voltage level, in values that can reach several times rated voltage, with durations between several microseconds and a few milliseconds

Form of wave Harmonic distortion

Deformation of sine wave, which can be broken down into sine waves, one of then at 50Hz (fundamental component) and other harmonic frequencies (multiples of 50Hz)

Symmetry of three-phase system

Unbalances and asymmetries

Module variations in phases and/or their relative phase lags, with regards to the three-phase system

Figure 6.3.1.2 Perturbations corresponding to changes in characteristics of the voltage wave 2. Regulation and standards Considering the Spanish regulation, the product quality is defined in RD 1955/2000 title VI, chapter 2, section 102 (Ministry of Economy, 2000c). Said section specifies that any regulations regarding product quality shall follow the criteria defined in the UNE-EN 50160 standard (UNE-EN 50160, 1994), which shall be adapted to the Spanish sector as discussed in (UNESA, 1996). Said European UNE-EN 50160 standard standardizes the electricity product throughout the European Union. The standard does not define electromagnetic compatibility levels, but it describes how the electricity should be supplied to each customer or the maximum perturbation levels that can exist at each point.

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With regards to voltage gaps, the latest legislation that covers this aspect is the government order of September 5, 1985, which establishes administrative and technical standards for operations and connections to electricity networks of hydroelectric power stations of up to 5,000 kVA and electric autogeneration stations (Ministry of Industry and Energy, 1985). Clause 2.1.4 states that “in the case of hydroelectric power stations of up to 5MVA and autogeneration stations, in the event of breaking the automatic circuit breaker of the power company corresponding to the line that connects to a station, it shall not maintain voltage in the company’s grid. And if it were capable of maintaining it due to being equipped with synchronous generators, or self-excited asynchronous, the owner shall implement a remote disconnect system from the station to the substation or transformer of the company that connects to the plant. In area grids with automatic reconnect, suitable devices shall be established so that the station does not connect again until the reconnect is secured”. RD 1366/2000, section 8, paragraph 2 (Ministry of Economy, 2000b) regarding photovoltaic facilities of up to 100kVA connected to the LV grid states: “in the event that the distribution line is disconnected from the grid, either due to maintenance works required by the distribution company or due to triggering some protection, the photovoltaic facilities shall not disconnect from the distribution line”. As we will discuss in the following sector, the biggest difficulty is associated to the blackout problem. The system operator has provided a draft that will be the operating procedure 12.3 and that will cover the most relevant aspects of wind farm generation. However, it has still not been approved. The most important aspect proposed in the procedure is: “Wind farm parks shall support three-phase, two-phase or single-phase blackouts without disconnecting at the connection point to the grid under the following characteristics and duration”:

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Figure 6.3.1.3 Voltage gap required in wind farm facilities This requirement shall be necessary for charging the premium defined in RD 436/2004. 3. Impact of distributed generation on product quality The most important impact of distributed generation is the result of blackouts in the grid. In the rest of impacts: harmonics, unbalances, etc. there are no major inconveniences that have not introduced other types of grid connections such as industrial loads, transmission system (Metro), rectifiers, etc.. With regards to slow voltage fluctuations, the most important impacts shall be discussed in section 6.4. The existing regulations allow for the automatic disconnect of distributed generation. This fact can be especially serious in the event of an abundance of generation on a local scale, as any incident that causes a blackout can trigger power bags to disconnect. Because of this phenomenon, the system operator may encounter situations in which an incident causes the disconnect of a power greater than secondary reserves, incurring in frequency instability and therefore trigger a blackout. This is the case of wind farm generation. The system operator, because of these and other connotations, which shall be reviewed in 8.1, have defined the maximum production that shall be available to maintain the safety and reliability of the electricity supply in Spain at 13,000MW. The figure of 13,000MW has been calculated for system peak and with the premise that wind farms must support blackouts timing the trigger of

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minimum voltage relays above 500ms. In valley situations, the limit shall be 3000MW timed at more than 500ms and 5000MW timed at more than 1s. Because the objective of this thesis is not to develop the technical impact of a short-circuit at a generation plant, the following is a summary of the effects of a blackout on wind farm generation in order to size the problem. In Spain the installed wind farms are:

• Asynchronous generators connected directly to the grid:

Figure 6.3.1.4 Asynchronous generator

• Double feed asynchronous generator set

Figure 6.3.1.5 Double feed asynchronous generator set

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• Synchronous generator with converter in the stator

Figure 6.3.1.6 Asynchronous generator set with converter in stator

The following charts show the response in time when an asynchronous machine suffers a blackout at its busbars of 400, 1200 and 1400 milliseconds, which is the most unfavourable situation (Luis Rouco, 2005). The most harmful effects that can be produced are derived from the loss of stability due to an unbalance of electromechanical pairs at the rotor and overcurrents the machine may experience.

Figure 6.3.1.7 80% gaps with durations of 400, 1200 and 1300 ms The acceleration that a machine would experience when its electric brake torque is reduced can be measured through its slide (the sliding is shown as negative because it is an asynchronous machine operating in generator mode):

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Figure 6.3.1.8 Sliding of wind farm generator in 400, 1200 and 1400ms gaps In the case of blackouts longer than 1300ms, the machine looses stability as the slide increases continuously. The intensities in the direct and transverse legs are:

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Figure 6.3.1.9 Intensities of direct leg of wind farm generator before 400, 1200 and 1400ms gaps

Figure 6.3.1.10 Intensities of transverse leg of wind farm generator before 400, 1200 and 1400ms gaps

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The reactive component shows that there can be intensities three times the rated level, but are absorbed very quickly in time (around 100ms) in the event of 500ms gaps. In the event of gaps longer than 1s, it does generate very high values maintain in time as the disconnect of this kind of machinery in the event of blackouts should not be greater than 1 second. The blackouts in the charts above apply a defect at machine busbars. In the case of points further away, the voltage levels are not as small, and the blackout depth is much lower. In order to understand the size of blackouts at points that are not machine busbars, the following shows the effect of a blackout at the 400kV substation in Loeches, Madrid (Alberto Ceña, 2005):

Figure 6.3.1.11 Voltage drop after a three-phase failure in the 400kV substation of Loeches

The voltages were affected down to Andalusia. Certainly this is one of the most severe defects that can occur in the peninsula.

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This thesis will not provide an in-depth review of the effect of blackouts in synchronous machines, as this has been widely covered elsewhere (P. Kundur, 1994), (Antonio Gomez Exposito, 2002), (J. J. Grainger, W. D. Stevenson, 1994), (José Luis Sancha, 1995). A practical example was the incident of Magallon on August 1, 2005 (Red Electrica Española, 2005d). At 16:30 there was an increase in generation that triggered the 220/400kV evacuation transformer at Magallon:

6.3.1.12 Evolution of wind farm production delivered in Magallón

Figure 6.3.1.13 Evolution of 400/220kV transformer load in Magallon

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The triggering of the transformer caused a loss of power of 300MW. Because of the 0.8p.u blackout in the area of approximately 1 second, there was an additional market loss of 300MW from wind farms.

