SCADA Based Smart Grids

UNIVERSITY OF THESSALY

SCHOOL OF ENGINEERING

DEPARTMENT OF ELECTRICAL AND COMPUTER ENGINEERING

SCADA Based Smart Grids

MSc Thesis

Lambros S. Tsintzouras

Advisor: Ioannis Panapakidis

Volos 2021

Institutional Repository - Library & Information Centre - University of Thessaly18/07/2022 08:01:39 EEST - 65.21.229.84

UNIVERSITY OF THESSALY

SCHOOL OF ENGINEERING

DEPARTMENT OF ELECTRICAL AND COMPUTER ENGINEERING

SCADA Based Smart Grids

MSc Thesis

Lambros S. Tsintzouras

Advisor: Ioannis Panapakidis

Volos 2021

iiInstitutional Repository - Library & Information Centre - University of Thessaly18/07/2022 08:01:39 EEST - 65.21.229.84

ΠΑΝΕΠΙΣΤΗΜΙΟ ΘΕΣΣΑΛΙΑΣ

ΠΟΛΥΤΕΧΝΙΚΗ ΣΧΟΛΗ

ΤΜΗΜΑ ΗΛΕΚΤΡΟΛΟΓΩΝ ΜΗΧΑΝΙΚΩΝ ΚΑΙ ΜΗΧΑΝΙΚΩΝ ΥΠΟΛΟΓΙΣΤΩΝ

Έξυπνα Δίκτυα βασισμένα σε συστήματα SCADA

Λάμπρος Σ. Τσίντζουρας

Μεταπτυχιακή Διπλωματική Εργασία

Επιβλέπων: Ιωάννης Παναπακίδης

Βόλος 2021

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Approved by the Examination Committee:

Supervisor Ioannis Panapakidis

Assistant Professor, Department of Electrical and Computer Engineering, University of Thessaly

Member Dimitrios Bargiotas

Associate Professor, Department of Electrical and Computer Engineering, University of Thessaly

Member Lefteri Tsoukalas

Professor, Department of Electrical and Computer Engineering, University of Thessaly

Date of approval: XX-XX-XXXX

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ACKNOWLEDGEMENT

I would like to express my deepest gratitude to my supervisor Assistant Professor Ioannis Panapakidis for

his guidance and invaluable contribution. I am also grateful to my friend and colleague Komnas Kotsis,

Electrical and Computer Engineer and Smart Grid specialist for his useful input and his indispensable

contribution especially in the Microgrids operation. Last but not least, I would like to thank my company

inAccess Networks S.A for all the support the last ten years in the hard work environment of field

commissioning around the globe that made me a Smart Grid Scada Engineer and the approval to use data

and real cases that i have personally carried out end to end.

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DISCLAIMER ON ACADEMIC ETHICS AND INTELLECTUAL PROPERTY RIGHTS

«Being fully aware of the implications of copyright laws, I expressly state that this diploma thesis, as well

as the electronic files and source codes developed or modified in the course of this thesis, are solely the

product of my personal work and do not infringe any rights of intellectual property, personality and

personal data of third parties, do not contain work / contributions of third parties for which the

permission of the authors / beneficiaries is required and are not a product of partial or complete

plagiarism, while the sources used are limited to the bibliographic references only and meet the rules of

scientific citing. The points where I have used ideas, text, files and / or sources of other authors are clearly

mentioned in the text with the appropriate citation and the relevant complete reference is included in the

bibliographic references section. I fully, individually and personally undertake all legal and administrative

consequences that may arise in the event that it is proven, in the course of time, that this thesis or part of

it does not belong to me because it is a product of plagiarism».

The declarant

Lambros Tsintzouras

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ΠΕΡΙΛΗΨΗ

Η νέα εποχή των έξυπνων δικτύων υποστηρίζεται και συνδέεται αυστηρά με τα συστήματαSCADA. Ένα σύστημα SCADA είναι ένα έξυπνο σύστημα που πραγματοποιεί υπολογισμούς και έχειπρογραμματιστεί με λογικές για τη λήψη αποφάσεων σύμφωνα πάντα μέσω μιας διεπαφής με τοχρήστη, προκειμένου να ολοκληρωθούν έξυπνα πολλές διαδικασίες. Έτσι, αυτή η νοημοσύνη πουπροσφέρεται από τα SCADA συστήματα, σε σχέση με το δίκτυο υψηλής τάσης ή της διανομής, μπορείνα συνδυαστεί για να αποδώσει μια καλύτερη και αξιόπιστη ενέργεια στον τελικό καταναλωτή.