Figure 6.3.1.14 Voltage gap in the Magallon incident

Figure 6.3.1.15 Loss of wind farm production due to the incident

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6.3.2 Continuity of supply

Continuity of supply is what is called reliability of the distribution network. Long or permanent interruptions are included in this paragraph. In Spain, long interruptions are those lasting more than 3 minutes. Continuity of supply is regulated in RD 1955/2000 in chapter II (Ministry of Economy, 2000c) and order ECO 797/2002 (Ministry of Economy, 2002c). The impact of DG on the continuity of supply is due to two main factors: the possibility of DG operating in isolation mode improving continuity of supply to consumers and on the other, the repercussion of DG during operation in the event of n-1 failures. The operation in isolation mode shall be reviewed in greater detail section 8.3. The repercussion on operations of continuity of supply has been analyzed in 6.1.

6.4. Influence of DG in the voltage profiles

This section must clearly distinguish the aforementioned areas as voltages behave differently in the delivery network at MV and LV. The resistance effect of lines is negligible in transmission grids and 132kV distribution networks compared to the inductive. In addition, considering that voltages operate relatively close to rated power, and the angular differences between two nodes are not major:

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Figure 6.4.1 P-Angle and Q-V relation for a generator set connected to an infinite network

Reactive power depends on the difference between voltage modules and active power on angular differences. However, this is no longer true after voltage levels below 66kV in the case of distribution networks and the resistance levels of power lines are no longer negligible compared to reactances. On the other hand, the networks stop being nodes of infinite power, which means voltages do not need to be close to rated levels. This implies that, although the voltage-reactive dependence or angular-active differences continues to be important, there are situations in which the voltage-active power relation or angular-reactive differences must be considered.

6.4.1 Delivery grid

In general terms, the voltage levels on the delivery grid are healthy and fall within the +7% and +10% limits required by product quality (see section 6.3.1). The health of voltages in the delivery grid does not depend on the reactive generated by DG, as is the case in the transmission grid with generation under the ordinary regime. Voltage levels in the delivery grid depend on its connection to the transmission grid and in local specific cases, on certain injections of active power from distributed generation as well as reactive compensation elements there may be in the delivery grid. Reactive power generated by DG is not especially significant for voltage control. They can help to compensate power factors but the distributor has no control over them. The injection of reactive provided by each distributed generator shall depend on the economic incentive to be obtained based on RD 436/2004. In addition, the potential of reactive that these generation facilities can produce is not significant compared to the active power they generate. Therefore their repercussion on voltage levels depends more on the active power they net and, therefore, obtain better voltage levels as a result of less flows in the lines.

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In order to better understand the above, we will review two actual examples of the delivery grid in Segovia and Leon. The delivery grid in Segovia in the area we are going to analyze has the following orthogonal layout:

I

T1 T2

T3T1

T1

T1 T2

T

1

∼

J

T1

T1

5

5

15

5 5

5 5

15MW

4MW

1.5MW

D

∼B

H

G

F

C

5

T2A

∼

Trafo 132/45

E

Red de 132kV

Trafo 132/45

Figure 6.4.1.1 Delivery grid in Segovia In the chart above the red area represents the 45kV grid and the blue area the 132kV grid. Each box represents a substation and the outbound arrows represent the transformation to 15kV by 45/15kV transformers. The problem of the network from the voltage point of view is that the 132kV network must cover major distances to satisfy demand. In 2005, the generator in substation B was connected to the network, which resulted in voltage improvements as it reduced voltage drops in the area. Below is a chart for a random day which shows the generation of active and reactive injected at substation B and its voltage profile:

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Figure 6.4.1.2 Generation of P and Q of cogenerator connected to substation B

Figure 6.4.1.3 Voltage profile in substation B

101


The charts describe how the voltage profile clearly accompanies the generator’s power injection. This has advantages and inconveniences. The advantages occur in networks whose generation results in better voltage levels. The disadvantage is that the distributor does not control voltage at that node and possibly also the nodes nearby; therefore if there are customers connected at those voltage levels, there may be problems in the quality of the delivered product. On the other hand, this variation must be assumed at substation B by the 45/15kV transformers, as their connection exchanges are changing continuously to maintain uniform 15kV voltage levels, which generates greater wear on transformers and therefore greater maintenance costs. Another similar example can occur in the delivery grid in Leon. Analyzing the orthogonal diagram:

Cliente

Cliente

6 MVA

6 MVA

T1

T1T1

T1

T1

T1

T2

T2

T2

T4T2

∼

15

15

15

15

15

5

5 5

5

Cliente

5

ClienteCliente

Cliente

5

∼ 7.4 MVA

T1

∼

JB

G

C

D

I

E

H

A

Red de 132kV

F

Trafo 132/45 Trafo 132/45

Figure 6.4.1.4 Delivery grid in Leon The grey colour represents the 45kV network and blue is the 132kV network. Each box represents a substation and the outbound arrows represent the 45/15kV transformers. In this case, we analyze the impact of the cogenerator connected substation D when it came into service in 2003. Once again, we provide the active and reactive power injected at the node and the voltage profile at node D:

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Figure 6.4.1.5 Generation of P and Q of generator set connected to substation D

103


Figure 6.4.1.6 Voltage profile of substation D It once again shows the influence of the injected power on the node with the voltage profile. However the chart shows have the voltage profile varies at 22 hours while generation does not change. This is because distribution network voltages depend on injections from voltage grids upstream, fundamentally. If you look at the voltage profiles of substation D and compare them with the substation F, you will see that voltage drops at 22 hours because the substation also suffered a voltage drop.

Figure 6.4.1.7 Voltage profiles of substations F and D

Therefore it is very important to see the role played by generators connected to the distribution network in terms of voltage levels, but it is necessary to consider that the health of voltages in the area do not only depend on it but also on connections with higher voltage networks. In conclusion, as already mentioned in previous sections, the distributor should have control on these important generation facilities connected to the distribution network just like the system operator has on major generation stations.

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Hence it would be necessary to create a process of resolving technical restrictions for the distribution network and the generator should receive a premium for providing this service. Today the distributor does not have control of DG but it must fulfil a series of quality and continuity requirements, as it is obliged to invest more than necessary to accommodate the networks to any situation on the network.

6.4.2 MV and LV grid

In MV and LV, the network structure is completely different as they are radial networks and not meshed or semi-mesh, as in the case of the delivery. In the case of MV, line voltage is determined by MV busbar voltage. This voltage is controlled by the last transformer that adjusts on load (220/15/15kV, 220/20/20kV, 132/15kV, 132/20kV, 66/20kV, 66/15kV, 45/15kV etc.), which will exist between the end user and the grid. From here the voltage drops in linear fashion to the TCs where they are MV/LV transformers that adjust on idle (typically they have 5 connections), which, depending on their distance to the header of the MV line, will have a connection to increase or maintain LV voltage level. In the case of very long MV lines regulators are sometimes installed that sometimes raise voltage in half the line. In the case of LV, the network depends on a transformer with adjustment on idle, as already discussed, which marks a voltage that will also drop in linear fashion depending on distance to the end user.

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Graphically the MV and LV voltage profile:

Cliente Cliente

CT

Figure 6.4.2.1 Voltage profile in MV grids The impact of DG on this kind of networks depends on their degree of penetration in the grid and the type of generation, as each type shall present a different production profile. In these cases, reactive practically has no relevance (in general) and active power produced would increase voltage levels at the expense of reducing voltage drops due to lower power flows. The fact that DG could supply or consume reactive energy depends on the technology of the generator (synchronous, asynchronous or investors) and economic signals that encourage it in one or other direction (supply or consumption of reactive). Previously, distributors required DG to operate at a power factor close to the unit (which shall not supply or consume reactive energy) although with RD 436/2004 each generator decides, due to the economic incentive proposed in section 3.2. However, the biggest problem is not in reactive but in active they produce, which noticeably modifies the voltage profiles. This again puts the distribution company in a delicate situation as there are MV and LV customers that receive voltage not 100% controlled by the distributor, but is 100% responsible for it. A possible solution for MV would be to provide TCs with adjustments on load in order to maintain LV voltage levels. However this would increase

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the maintenance costs of TCs and the change of all TC transformers would have a disproportionate cost. Therefore the ideal solution would be to change the regulatory framework, where generators only try to comply with RD436/2004, not considering voltage levels. Therefore, it would only be necessary to enable voltage control devices at the node they are connected to. The distributor would be responsible for facilitating consigned voltage that should be maintained by generators in the network.

6.5. Influence of DG in the safety of maintenance personnel

Each year, in order to maximize useful life, reliability and profitability of investments made at facilities must include maintenance tasks. The most important network operations that allow maintenance works in the distribution network are discharges and special regimes. Discharges are performed for works that require absence of voltage in order to perform them. Special regimes are planned for those works that can be performed with power on the network. The repercussion of DG on personnel safety that work on a line or a substation is because in the past, according to the traditional structure of networks, generation was connected to very high voltage grids. Because of this disconnect of power from the header of an MV line gave many guarantees of non existence of voltage in the entire MV line. The same reasoning can be applied to different voltage levels. Distributor companies have a basic safety rule, which they call the five golden rules. These rules were created to maximize safety at work with regards to any kind of discharge. • Rule 1: break all voltage sources with a visible and effective cut (visible or signalled by safe means) using circuit breakers and isolators that ensure it is impossible to close them. • Rule 2: interlock or block, if possible, of breaking and signalling devices. • Rule 3: recognition of absence of voltage. • Rule 4: earthing and short-circuit of all possible voltage sources. • Rule 5: Place suitable safety signals delimiting the work area.

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Graphically:

Figure 6.5.1 Five golden rules The critical aspect is between rule 2 and 4, as it is very important to check the absence of voltage, as now it is possible to have return voltage downstream. Today it is relatively normal to open the circuit breaker at the header of a 15kV line, when checking for the absence of voltage and detect return voltage if any generators have remained in isolation mode. Similarly when low voltage output is opened at a TC, it is frequent to find return voltage in LV cables because generation is connected. In order to avoid this kind of situations, a possible alternative is the possibility to remotely trigger those generator facilities connected to the network or, when in the case of photovoltaic facilities connected to LV grid, when generator facilities have network disconnect mechanisms that detect the absence of voltage.

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7. Influence of DG in short-circuit powers

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7. Influence of DG in short-circuit powers

The short-circuit power is defined as the maximum value of power that the network can supply to a facility during a failure. It is expressed in MVA or kVA for a specific operation voltage:

Figure 7.1 Single wire diagram of a short-circuit

CCCC IU3S ⋅⋅= Where: Scc: three-phase short-circuit power at the node of the failure U: Voltage consisting of rated system voltage level where the failure was produced Icc: Three-phase short-circuit current once the steady-state regime has been established (symmetric component). Short-circuit power is in some way a measure of the efforts (thermal and electrodynamics) caused by the short-circuit. Of the aforementioned parameters, the only one that has real meaning is short-circuit current as this is the value to be broken by the circuit breaker on the failure. During the initial instants, the voltage of the failure will clearly not be rated level, but much lower, which shall depend on grid strength. Once the failure has been cleared, the rated voltage will appear between the circuit breaker busbars. Short-circuit power depends directly on grid configuration and impedances of components: lines, cables, transformers, motors... and any component that passes the short-circuit current. Short-circuit power in an electricity grid is an index of robustness, interconnectivity and capacity of transmission grid. Greater short-circuit power in a grid indicate greater number of interconnections (mesh), greater capacity of transmission capacity and greater robustness. Although short-circuit power gives us the sizing of circuit breakers, it also reports on voltage drop that may be experienced by a grid in the event of a connection of a facility or the equivalent impedance experienced by said facility when it connects to this network.

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The possible short-circuit sources of a power grid are: • Public distribution supply grids. • Generation. • Return of power from rotating machines (motors, ...) or from MV/MV or

MV/LV transformer to networks (whenever there is a source on the other side.

Another direct application is the location good connection point for generation, such as the transitory stability criteria of generators. The greater the short-circuit power at the nodes where they connect to generation, the greater transitory stability is available. As a general rule, a generator connected to a node shall continue in synchronism in the event of failure if the short-circuit power of the node is three times greater than the installed generator power. It is necessary to distinguish two clearly differentiated cases when talking of short-circuit powers.

7.1. Transmission

The provisions of the transmission grid are developed in resolution February 11, 2005, of the General Secretary of Energy, which approves a series of technical and instrumental procedures necessary to perform an appropriate technical management of the Electricity System. The short-circuit criteria have been detailed in the system operator operating procedures 12.1, 12.2 and 13.3 (Red Electrica Española, 2005). Points have been detected in the Iberian peninsula where there is too much generation connected to the node, which has caused possible transitory instability situations. This is the case of Escombreras, where under certain situations the system operator is forced to de-mesh in order to reduce the contribution of installed generation to short-circuit. This situation is not very usual in the peninsula, where the system operator is not very used to have to de-mesh the grid because circuit breakers do not have sufficient breaking power or because they may encounter unstable situations in the event of n-1 failures. However this kind of situations are very normal in countries such as the United Kingdom where National Grid (operator and transmission company in the United Kingdom) is forced to de-mesh between 10-15 substations every day, reaching situations in which some substations are separated into three busbars.

7.2. Distribution

This section will cover it in greater detail as distribution generation is immersed in such network.

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As in the event of transmission, the conditions are reasonably detailed, normalized and transparent, the truth is that the connection of generation facilities to the distribution network is not clearly defined. There is regulation that covers this subject but without covering all types of generator facilities and at all voltage levels that may connect. In general lines, the regulations specify that the facilities connected to the network must fulfil a series of specifications indicated by the distribution company, such as for example short-circuit power. RD 1663/2000, chapter II, clause 4 (Ministry of Economy, 2000b) states that in one month after receiving the request for connection, the distribution company shall specify the short-circuit power expected at the connection point from the generation facilities. However, this condition is only for photovoltaic facilities. RD 1955/2000, chapter 2, section 63 (Ministry of Economy, 2000c) states that “agents of the distribution network shall provide the system operator and manager of the transmission grid any requests for access to the distribution network of new facilities that may constitute a significant increase of energy flows at connection nodes of the distribution network or that may affect safety and quality of service. In this respect, the affection shall be significant when any of the following conditions concur: • Generators or groupings of these with installed power greater than 50 MW. • Generators and consumers whose requested installed power is greater than 5% and 10% of short-circuit power at the connection node to the distribution network under peak and valley demand situations, respectively. Section 15 of the LV electrotechnical regulation states that “the supplier companies shall provide the maximum foreseeable values of power or short-circuit currents of their distribution networks, in order for the draftsman to consider this figure in his calculations”. On the other hand, according to ITC-BT-40 (Ministry of Science and Technology, 2002) chapter 4, paragraph 3 states that the maximum power of stations connected to a public distribution network shall be conditioned by its characteristics: service voltage, short-circuit power, line transmission capacity, power consumed in the low voltage network, etc. 1. Maximum power of stations connected at low voltage Generally, the interconnection of generator stations to the 3x400/230 V low voltage network shall be admissible when the sum of rated power of generators does not exceed 100 kVA, or half the output capacity of the transformation centre corresponding to the Public Distribution network that the station connects to.