Η παρούσα διατριβή ασχολείται με την τεχνολογία των συστημάτων SCADA και πώς αυτά τασυστήματα μπορούν να εξυπηρετήσουν το εθνικό δίκτυο για τη βελτίωση της απόδοσης της ενέργειαςστο τελικό καταναλωτή. Ειδικότερα, σε αυτή τη διατριβή θα εξεταστεί πώς οι ανανεώσιμες πηγέςενέργειας, τα ηλιακά και αιολικά πάρκα, θα αλλάξουν τη συμπεριφορά τους βάσει εντολών συστημάτωνSCADA. Εκτός από τις μονάδες ανανεώσιμων πηγών ενέργειας, θα συμπεριληφθούν και θα εξεταστούνάλλες τεχνολογίες με βάση τα συστήματα SCADA όπως συστήματα αποθήκευσης ενέργειας με μπαταρίεςκαι συνδυασμένες τεχνολογίες όπως μικροδίκτυα.

Όλες αυτές οι μονάδες παραγωγής ενέργειας έχουν στόχο, εκτός από την παραγωγή ενέργειας,να διατηρούν τις παραμέτρους του δικτύου στο οποίο συνδέονται εντός των ορίων. Αυτός ο στόχος θαεξεταστεί και το πιο σημαντικό είναι το πώς θα επιτευχθεί. Επιπλέον, σε αυτή τη διατριβή θασυμπεριληφθεί η ιστορία των συστημάτων SCADA και των παραδοσιακών πρακτικών, καθώς και τατελευταία χαρακτηριστικά τεχνολογίας των συστημάτων SCADA και πώς συνδυάζονται με το έξυπνοδίκτυο. Εκτός από αυτό, θα εξεταστεί ο αυτοματισμός του υποσταθμού που είναι η υποστήριξη μέσωτων SCADA όλων αυτών των σταθμών παραγωγής ενέργειας.

Τέλος, η συνολική έννοια του έξυπνου δικτύου, ως συμπέρασμα, θα εξηγηθεί και θα εξεταστείμέσω των συστημάτων SCADA. Όλα τα χαρακτηριστικά και οι λειτουργίες που αναφέρονται θα είναιμέσω μιας πλατφόρμας HMI που είναι η τάση της αγοράς, μέσω φορητού υπολογιστή, tablet ήsmartphone. Η έννοια του έξυπνου δικτύου θα εξηγηθεί με βάση όλα τα είδη σταθμών παραγωγήςενέργειας (PV, Wind, Hybrid, Micro-grid, Gas) σε συνδυασμό με συστήματα SCADA. Υπάρχουν 3 σημείασε αυτήν την ιδέα - 1ο Οι σταθμοί παραγωγής ενέργειας, 2ο το δίκτυο μεταφοράς / διανομής και 3ο οτελικός καταναλωτής. Σε αυτά τα 3 σημεία, τα συστήματα SCADA θα ενσωματωθούν για να μετατρέψουναυτήν τη διαδικασία σε μια διαδικασία έξυπνου δικτύου. Αυτό σημαίνει, από άποψη αξιοπιστίας τουδικτύου, ότι θα έχουμε μειωμένες απώλειες, λιγότερα σφάλματα, καλύτερη απόδοση δικτύου,ικανοποίηση της ζήτησης της ενέργειας, λιγότερη συντήρηση του εξοπλισμού του συστήματος καιασφαλή και αξιόπιστη ενέργεια για την κάλυψη του φορτίου.

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ABSTRACT

The new smart grid era is followed and strictly connected to the SCADA systems. A SCADA system is anintelligent system computed and programmed with several logics to make decisions on schedule orthrough the Human Machine Interface in order to complete several commands smartly. So, thisintelligence, in relation with the high voltage or distribution medium voltage network, can be combined toserve a better and reliable energy in the final consumer.

The current thesis deals with the technology of SCADA systems and how these systems can servethe national grid network to improve the performance. Particularly, in this thesis shall be examined howthe renewable energy plants, solar and wind parks, will change their behavior based on SCADA systemscommands. Also, apart from the renewable energy plants, other technologies will be included andexamined based on SCADA systems such as battery energy storage systems and combined technologiessuch as micro-grids and other hybrid plants.

All these power plants have a secondary goal, apart from producing energy, to maintain theparameters of the grid network within the limits. This goal shall be examined from this thesis and themost important is how it will be achieved. Additionally, in this thesis shall be included the history of theSCADA systems and traditional practices as well as the latest technology features of the SCADA systemsand how they are combined with the Smart grid. Apart from this, the substation automation shall beexamined which is the support of all these power plants. The hardware and partially the software of theSCADA systems will be shown used to implement the smart grid concept. HMI platforms will be shownand how the full control of the systems shall be integrated into the platform.