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Generally, the interconnection of generator stations to the 3x400/230 V low voltage network shall be admissible when the sum of rated power of generators does not exceed 100 kVA, or half the output capacity of the transformation centre corresponding to the Public Distribution network that the station connects to. In these cases, the entire installation shall be prepared for a future operation at 3x400/230 V. At wind farms, and in order to avoid network fluctuations, the power of generators shall not be greater than 5% of short-circuit power at the point of connection to the Public Distribution Network. 2. Specific conditions for the start-up and coupling of the generator facility to the Public Distribution Network. 1. Asynchronous generators. Voltage drops that may occur during the connection of generators shall not be greater than 3% of the network rated voltage. In the case of wind farms, the connection frequency shall be not more than 3 per minute, the limit being a 2% drop of rated voltage for 1 second. Suitable devices shall be used in order to limit intensity at the time of connection and voltage drops to the aforementioned values. The connection of an asynchronous generator to the grid shall not be performed until, triggered by the turbine or motor, they have reached between 90 or 100% of synchronism speed. 2. Synchronous generators The use of synchronous generators in facilities that must be connected to Public Distribution Networks, shall be agreed with the electricity distribution company, covering the need of independent operation in the grid and its operating conditions. The station shall have synchronization equipment, either automatic or manual. This unit may not be required if the connection can be performed as an asynchronous generator. In this case, the start-up characteristics shall fulfil the provisions for this kind of generators. The connection of stations to the public distribution network shall be made when the differences between electricity values of the generator and grid during the synchronization operation are not greater than: • Difference of voltages ±8% • Difference of frequency ±0.1 Hz • Phase difference ±10° The points without a synchronization device and when it is possible to put in parallel, between generation and the public distribution network, shall have interlocking that prevents putting them in parallel.

7.3. Conclusions

The most fundamental aspect is that short-circuit power is not a major problem in distribution networks due to distributed generation. It could be the case that the connection of DG to the network with significant increases in short-circuit power,

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but it is an easily resolved technical problem using switchgear of greater breaking power. There have been no cases that have required demeshing the grid due to high short-circuit powers as a consequence of new generation; and only certain situations which required changing switchgear. We already mentioned that the transmission grid is already seeing situations with very high short-circuit power levels or with situations breaching n-1. These situations shall be increasingly repetitive, as is the case in European countries. However this type of situations are caused by generation under normal regime and not from DG. However, we would like to highlight this problem as a critical point with regards to short-circuit powers. With regards to the existing regulations, the standard only provides short-circuit power values for the case of photovoltaic generation connected to the LV network (installed power not greater than 5% of short-circuit power at the point of connection to the network). Similarly, in the case of generation of installed power greater than 50MW or installed powers greater than 5-10% of the short-circuit power, the system operator must review such connection. In general, it can be stated that the distributor shall define the short-circuit power level of new generation facilities connecting to its network and the installer shall design the installation considering such condition in the design.

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8. Influence of DG in ancillary services

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8. Influence of DG in ancillary services

Ancillary services are those that are associated to generation, transmission and distribution, required to guarantee the safety and quality of supply (D. Soler, 2004). The most typical ancillary services are: • Frequency control - power • Voltage control - reactive • Autonomous start-up (black start) and island separation In order to not make this document very long, we shall define the most fundamental aspects of each one of them, in order to tackle the problems of distributed generation in each case.

8.1. Power Frequency Control

1. Definitions The purpose of this service is to maintain balance between demand and generation at all times in a specific system, offsetting unbalances that may arise as a result of contingencies or unexpected variations of demand. The balance between generation and demand is basic for system stability and reliability, given that deviations of one with regards to the other can cause a frequency variation with regards to its rating. The frequency of an electricity system must remain very close to its rated value, bearing in mind things such as quality of supply, machine safety and other system components. This service is usually implemented through a series of hierarchical controls that act in different time scales. Hence, it is worth distinguishing between:

• Primary power-frequency regulation: the control in charge of reacting first to an unbalance between generation and demand. Its mission is to limit the deviation between frequency of the system and rated frequency. It is an automatic control that is local in nature. Its response time is in seconds (3, 4s).

• Secondary power-frequency regulation: reacts after the primary and

is responsible for substituting primary power and recovering system frequency. Its response time is in minutes. Generally this regulation is centralized and automatic.

• Tertiary regulation: it is the last in acting. It is in charge of replacing

secondary and is manual. Its time to react is within tens of minutes.

Graphically:

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Figure 8.1.1 Frequency response in a generation failure

In Spain, the implementation of secondary regulation is somewhat particular, as it is performed in a distributed way. There are a series of control areas that receive the power set point to supply in one direction or the other from the master regulator. It is the control areas the distribute this set point to its generation units, which are responsible for fulfilling the requirement established for the area by the master regulator. The areas and master regulator have an automatic generation control system (AGC). This regulation system is called “Regulacion Compartida Peninsular” (RCP, or Peninsular Shared Regulation). The set point provided by the master regulator is updated every 4 seconds in the secondary regulation. The secondary regulation has been established as an open market service: a market has been created where the essential product of this service purchased and sold, is power reserves made available to the system operator by areas with a view to face any of the aforementioned generation-demand unbalances. The system operator determines the necessary reserve level (both to increase generated power and to reduce it). The regulation areas make offers (reserve and price) broken down into units. These reserve offers are matched by economic criteria, in the same way as in other markets, until achieving the required reserve level.

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2. Regulations The most important documents that define the frequency – power control limits are defined in the system operator operations procedure 1.5 (Red Electrica Española, 1998) and in the guide on wave quality in electricity networks (UNESA, 1996). Rated frequency of the Spanish system is 50Hz. Normal variations in frequency are those between 49.85 and 50.15Hz. OP 1.5 follows the recommendations of UCTE to establish the reserve between frequency – power regulation. In the case of primary reserve with frequency deviations below 100mHz, the power unbalance of the system shall be corrected within 15 seconds, while in the case of frequency deviations of up to 200mHz, the response time shall vary in linear fashion between 15 and 30 seconds. The primary regulation of generator sets shall allow establishing stability at the regulator in order to vary its load by 1.5% of rated power. The lack of sensitivity of group regulators shall be less than +10mHz and dead band voluntarily null. For the secondary reserve, the system operator calculates that amount to supply depending on the statistical indecisiveness in the foreseeable temporary evolution of demand and the probability of failure, according to the power and generator units connected. According to the UCTE, secondary reserve shall be around:

maxP6 ⋅ where Pmax is the maximum demand power during the interval in which secondary reserve shall be assigned. 3. Effects of distributed generation in the frequency – power

regulation Until today, the tendency was to believe that frequency stability of electric power systems depended mainly on the generation connected to the transmission grid. This concept today is very much questioned because production of distributed generation is reaching levels that are not negligible when compared to ordinary generation. We shall now analyze two situations that affect the frequency – power control. On one hand, it analyzes deviations such as wind farm generation and on the other, we shall analyze a specific example to demonstrate the possible influence of distributed generation in emergency situations or possible frequency events.