Last but not least, the platform will be used by the producers or other 3rd party vendors todispatch the sites through the HMI platform and participate in the daily spot energy market for biddingand systems’ marginal price, so as to reduce the price for the consumers. Finally, the overall smart gridconcept, as a conclusion, will be explained and examined through the SCADA systems. All the features andmodes explained will be through an HMI platform which is the tendency of the market, through a laptop,tablet or smartphone. The smart grid concept shall be explained based on all kinds of power plants(PV,Wind,Hybrid,Micro-grid,Gas) combined with SCADA systems. There are 3 points in this concept - 1stThe power plants (production of energy), 2nd the transmission/distribution network, and the 3rd finalconsumer. In these 3 points the SCADA systems will be integrated to transform this procedure into asmart grid procedure. That means, in terms of network reliability, that we shall have reduced losses, lessfaults, better network performance, meet the energy demand, less maintenance of the system equipmentand safe and reliable energy to meet the load.

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CONTENTS

ACKNOWLEDGEMENT 5

ΠΕΡΙΛΗΨΗ 8

ABSTRACT 10

CONTENTS 12

LIST OF FIGURES 15

LIST OF TABLES 17

DEFINITION of ACRONYMS 18

CHAPTER 1 1

1. SCADA & Automation History 11.1 Introduction 11.2 SCADA Systems History 3

1.2.1 SCADA System Definition 31.2.2 Monolithic & Early SCADA Systems 6

1.2.2.1 1st Generation Monolithic Scada Systems 61.2.2.2 2nd Generation Distributed Scada Systems 61.2.2.3 3rd Generation Networked Scada Systems 71.2.2.4 4th Generation Web-Based Scada Systems 81.2.2.5 5th Generation Agent-Based Scada Systems 9

1.3 Evolution of SCADA Systems & Future 9

CHAPTER 2 11

2. SCADA Fundamentals 112.1 SCADA Systems Architecture 11

2.1.1 CPUs in SCADA Systems 132.2 SCADA I/O Peripheral Units 14

2.2.1 Analog Inputs & Outputs 152.2.2 Digital Inputs & Outputs 172.2.3 Pulse Signals 18

2.3 SCADA Communication Networks 182.3.1 RS485 Serial Network 192.3.2 TCP/IP & Ethernet/Fiber Networks 192.3.2 Firewalls Routers & Switches 212.3.4 Servers Historian Platforms & HMIs 22

2.4 SCADA Communication Protocols 24

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2.4.1 Modbus Protocol 242.4.2 DNP3.0 Protocol 252.4.3 IEC-60870-5-104 Protocol 262.4.4 IEC-61850 Substation Automation 272.4.5 DLMS Energy Metering 29

CHAPTER 3 31

3. SCADA Based Smart Grids 313.1 SCADA & Smart Grid Architecture 31

3.1.1 Smart Infrastructure Analysis 313.1.1.1 HV Transmission Lines Smart Infrastructure 323.1.1.2 MV Distribution Lines Smart Infrastructure 333.1.1.3 LV Delivery Lines Smart Infrastructure 34

3.1.2 Smart ICT Infrastructure 353.1.2.1 IP Security 353.1.2.2 IP Security & IoT 363.1.2.3 Cybersecurity and access control 37

3.1.3 Smart Infrastructure on Power Generation 383.1.3.1 Flexible Alternating Current Transmission Systems (FACTS) 383.1.3.2 Smart PV Inverters 393.1.3.3 Next Generation Gas Turbines 413.1.3.4 Battery Energy Storage Systems (BESS) 423.1.3.5 Wind Generators 433.1.3.6 Smart Metering 44

3.2 SCADA & Smart Grid in Renewable Energy Generation 463.2.1 SCADA & Smart Grid in PV Power Plants 46

3.2.1.1 PV Active Power Control (APC) 503.2.1.2 PV Active Power Control on 50MW AC Plant 533.2.1.3 PV Frequency Control (FC) 553.2.1.4 PV Frequency Control on 50MW AC Plant 563.2.1.5 PV Reactive Power Control (RPC) 603.2.1.6 PV Reactive Power Control on 80MW AC Plant 613.2.1.7 PV Power Factor Control (PFC) 623.2.1.8 PV Power Factor Control on 80MW AC Plant 633.2.1.9 PV Automatic Voltage Regulation (AVR) 633.2.1.10 PV Voltage Control & AVR on 80MW AC Plant 64

3.3 SCADA & Smart Grid in Battery Energy Storage Systems 653.3.1 SCADA BESS control & Grid Services 67

3.3.1.1 High level control logic of BESS 683.3.1.2 Firm Frequency response in BESS 693.3.1.3 Close loop control in BESS 74

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3.3.1.3 State of Charge Algorithm in BESS 743.3.1.4 SCADA BESS Control in 57MWh Capacity Site 75

3.5 SCADA & Smart Grid in Micro-Grid Systems 803.5.1 SCADA & Micro-Grid Control 81

3.5.1.1 SCADA features for off-grid applications 823.5.1.2 Intro to Micro-Grid systems operation with SCADA 833.5.1.3 SCADA for an autonomous Micro-Grid system (PV/Battery/Diesel Generators) 85

CHAPTER 4 93

4. Energy Management & Control Centers 934.1 Control centers 944.2 Energy Management Systems (EMS) 954.3 Virtual Power Plant (VPP) 97

4.3.1 SCADA Systems & VPP 984.3.2 VHP Ready Protocol 99

4.4 CIM (Common Information Model) 1034.5 Grid compliance 1034.6 AI in SCADA systems 104

4.6.1 SCADA Systems advanced features 1064.6.1.1 KPIs 1064.6.1.2 Inverters Heatmap 108

CHAPTER 5 109

5. SCADA Based Smart Grids Conclusion 1095.1 Overall Conclusion 1095.2 Concept of SMART GRID conclusion 111

References 113

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LIST OF FIGURES

Figure 1.1: A Complete SCADA System 5 Figure 1.2: Monolithic SCADA System [4] 6 Figure 1.3: Distributed SCADA System [4] 7 Figure 1.4: Networked SCADA System [4] 8 Figure 1.5: Web-Based SCADA System [3] 8 Figure 2.1: A complete SCADA System Hardware design 12 Figure 2.2: A complete SCADA System architecture 13 Figure 2.3: Stand alone CPU with Serial RS232 Connectors 13 Figure 2.4: Legacy SCADA System 14 Figure 2.5: A typical schematic of I/O units in a SCADA system 14 Figure 2.6: Power scaling in to analog 4-20mA values [1] 16 Figure 2.7: Analog values converted to digital values and routed to a SCADA CPU

16 Figure 2.8: A typical connection of an analog input/output signal to an I/O unit 16 Figure 2.9: A typical connection of a digital input signal to an I/O unit 17 Figure 2.10: A typical connection of a digital output signal to an I/O unit 18 Figure 2.11: Diagram of OSI 7 layers 20 Figure 2.12: Overall SCADA network design with Ethernet and Fiber connections 21 Figure 2.13: Overall data flow for power station until consumer 22 Figure 2.14: SCADA server functionalities architecture 23 Figure 2.15: DNP3.0 frame data structure [16] 26 Figure 2.16: Data architecture with IEC104 protocol 27 Figure 2.17: Data modelling with IEC61850 protocol [20] 28 Figure 2.18: Data modelling with IEC61850 protocol [20] 28 Figure 2.19: DLMS Communication profile [22] 30 Figure 2.20: Extensive DLMS Communication profile [23] 30 Figure 3.1: A Smart Grid Infrastructure end to end [24] 32 Figure 3.2: A Smart Grid Recloser protection 34 Figure 3.3. Network Security Architecture – TCP/IP Model. [29] 36 Figure 3.4. IP Communication between Smart IoT devices and Gateway. [31] 36 Figure 3.5. Central Management System Secure Redundant Controller Access 37 Figure 3.6: UPFC Structure for HV Lines Support [34] 39 Figure 3.7: Smart PV inverter control scheme [33] 40 Figure 3.8: Flow chart of Smart PV inverter control [28] 40 Figure 3.9: Simple gas turbine system [36] 42 Figure 3.10: Combined Cycle gas turbine system [36] 42 Figure 3.11. Battery Energy Storage System 43 Figure 3.12. Smart Meter front view and back view with SCADA communication card 45 Figure 3.13: SCADA System for PV Power Control 47 Figure 3.14: SCADA System data flow for PV Power Control 48 Figure 3.15: SCADA System PV Power Control Services 50 Figure 3.16: Active power control with direct setpoints 53 Figure 3.17: Active power control with gradient setpoints 54 Figure 3.18. Frequency support through active power control 55 Figure 3.19. Three characteristic curves for three different Pref values. 57 Figure 3.20. Three characteristic curves for three different Pref values. 58 Figure 3.21. Three characteristic curves for three different Pref values. 58