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Wind farm generation: The most important problem faced by frequency regulation in the peninsular system is caused by wind farms, due to the volatility of their generation. Although not all wind farms could be included in the distributed generation concept as it is often connected to the transmission grid, it is true that most of the wind farm power is connected to the distribution network. Wind farm generation affects frequency – power control in two different ways. On one hand, secondary regulation due to the volatility of its production and on the other, the global combination of primary – secondary – tertiary as there is a possibility of mass disconnect in the event of some kind of general contingency. With regards to the volatility of its production, the following is the demand in the Spanish power system and wind farm production:

Figure 8.1.2 Demand profile on the peninsula. 8-12-2005

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Figure 8.1.3 Wind farm production profile on the peninsula. 8-12-2005 The charts were taken on December 8, 2005, observing two basic aspects. On one hand, the wind farm production profile does not need to adapt to the demand profile and on the other, the variability of its production. These two aspects affect frequency control as the system operator must provide reserves to increase and reduce in order to adapt production to demand fluctuations and wind farm production. Another significant day was March 1, 2005. On this day, the 6 hour uninterrupted supply was applied due to the cold weather, the unavailability of thermal power plants, lack of wind, low gas reserves due to bad weather and low hydraulic reserves.

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Figure 8.1.4 Demand profile on the peninsula. 1-03-2005

Figure 8.1.5 Wind farm production profile on the peninsula. 1-03-2005 Again, a production of 4000MW from wind farms dropped to 500MW, resulting in the period of least production and of greatest demand. In this case, the plants were unable to assume the gap and the uninterruptibility was applied.

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Blackout in Italy, September 28, 2003: Another very significant case for the Spanish power system was the blackout in Italy on September 28, 2003. As described below, distributed generation in another similar situation would have been disastrous for the system. In order to understand the blackout, it is first necessary to provide a short description of the Italian power system. National peak demand in Italy was around 52GW. It presents a total installed power of 72GW, but due to strong hydraulic dependence, the available capacity sometimes drops to 49GW. This fact, combined with that Italy presents some of the most expensive electricity in Europe (due to its high thermal production), involves considerable imports from Europe, which represent 15-20% of the country’s demand. Of the installed generation 27% is hydraulic and 73% comes from thermal production, hence the reason for its high prices. Therefore, Italy is a country with strong dependence on Europe for its electricity. From the point of view of the GRTN (Italian electricity operator), the sequence of the incident was as follows: • 3:01: The 400kV Metten Lavorgo line triggered. This line connects Italy with Switzerland. Italy experiences a variation in power, but all within normal operation levels. • 3:11: ETRANS (system operator of the southeast of Italy) asked Italy for a reduction of imported power to Italy. GRTN increased 200MW, resulting in a transferred power of 6400MW; within the plans. The reports from ETRANS states that this did not occur and the Italians failed to comply with the exchange programs by 500MW above the agreed levels. According to GRTN, the Swiss did not report on the incident, and therefore did not take additional safety precautions. • 3:25: The 380kV Sils – Soazza line triggered for reasons unknown to GRTN. ETRANS stated that this fault in the line in its country was due to the failure by the Italians to fulfil the import programs, by excess in the Swiss case, and defect with the French. ETRANS stated these non fulfilments, combined with the initial failure, generated an excess in transmission of power from north to south, generating considerable overload in its circuits. Hence the overload of the Altberville - Rondissone double circuit, which connects France with Italy. It is unknown what happened to the phase lag transformers connected to these lines to avoid overloads.

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After that, there were overloads in connection lines to Italy as these triggered. • 3:25 – 3:28: During this interval and in this order, the following lines triggered. Airolo – Metten of 220kV, Lienz – Soverzene of 200kV, Albertville – Rondissone of 400kV, Riddes – Avise/Valpelline of 220kV, Divacia – Redipuglia of 400kV, Praz – La Coche of 400kV, Robiei – Bavona of 220kV, Innertkirchen – Robiei of 220kV, Villarodin – Yeraus of 400kV, Soazza – Bulciago of 400kV. • 3:28: Italy was disconnected from Europe. It presented a shortage of 6400MW according to GRTN. Frequency dropped to 47.5 Hz after unloading and loosing some power plants. Subsequent losses disabled the automatic unloading of hunting and load. Italy suffered a blackout. Graphically these are the interconnections and order in which they disconnected:

Figure 8.1.6 Interconnection lines from Italy to Europe

The balance of power at the time of disconnect is provided below:

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Figure 8.1.7 Balance of power in Italy on disconnect

The following chart shows the evolution of the frequency at the time considering the various incidents as they occurred.

Figure 8.1.8 Evolution of frequencies in Italy before the Blackout

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After analyzing the reasons for the blackout we shall now analyze the repercussion of distributed generation to the Spanish power system. We already explained how frequency evolved in Italy when it separated from the UCTE. We shall now review the evolution of the frequency at UCTE. In Spain, just at the time of the blackout in Italy, the coverage of demand was as follows:

Table 8.1.1 Coverage of demand on blackout in Italy The detail of international exchanges:

Table 8.1.2 International exchanges in Spain at the time of the blackout in Italy At the time of the disconnect in Italy from the rest of the system, the frequency increased approximately 227 millhertz as shown in the following figure:

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Figure 8.1.9 Evolution of frequency in the UCTE after the Italian disconnect The deviation suffered by the scheduled exchange between Spain and Italy of 1200 MW is shown in the following chart:

Figure 8.1.10 Evolution of the deviation in the exchange with France after the Italian disconnect As can be seen, there was a deviation of approximately 1000 MW over the scheduled exchange. Breaking down the volume from primary regulation, we get:

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Figure 8.1.11 power balance in Spain after the Italian disconnect At the time of the disconnect, group 3 in Castellon dropped out. If we suppose a 2% variation of demand in the event of frequency changes and that the contribution of primary reserve produced an increase of losses, we get an imbalance of 380MW. Subsequent analyses have shown that the 380MW could be due to distributed generation. This means there is major amount of energy not monitored in real time, of which the system operator has no real control and which affected the primary reserve contribution. In this case, because the increase in frequency was due to surplus of energy, the triggering of group 3 in Castellon did not represent a problem as well as the disconnect of 380MW of distributed generation. Once again it is worth highlighting as we did in section 5.2.1 that the protections of each generator will vary depending on the type of installation and the technology, hence there will be generation that will disconnect with 0.2 hertz and others that will not. However, a question to consider is: What would have happened in Italy had been an exporting country and the UCTE had experienced a deficit of 6500MW? In this case, the disconnect of distributed generation would have had a fatal repercussion and very possibly have been talking of generalized blackouts in the peninsula. Due to the analysis performed we wanted to highlight this fact to demonstrate the distributed generation already has a relevant role in the frequency – power regulation and it is necessary to develop mechanism that integrate such generation in the frequency – power control.

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8.2. Voltage Control - Reactive

1. Definitions A very important ancillary service but not encouraged in Spain, both on a regulatory level and a technical level is voltage control. In Spain, the elements used for voltage control are: • Generators: overexcitement or under excitement • Condensers • Reactances or coils • Transformers with regulation points • The lines (sometimes in transmission due to excess of reactive) Other UCTE countries use another type of elements, but they are not the purpose of this thesis. However, not all these elements are those that are involved in the voltage – reactive binomial. The voltage levels of a system depend on many factors such as meshing and grid structure, the location of generation with regards to the consumption centres, the degree of compensation of the grid, the level of system demand, etc... If the voltage level depends in general on “reserves of reactive” available to a system, we could perform the following comparison:

Generadores

Condensadores

Líneas aéreas poco cargadas

Cables subterráneos

Tensión del sistema

Generadores

Reactancias

Líneas aéreas muy cargadas

Demanda

Transformadores

Tanque de potencia Reactiva

Control directo

No “controlables directamente”

Figure 8.2.1 Voltage – reactive – control diagram

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2. Regulations This ancillary service only applies to what has been called slow voltage fluctuations in 6.3.1 (which are those that last more than 10 seconds). Those fluctuations of less than 10 seconds are included in what is called voltage gaps, harmonic distortion, transitory overcurrents, etc. According to current regulations, there are two documents that basically affect this ancillary service. On one hand, the operating procedure 7.4 of the system operator approved by the ministry of industry and energy through resolution dated March 10, 2000 (Red Electrica Española, 2000). On the other hand, RD 436/2004, which provided the economic incentives for generation under special regime in its reactive production. The following describes the most important aspects of OP 7.4: • The service suppliers are: - All generator groups, regulated under ordinary regime, of net power equal to or greater than 30 MW and in direct connection through a specific evacuation line to nodes in the transmission grid. - Generators under the special regime shall be service suppliers when supported by the regulations established for this type of production. Hence, and as already mentioned in 3.2, the facilities will receive an incentive to achieve the following power factors:

Table 8.2.1 Incentive to the compensation of reactive as per RD 436/2004 - Distribution network managers.

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The role played by distributed generation is key in this aspect as the distributor plays a very delicate role. • Service provision: Due to eminently local nature of voltage control and the impossibility, in the current situation, of implementing a competitive market applicable to all areas, which could guarantee system safety, an ancillary service was established that requires a minimum mandatory service provision. Furthermore, there will be an optional provision of resources in addition to the mandatory part. This additional provision referred to by the manager of the distribution network, is currently not applicable. The minimum mandatory service provisions are: Generators: generators shall enjoy a mandatory minimum margin of reactive power both in generation and in absorption for the provision of the service, and shall modify their production and absorption of reactive power within such limits, so they collaborate in maintaining voltage at the power station busbars within the variation margins defined by the voltage set point and the admissible variation band around those established by the system operator. For generators, the mandatory minimum reactive power margin at power station busbars at the rated voltage of the transmission grid is defined by the net installed active power determined from the information obtained in the Administrative Register of Electricity Production Facilities and the following power factor values: a) Capacitive power factor equal to 0.989 (generation of reactive power equal to 15% of maximum net active power). b) Inductive power factor equal to 0.989 (absorption of reactive power equal to 15% of maximum net active power). The group shall be capable of providing this margin of generation/absorption of reactive for the entire variation range of active power, from the technical minimum and its maximum net active power. These requirements shall vary depending on the value of voltage at the corresponding node on the transmission grid, based on the linear function specified in the following chart:

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Figure 8.2.2 Voltage profile requirements of the 400kV network depending on reactive as per OP 7.4

Figure 8.2.3 Voltage profile requirements of the 220kV network depending on reactive as per OP 7.4 Distributors and consumers suppliers of the service: The following mandatory requirements applicable to consumers service suppliers, for each one of three time periods (peak, valley and flat):

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Figure 8.2.4 Classification of time periods: peak, valley and flat as per OP 7.4

a) Peak time period: The consumption of reactive power shall not exceed 33% of active power consumption (Power factor > 0.95 inductive).

Figure 8.2.5 Power factor requirements at transmission border points – distribution for peak hours as per OP 7.4 b) Valley time period: Reactive power shall not be delivered to the transmission grid (Cos° > 1 inductive).

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Figure 8.2.6 Power factor requirements at transmission border points – distribution for valley hours as per OP 7.4 c) Flat time period: The consumption of reactive power shall not exceed 33% of active power consumption, and reactive power shall not be delivered to the transmission grid (0.95 inductive < power factor < 1 inductive).

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Figure 8.2.7 Power factor requirements at transmission border points – distribution for flat hours as per OP 7.4 If we summarize all the above, the distributors are in a bottleneck as they must comply with the following requirements: • According to OP 7.4, power factors must be fulfilled depending on the time of day: peak, flat and valley. • According to RD 1955/2000 and more specifically the UNE-EN 50160 standard for distribution networks and MV (132, 66, 45, 33, 20 and 15kV), voltages must fall within +7% of rated voltage in the event of LV, voltages must be within +10% (it is allowed to exceed this margin if it does not exceed 5% of time in each week).

3. Effects of distributed generation in voltage – reactive control

ancillary services And the key question we must now ask is what is the role of distributed generation and what is its impact in the distribution network? Firstly, we should distinguish between the regulatory requirements and the priorities when it comes to operating a power system. Basically, the form of operation is clearly reflected in OP 7.4, where the system operator seeks to maintain voltage within reasonable levels. As

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second derived, it optimizes reactive demanding certain power factors at its border points. Logically, the most important indicator for the distributor, as it is a system operator, although of the distribution network, is voltage control on the network. In second place, if voltage levels are optimum, they will optimize reactive to maintain the power factors desired in OP 7.4. However, there are two very important considerations we must make. • On one hand, compliance with OP 7.4 and the UNE-EN 50160 standard

may be incompatible. For example, it is possible to comply with all voltage wave requirements and however not comply with the required power factors. According to this, the distributor could be forced to install condenser batteries in its network that could provide the required +7% of effective voltage or even involve resonance frequencies as the condenser is connected. Because the main objective for the proper operation of a system is voltage levels, the distributor would be obliged to not fulfil the desired power factor.

• On the other hand, the distributor has no total control on voltage and all its wave characteristics due to the variability of transmission voltage at border points, the customers connected to its network (which are potentially perturbating elements) and distributed generation connected to its network. If the power factor at the border point between the transmission grid and the distribution network is defined as:

( )22 QP

PSPαCos

+==

Where: P: Active power consumed at the transmission – distribution border point. Q: Reactive power consumed at the transmission – distribution border point. S: Power apparently consumed at the transmission – distribution border point. However, we should highlight that both active power and reactive are net at the border point. Hence, we could break down the formula and state:

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( )( ) ( )2generadademanda

2generadademanda

generadademanda

QQPP

PPαCos

−+−

−=

The formula clearly shows that the power factor of the distributor depends on active power production by the DG (depending on its production process and the economic incentive) and reactive power (the economic incentive of RD 436/2004).

In summary, the impact of distributed generation on the voltage – reactive control ancillary service is very important as the active and reactive power flowing through lines are affected as they have facilities injecting into the grid. This modifies voltage profiles of the grid with the various connotations analyzed for the various voltage levels. This can make the regulatory technical requirements demanded from the distributor incompatible or make the distributor invest and support additional expenses. Furthermore, regardless of the presence of distributed generation, it has been shown that the regulations to be fulfilled by the distributor with regards to voltage control and reactive power can generate contradictory and irresolvable problems as they have to breach a standard in order to comply with another.

8.3. Autonomous start-up and island operation

One of the fundamental aspects of ancillary services is the autonomous start-up. The operation in isolation is an ancillary service that is not recognized today and there are very few distributed generators capable of offering it.