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Figure 3.22: Active power control with frequency setpoints 59 Figure 3.23: Reactive power control setpoints 61 Figure 3.24. Power factor control as a function of active power 62 Figure 3.25. Voltage control with a slope 64 Figure 3.26. AVR control with Q setpoints 65 Figure 3.27. Electric circuit of a Battery System 66 Figure 3.28. Battery System with BMS 66 Figure 3.29. Overall Electric circuit of a Battery System 67 Figure 3.30. High Level Control Logic Diagram 69 Figure 3.31. Example of a Non-Dynamic Response to a Varying Frequency 70 Figure 3.32. Example of a Dynamic Response to a Varying Frequency 71 Figure 3.33. Injection Profile 72 Figure 3.34. Allowable Power Tolerance for a Negative Gradient Active Power Response 73 Figure 3.35. Example of frequency simulation for SCADA test 74 Figure 3.36. A BESS system with SCADA 76 Figure 3.37. Central Management System integration to Site Equipment 77 Figure 3.38. SCADA Platform for a BESS site 78 Figure 3.39. Active power export/import on real BESS site based on frequency fluctuation 79 Figure 3.40. All power converters SOC (charge/discharge) during Dynamic FFR mode 79 Figure 3.41. A Microgrid control system with SCADA 81 Figure 3.42. Electrical Single line drawing of the Microgrid system 86 Figure 3.43. Microgrid operation flow chart 87 Figure 3.44. Microgrid operation through the SCADA system 91 Figure 3.45. Microgrid overall electrical Schematic SCADA page 91 Figure 4.1. EMS & Control Center framework with SCADA [1] 93 Figure 4.2. Overall Control center architecture [10] 94 Figure 4.3. PV plant Control Center connection with local SCADA 95 Figure 4.4. EMS Architecture 96 Figure 4.5. Overview of VPP 97 Figure 4.6. SCADA & VPP 98 Figure 4.7. Schematic description of the VHPready 4.0 scope 100 Figure 4.8. SCADA and smart grid protocols in use and under development [1] 103 Figure 4.9. System’s Marginal Price computation with ftp data import to SCADA 105 Figure 4.10. Overview of SCADA structure with SMP calculation 106 Figure 4.11. Performance ratio KPI of a SCADA platform 107 Figure 4.12. SCADA heatmap feature for PV inverters 108 Figure 5.1: A Complete SMART GRID with SCADA System [51] 110

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LIST OF TABLES

Table 2.1: Modbus function codes table 25

Table 3.1: Active power setpoints and grid response 53

Table 3.2: Active power setpoints, Frequency and grid response 59

Table 3.3: Reactive power setpoints and grid response 61

Table 3.4: Power factor setpoints and grid response 63

Table 3.5: Voltage setpoints and grid response 65

Table 3.6. Frequency Injection Table Corresponding with Times 71

Table 3.7. Frequency Injection and Expected Response values 72

Table 4.1: VHP Ready Signals 101

Table 4.2. SCADA & Control center data points for Grid Compliance with IEC104 protocol 104

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DEFINITION of ACRONYMS

ADC Analog to Digital Converter GG Gas Generator

AI Artificial Intelligence GT Gas Turbine

AMI Advanced MeteringInfrastructure

HMI Human Machine Interface

APC Active Power Control HV High Voltage

AVR Automatic Voltage Regulation HP Heat pumps

BESS Battery Energy StorageSystem

MV Medium Voltage

BMS Battery Management System PA Power Analyzer

CB Circuit Breaker PCC Point of Common Coupling

CC Control Center PFC Power Factor Control

CCTV Closed Circuit Television PPC Power Plant Controller

CHP Combined heat power PR Protection Relay

DA Distributed Automation PV Photovoltaic Plant

DER Distributed Energy Resources RES Renewable Energy Sources

DCS Distributed Control Systems RPC Reactive Power Control

DMS Distributed ManagementSystems

SCADA Supervisory Control andData Acquisition

DSO Distributed System Operator SM Smart Meter

EM Energy Meter SMP System marginal price

EMS Energy Management System STATCOM Static Compensator

FC Fuel Cells

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CHAPTER 1

1. SCADA & Automation History

1.1 Introduction

The global electricity demand is growing at a rapid pace, making the requirements for more reliable,

environment friendly, and efficient transmission and distribution systems inevitable. The traditional grids

and substations are no longer acceptable for sustainable development and environment-friendly power

delivery. Hence, the utilities are moving toward the next-generation grid incorporating the innovations in

diverse fields of technology, thereby enabling the end users to have more flexible choices and also

empowering the utilities to reduce peak demand and carbon dioxide emissions to become more efficient

in all respects. Power engineering today is an amalgam of the latest techniques in signal processing, wide

area networks, data communication, and advanced computer applications. The advances in

instrumentation, intelligent electronic devices (IEDs), Ethernet-based communication media coupled with

the availability of less-expensive automation products and standardization of communication protocols