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1. Autonomous start-up Autonomous start-up is the capacity of a generator to start-up and connect to the grid without having received reference voltage from the grid or required external power sources. In the event of zonal or national blackout, the system operator is in charge of coordinating the reposition of supply in each zone. Hence distribution companies in each zone play a determining role as they have to coordinate demand blocks with the system operator to be coupled in order not to loose stability of the few groups connected during the initial hours of reposition. The system operator divides the grid into 7 areas, which are shown below:

Figure 8.3.1 Zone classification for reposition in the event of zonal or national blackout In general terms, the philosophy of reposition in each zone consists in the start-up of groups with capacity to start autonomously (typically hydraulic) and extend reference voltage to supply auxiliary services of other plants so they can start (typically thermal). Slowly, demand is added so that new groups that have started pick up the load, allowing the hydraulics to regulate frequency and maintain stability of the isolated operation mode. The islands are meshed until in they are finally coupled to have the entire system in synchronization. Graphically:

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Figure 8.3.2 Reposition diagram in the event of national blackout Stations with autonomous start-up for each zone are: • Zone 1 (Duero - Francia): group 2 of Aldeadávila 400kV and Ricobayo

2 220kV, Barazar, Compuerto, Villalcampo. • Zone 2 (Tajo – Centre): Entrepeñas, Buendía, Bolarque 1, Zorita,

Almoguera, Villalba, San Juan, Las Picadas, Azután, Valdecañas, Torrejón, Gabriel and Galán, Valdeobispo, J.M Oriol and Cedillo.

• Zone 3 (Levante): Contreras, Cofrentes, Cortes II and Millares II. • Zone 4 (Aragon and Catalonia): Terradets, Cabdella, Talam, Serós, Flix,

Ribarroja, Mequinenza, Camarasa, Pliana, La Baells, Canelles, Sau, Susqueda, Esterri, Unarre, Aiguamoix, Joeu, Barrados, Bossost, Pont de rei, Baserca, Ip, La Sarra, Seira and Sesue.

• Zone 5 (Andalusia): Tajo de la Encantada, Guillena, N.Chorro, Iznajar

and Tranco. • Zone 6 (Galicia – Leon): las CC.HH. de Belesar, Peares,

Portodemouros, Tambre II, P. Bibey, Conso, S. Esteban, Montefurado, S. Clodio, Soutelo and S. Agustín.

• Zone 7 (Asturias – Cantabria): Arbón, Doiras, Silbón, Salime, Tanes,

Aguayo, La Barca, Priañes, Miranda and Proaza. Today it is very difficult for distributed generation to participate in the reposition plan in the event of a blackout.

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On one hand, we have wind farms whose variability of production could cause many problems in each island due to criticality of frequency – power regulation. On the other, the coordination of the system operator, with dispatches of generation and distribution, is key during the first hours of reposition. Therefore and because today the communication systems between generation under special regime and the distributor are not perfectly integrated, it is not reasonable to make them participate and their connection to the grid should wait until they receive the voltage signal. Finally, it is worth highlighting that all generation facilities connected to the distribution and included in the special regime do not have the capacity to start autonomously. 2. Operation in island mode: This is one of the most important aspects and some way can condition and configure the future of distribution. Today, this possibility is not considered in regulations and the distribution company cannot encourage these phenomena. This is because the distributor is the ultimate party responsible for the supply and its quality; therefore if a generator remains operating in island mode, it is practically impossible for the distributor to guarantee quality levels as they are beyond its control. On the other hand, technically the grid and small generators are prepared as they must develop the following aspects: - Increase the control and monitoring mechanisms of generation units

connected to the network as well as other elements connected to the network.

- Installation of a greater number of voltage and reactive control elements - Considering the capacity to control each generator and distributor, each

network should be adapted and equipped with new tools to optimize the operation and reposition systems.

- The network needs to be adapted in order to be more flexible and allow distributed generation to participate in order to resolve technical restrictions.

- It shall be necessary to create new regulations that develop and encourage this new network concept with a proper assignment of costs and perfect transparency in their calculation.

Finally most of the distribution networks, MV and LV, there is not as much installed generation as demand connected to them. This is a technical problem that makes operation in isolation mode impossible unless the island is created with less demand than what is connected to the network.

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• The Future? For this reason, the concepts handled until now in the frequency – power regulation of major transmission systems, typically based on inertia of turning masses, changes in set point of production and maintenance of international exchanges, give way to generators that provide this service are not synchronous machine but fuel cells, photovoltaic panels, microturbines, flywheels, micro cogeneration, etc. The emerging concept of the Distribution System Operator (DSO) that may also own distribution networks, similar to what happens in the transmission grid. Therefore, more powerful communication and control systems are required with a greater coordination as the number of facilities is much greater than in the transmission grid. Micro control centres could emerge at TC level connected to the distribution operator. Graphically, the following types of networks could be designed:

Figure 8.3.3 Possible future active distribution network diagram Where: DMS (Distribution Management System): distribution control centre. MGCC (Micro Grid Central Controller): micro control centre that receives communications on loads and other elements from controllers. LC (Load Controller): load control system. MC (Microsource Controller): control system for other kinds of elements such as electronic power systems, generator, reactive compensation devices, etc.

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As already discussed in section 2.2.10, Flywheels may become the revelation technology to provide a primary frequency response (primary system reserve) as until now, one of the biggest problems faced in terms of frequency response was the difficulty of finding a technology capable of providing good primary response. Although, as already discussed, it would be difficult to operate in island mode, below are some distribution network examples that did operate in isolation. Hence, we shall once again display the network analyzed in 6.4.1 of a distribution network in Segovia:

I

T1 T2

T3T1

T1

T1 T2

T

1

∼

J

T1

T1

5

5

15

5 5

5 5

15MW

4MW

1.5MW

D

∼B

H

G

F

C

5

T2A

∼

Trafo 132/45

E

Red de 132kV

Trafo 132/45

Figure 8.3.4 Delivery grid in Segovia This example was produced with the generator in substation J producing 2.5MW. Line I-J 45kV open due to discharge generated a failure in line E-J 45kV. Because of this incident, demand in substation J happened to coincide with the generation that was feeding the island in that substation. Another similar situation occurred when substation H remained feeding substation G in isolation after the 45kV I-J circuit disconnected. As can be seen these cases only reflect casuistic, as in another type of situation generation would not have to be equal to demand in order to trigger the protections of the generator.

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9. Impact of DG in the purchases of power from distribution companies

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9. Impact of DG in the purchases of power from distribution companies

As already stated in 6.2, a fundamental activity to be performed by the distributor is the purchase of any energy consumed by consumers participating in the regulated market. However generation included in the special regime must be deducted from this gross demand, hence the distributor buys net energy at fixed prices in the wholesale market (market rate less generation under special regime). Before RD 436/2004, this was a real problem for the distributor as it not only had to predict demand from the regulated market but also predict the generation under special regime included in its network. This started to be a serious problem when wind farms started to reach significant production levels. In addition, generation under special regime did not incur in penalties due to deviation as it did not even have to declare its schedule in order to dump its generation to the distribution network. RD 436/2004 changed several aspects mentioned above: • Any facilities with power greater than 100 MW must notify the distributor

with the forecast of electricity to be transferred to the network for each one of the electricity production market time periods. Forecasts of the 24 periods in each day shall be provided at least 30 hours in advance of the start of such day.

Furthermore, corrections may be provided to such program with an advance of one hour to the start of each intraday market. Should the facilities be connected to the transmission grid, they shall also notify their estimates to the system operator, in addition to the corresponding distributor. Any facilities opting to sell their electricity freely in the market shall be exempted from said notices.

• Any facilities of more than 10 MW under special regime that, in accordance

with section 19.4, must notify their surplus estimates shall be assigned a cost of deviation for each scheduled period where actual production deviates more than the allowed tolerance level from its estimate. Such tolerance shall be 20% for groups b.1 and b.2 in section 2.1 (solar and wind farm energy) and 5% for the rest of groups in section 2.1. Deviation in each one of these schedule periods shall be calculated as the absolute value between the difference in the surplus estimate and the corresponding measurement.