led to the widespread automation of power systems, especially in the transmission and distribution

sector. In today’s world with limited resources and increasing energy needs, optimization of the available

resources is absolutely essential. Conventional power generation resources such as coal, water, and

nuclear fuels are either depleting or raising environmental concerns. Renewable sources are also to be

utilized judiciously. Hence there is a need to optimize the energy use and reduce waste. Automation of

power systems is a solution toward this goal, and every sector of the power system, from generation, to

transmission to distribution to the customer is being automated today to achieve optimal use of energy

and resources. In order to integrate the new technologies with the existing system, it is necessary that the

practicing engineers are well versed with the old and new technologies. However, in the present scenario,

most of the engineering professionals learn the new technology “on the job” as the pace of technology

development is very fast with the advent of new communication protocols, relay IEDs, and related

functions. This is all the more relevant in the core field of power engineering as the power industry needs

trained engineers to keep up the pace of the rapid expansion the power industry is envisaging, to meet

the energy consumption that is expected to triple by 2050. It is pertinent to explore the automation of

power systems in detail. [1] The traditional process control systems are computer based systems that

control flows, temperatures, pressures etc in the process industry. Before computers process engineers

observed instruments and manually opened and closed valves etc. The manual control was replaced by

mechanical and pneumatical regulatory controllers, which later on became electronically based (single

loop controllers). During the 60's (last century) central computers took over the role of the loop

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controllers. After the first microprocessors (Intel 8080 etc) came to the market the first microprocessor

based control system, DCS (Distributed Control System), was introduced. At the same time the first PLC's

were launched. These were also based on the same technology, but their history came from relay

technology. The applications were on-off binary control and sequence control. In practice the DCS and the

PLC were used in the same industries, but because of the different user groups the systems were

developing separately Over the years. The DCS users were Instrument and Process Engineers while the

PLC users were the Electrical Engineers. This is still valid today, where we see DCS systems and PLC

systems on the market. They use the same basic technologies, but have to some extent different

functions and are positioned differently in the market. The borderlines between PLC’s and DCS’s are

disappearing for the process industries and more DCS functionality is moved into the systems that are

used by the Manufacturing Industries (traditional PLC users). Some “traditional” PLC functions are also

being moved into the DCS’s. Examples of this are interfaces to switchgears and to motor drive equipment.

[2]

Automation is the use of control systems such as numerical control (NC), programmable logic control

(PLC), distributed control system (DCS) and other types of control systems, in addition to other

applications of information technology such as computer-aided technologies, i.e., CAD, CAM, CAx…etc., to

control industrial machinery and processes, reducing the need for human intervention. In the scope of

industrialisation, automation is a step beyond mechanisation. Where mechanisation provided human

operators with machinery to assist them with the muscular requirements of work, automation greatly

reduces the need for human sensory and mental requirements as well. There is confusion among

automation beginners and students with the differences between PLC, DCS, and SCADA. PLC is a pure

control system which can work standalone to control a physical process; it can be used as a RTU in a

SCADA system, and usually, it is used for small control processes. Historically, PLCs were usually

configured with only a few analogue control loops but for processes requiring hundreds or thousands of

loops, a DCS would instead be used. PLC has some disadvantages such as, it lacks the flexibility for

expansion and reconfiguration, the operator interface in PLC systems is also limited, moreover,

programming PLC by a higher-level language and/or capability of implementing advanced control

algorithms is also limited. DCS is a system that does what a PLC would do, but the difference is that a DCS

is used in much larger and complex control processes. DCS is the system in which controllers are

distributed geographically and integrated with all the control hardware which is connected from the

various field devices. DCS has its own network, Controllers and HMI. It controls the process as a stand-

alone system. It has the control loops built into its own controller. [3]


1.2 SCADA Systems History

1.2.1 SCADA System Definition

The concept of SCADA is very often used in the industrial world, as it is widely used in almost every field of

industry and not only: manufacturing, electric power generation, transmission and distribution, building

and facilities, traffic signals etc. But behind this concept, there is a history of over 50 years of

development: from the first idea of supervisor control of systems to the most complex data acquisition

and supervisory control systems nowadays. [4] Since the early 60s, industrial process control has been

applied by electric systems. In the mid 1970’s, the term SCADA emerged, describing the automated

control and data acquisition. Since most industrial and automation networks were physically isolated,

security was not an issue. This changed, when in the early 2000’s industrial networks were opened to the

public internet. Increased interconnectivity led to more productivity, simplicity and ease of use. It

decreased the configuration overhead and downtimes for system adjustments. However, it also led to an

abundance of new attack vectors. In recent time, there has been a remarkable amount of attacks on

industrial companies and infrastructures. This is done by investigating the exploits that are available on

public sources. In the 1970’s, the third industrial revolution took place. During this phase, computers were

introduced into industry in order to automate tasks that, until then, had to be done by hand or by

application-tailored solutions. Since then, computer technology has taken huge steps. Reconfigurable