The cost of deviations from each month shall be 10% of the result from

multiplying the average or reference electricity fee for each year defined in Royal Decree 1432/2002, section 2, December 27, and published in the royal decree that establishes the electricity tariff, times the sum of all deviations during such month that have exceeded the tolerances set in the

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previous section. The cost of such installations shall be included in the corresponding invoice to the distribution company.

It is necessary to add the strong incentive experienced by wind farms when moving these two paragraphs to the free market. Hence, the volatility experienced today by the distribution company due to the difficulty of estimating that production of generation under special regime has dropped significantly. However, with the current regulations, the distributor must face deviations that fall within 20% of declared scheduled production to the distribution company by solar and wind farms of more than 10MW under the special regime tariffs and 5% deviations for the rest of technologies. Generally, distribution companies today have more reliable forecast mechanisms, even more than the scheduled production declared by wind farms. On the other hand, the distributor must assume 100% of deviations on behalf of facilities of less than 10MW under the special regime. In conclusion, the situation as of today of distribution companies is far more favourable than before RD 436/2004. Thanks to this RD, deviations under special regime are penalized. Wind farm production, which was what most worried distribution, has mostly moved into the market and therefore the uncertainty forecast problems have dropped. However, the distribution already had powerful production estimate tools for wind farms.

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10. Conclusions

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10. Conclusions

The new regulatory framework which started with Act 54/1997 has represented a very significant change in the Spanish power sector. Since then, the incentives for the development of distributed generation have represented structural changes in the networks to the point that new technical and regulatory challenges have arisen. The benefits of generation installed near production centres are very important, however the impact caused by such generation in the network may not be as positive if the regulations are not adapted and new rules are defined to help resolve technical problems. • In chapter two of this thesis we have defined the concept of distributed generation and reviewed the most important technologies. In conclusion as a definition that best adapts to DG in Spain, we could say that distributed generation is the combination of electricity generation systems connected to the distribution networks, characterized by their reduced power and location close to consumers. The main characteristics are: • Connected to the distribution network. • Often a part of the generation is consumed by the same facility and the rest is

exported to a distribution network (e.g.: cogeneration) • There is no centralized planning of said generation and is not distributed

centrally. • The power output of the groups is usually less than 50 MW. Chapter three showed the installed power, production and capacity of the peninsula for the installation of new renewable generation. Chapter four reviewed the most important regulations that have affected distributed generation facilities directly and indirectly, as well as the networks they are connected to. As the fundamental aspect of this thesis, chapters 5 to 9 covered the impacts of distributed generation on the transmission and distribution networks. We have analyzed the influence of distributed generation in: • The planning and design of distribution networks • Operation and exploitation of the grid • Short-circuit power • Ancillary services • Energy purchases by distributors

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10.1. Influences of distributed generation in the planning and design of networks

Two aspects have been covered with regards to the influence of distributed generation in network investments. On one hand, the technical connection criteria that must be fulfilled by new facilities wishing to be connected to the network and on the other the problems faced by the distribution company when it comes to investments considering the generation included in its network. With regardss to the technical connection criteria, we have mentioned the great importance of the protections used by generation facilities that have been connected as well as their compatibility with network protections. In MV and LV, we have mentioned the importance of disconnecting DG on detecting absence of voltage, while their resistance to voltage gaps in meshed grids is of vital importance to guarantee continuity of supply. With regards to investments, and with the existing regulation, distribution cannot consider the generation included in its network and must be planned as if it were not available. Only in the cases when generation is injected into the transmission grid can the distributor provide facilities with the necessary transmission capacity. An alternative would be to pay for the guarantee of power or the participation in a restrictions market at a distribution level, where the distributor would be in charge of its management.

10.2. Influences of distributed generation in the operation and exploitation of the network

In this section, we have analyzed the influence of DG in aspects such as technical restrictions, losses, voltage levels, voltage collapse, losses and safety of maintenance personnel. With regards to technical restrictions and voltage profiles, we have presented a large number of examples that demonstrate how with the existing regulation, the distribution has no resources to cover all situations that arise in the network. In addition, it has been demonstrated that the current regulations incurrs in contradictions such as for example the fulfilment of certain power factors and voltage levels at the same time. We have proposed a regulatory change describing the importance of creating the figure of the distribution system operator. This new figure should emerge with similar responsibilities as the system operator (REE). Some of the most important are voltage controls; therefore it should be possible to define voltage setpoints for the generation included in its network. Furthermore, there should be a possibility of modifying the production programs of stations in its network, when it is affected by overloads, voltage problems and n-1 failures. The influence of distributed generation in the losses has been demonstrated as highly positive, as penetration today is not very high and in general the flows of higher voltages to lower would be reduced.

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We have highlighted how some of the most important aspects that determine the degree of reduction of losses, the location of DG in the distribution network, the topology and network structure, the degree of penetration of DG in the network, the demand profile of the network and type of production profile of DG. With regards to the safety of maintenance personnel, we have highlighted the importance of including MV and LV mechanism so that generation facilities disconnect when they detect an absence of voltage. In the delivery grid, we have highlighted the importance of telecontrol for disconnecting facilities when it comes to accessing network works.

10.3. Influences of distributed generation in short-circuit powers

The most fundamental aspect is that short-circuit power is not a major problem in distribution networks due to distributed generation. It could be the case that the connection of DG to the network with significant increases in short-circuit power, but it is an easily resolved technical problem using switchgear of greater breaking power. There have been no cases that have required demeshing the grid due to high short-circuit powers as a consequence of new generation; and only certain situations which required changing switchgear. We already mentioned that the transmission grid is already seeing situations with very high short-circuit power levels or with situations breaching n-1. These situations shall be increasingly repetitive, as is the case in other European countries. However this type of situations are caused by generation under normal regime and not from DG. However, we would like to highlight this problem as a critical point with regards to short-circuit powers.

10.4. Influences of distributed generation in ancillary services

As part of the ancillary services, we have analyzed the frequency – power control, voltage – reactive control, autonomous start-up and operation in isolation mode. Three main problems have been identified in terms of frequency – power control: • The difficulty of forecasting wind farm production and therefore the

estimate of secondary reserve necessary to adapt generation to changes in demand. Today this problem is becoming less important thanks to the incentives of wind farm generation, which is moving into the free market. Hence, wind farms must estimate their production in order not to be penalized due to failure to fulfil the production programs.

• The possible lack of frequency stability due to the mass disconnect of wind farm production in the event of network failures. Operating procedure 12.3 establishes some criteria for wind farms to support voltage gaps.

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• The mass disconnect of generation included in the distribution network in the event of important nationwide incidents.

10.5. Influences of distributed generation in the purchases of power from distribution companies

The situation as of today of distribution companies is far more favourable than before RD 436/2004. Thanks to this RD, deviations under special regime are penalized. Wind farm production, which was what most worried distribution, has mostly moved into the market and therefore the uncertainty forecast problems have dropped. However, the distribution already had powerful production estimate tools for wind farms. However, with the current regulations, the distributor must face deviations that fall within 20% of declared scheduled production to the distribution company by solar and wind farms of more than 10MW under the special regime tarifs and 5% deviations for the rest of technologies.

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11. Bibliography

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11. Bibliography

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