Programmable Logic Controllers (PLCs) took the place of hard-wired relay logic circuits. Domain-specific,

proprietary fieldbuses, like CAN and Modbus, have been replaced by TCP/IP-based solutions, such as

ModbusTCP, ProfiNET and OPC UA, that make use of the vastly available internet infrastructure and its

network hardware. Opening networks to the outside enables easier management of production

capabilities. Remote maintenance, simpler adjustment of machines and a constant flow of information

are but a few of the advantages. [5]

SCADA System Definition (a)

SCADA (supervisory control and data acquisition) systems are a type of industrial control system widely

used in virtually all industrial plant and production facilities to monitor and control industrial processes.

They are critical for increasing the efficiency of processes and detecting possible problems in facilities.

SCADA systems use RTUs(remote terminal units) or PLCs (programmable logic controllers) to collect

measurements and equipment status data. The collected data are compiled, formatted, and presented to

a control room operator using a special dashboard that enables supervisory decisions to adjust or

override normal RTU controls. The main application of SCADA is alarm handling—the SCADA system

monitors whether certain alarm conditions are satisfied or not. Early SCADA system computing was done

using large minicomputers. Common network services did not exist at the time SCADA was developed.

Thus, SCADA systems were independent, with no connectivity to other systems, and the communication

protocols were strictly proprietary. In second generation SCADA systems, information and command

processing were distributed across multiple stations, which were connected through a local area network.


Each station was responsible for a particular task, which reduced the cost compared to the first-

generation systems. [6]

SCADA System Definition (b)

A SCADA system is a computer based system that handles and logs several physical signals. These signals

might be analog, digital or signals that are exported from other devices, such as meters and protection

relays. In any case, the SCADA system has to evaluate these signals and make decisions. SCADA is the

system that sits on top of those devices in order to supervise them. As the SCADA system supervises all

system’s devices it can do several things, such as inform the user about the status of the physical signals

that the whole system contains and the user could proceed in any command, secondly make decisions

based on logics written in the memory of the SCADA computer and connected with the physical signals of

the system, and thirdly to provide the status and events, or alarms of all connected devices. Concluding, it

can do an informative job for the user and the user can prepare any maintenance or decision based on

SCADA signals’ information. So, any value of the connected physical signal can be used either to inform

the user and make decisions, and to be stored in servers or trigger any logic written based on these

signals, or create alarms for the user. This is a fully completed description of the SCADA Systems. The

description will be added and explained as well in the second chapter in more detail.

SCADA System Definition (c)

A SCADA (supervisory control and data acquisition) is an automation control system that is used in

industries such as energy, oil and gas, water, power, and many more. The system has a centralized system

that monitors and controls entire sites, ranging from an industrial plant to a complex of plants across the

country. A SCADA system works by operating with signals that communicate via channels to provide the

user with remote controls of any equipment in a given system. It also implements a distributed database,

or tag database, that contains tags or points throughout the plant. These points represent a single input

or output value that is monitored or controlled by the SCADA system in the centralized control room. The

points are stored in the distributed database as value-timestamp pairs. It's very common to set up the

SCADA systems to also acquire metadata, such as programmable logic controller (PLC) register paths and

alarm statistics. While these systems simplify a given infrastructure, their components are quite complex.

There are some essential composing parts of a SCADA system:

Flexible and open architecture

Basic SCADA functionality

Alarm Handling and Trending

Access Control

Automation

Logging, Archiving, Report Generation

Interfaces to H/W and S/W

Development Tools


Human Machine Interface (HMI)

MIMICs & Schematics

Supervisory system

Remote Terminal Units (RTUs)

Programmable Logic Controllers (PLCs)

Communication infrastructures

The HMI processes data from each tag and sends it to a human operator, where he or she then can

monitor or control the system. The supervisory system gathers the data sent from each tag and sends

commands or operations to the process. The RTUs connect sensors and convert their signals to digital

data and send it to the supervisory system, where it can be stored in a distributed database. PLCs are

used as field devices because they are much more versatile and economical than process-specific RTUs.

Finally, the communication infrastructure delivers connectivity to the supervisory system and then to the

RTUs and PLCs for the user to command. The communication infrastructure is necessary to relay data

from remote RTU/PLCs, which run along electric grids, water supplies, and pipelines. Communication is

the absolute most essential link for a SCADA system to operate properly; however, how well the system

manages communication from HMI to RTUs and PLCs fundamentally determines how successful a SCADA

system can be. Figure 1.1 depicts what a basic SCADA system might look like for a given infrastructure.

Figure 1.1: A Complete SCADA System


1.2.2 Monolithic & Early SCADA Systems

The Scada systems can be divided in the following sections as it was first introduced until today’s

technology. So, it goes as follows:

1st Generation Monolithic Scada Systems

2nd Generation Distributed Scada Systems

3rd Generation Networked Scada Systems

4th Generation Web-Based Scada Systems

5th Generation Agent-Based Scada Systems [3]

1.2.2.1 1st Generation Monolithic Scada Systems

Introduced in the 70s the monolithic SCADA systems were installed in the same place of the units and

devices that should be monitored. Master controller and slaves at the same area. There was no network

connectivity or remote access through the internet. There was only some serial communication between

the devices and the same serial communication for local access and maintenance. The protocols were

proprietary and the master computers configuration as well. In Figure 1.2 a Monolithic SCADA system is

depicted.

Figure 1.2: Monolithic SCADA System [4]

1.2.2.2 2nd Generation Distributed Scada Systems

Introduced in the 80s and 90s these SCADA systems were networked with devices using special purpose

protocols. There was no external network connection. The development and improvements in system

miniaturization and the Local Area Network (LAN) technology were the key factors that led to the

distributed SCADA. Multiple stations with various functions were able to communicate real-time with

each other and interchange data between them. [3],[4] The LAN used in this kind of SCADA system was


based on proprietary protocols developed by vendors. This offered the possibility of increasing

communication speed, system reliability and real-time traffic optimization. But again, all the devices

connected to the SCADA LAN were not able to communicate with other external devices using other

existing protocols. Therefore, the systems were distributed, capable of communicating with each other,

but only with proprietary protocols supplied by vendors. [4] In Figure 1.3 a Distributed SCADA system is

depicted.

Figure 1.3: Distributed SCADA System [4]

1.2.2.3 3rd Generation Networked Scada Systems

Introduced in the early 2000 SCADA systems are no longer isolated but connected to external networks,

i.e., the internet. The third generation of SCADA systems is very similar with the second one, except one

primary difference: it is oriented to an open system architecture, rather than a vendor controlled and

proprietary environment. In this kind of system, the communication is based on open protocols, which

allow SCADA functionality to be distributed in WANs, not only in closed LANs. Also, using open standards

and protocols eliminated the SCADA limitations. [3],[4] In Figure 1.4 a Networked SCADA system is

depicted.


Figure 1.4: Networked SCADA System [4]

1.2.2.4 4th Generation Web-Based Scada Systems

Accessing SCADA components from everywhere at any time using any web browsers, thin clients, PDA,

mobile phone, etc. [3] An interesting direction of SCADA architectures is what is called web-based or

internet-based SCADA systems. Web-based SCADA System makes use of the internet and hypertext

transfer protocol (HTTP) and other web technologies as a communication layer of the system. It also uses

development tools, framework, platforms and computer languages which are used by regular internet

applications as the development environment of SCADA applications. Web-based SCADA systems use the

internet to transfer data between the remote terminal units (RTUs) and the master terminal unit (MTU)

and/or between the operators’ workstations and the MTU. [4] In Figure 1.5 a Web-Based SCADA system is

depicted.

Figure 1.5: Web-Based SCADA System [3]


1.2.2.5 5th Generation Agent-Based Scada Systems

Nowadays and futurely, using agents and multi-agent systems new architectural styles to build scalable,

reliable, and flexible agents. Modern supervisory control and data acquisition (SCADA) systems comprise

a variety of industrial equipment such as physical control processes, logical control systems,

communication networks, computers, and communication protocols. They are concerned with control

and supervision of production control processes. Modern SCADA networks contain highly distributed

information, control, and location. Moreover, they contain a large number of heterogeneous components

situated in highly changing and uncertain environments. As a result, engineering modern SCADA is a

challenging issue and conventional engineering approaches are no longer suitable for them because of

their increasing complexity and highly distribution. MultiAgent Systems (MAS) are used to enable building

adaptive agent based SCADA systems by modeling system components as agents in the micro level and as

organizations or societies of agents in the macro level. [3], [7]

1.3 Evolution of SCADA Systems & Future

The working environments of modern SCADA systems are dynamic and change continuously in

unpredictable and uncertain manner. If the system is flexible enough, it will be able to adapt to

environment changes in runtime without the need to administrator intervention or at least with less

intervention, these are the challenges of modern SCADA systems as described below: [7]

Complexity is the quality of being intricately combined. Complexity tends to be used to characterise

something with many parts in intricate arrangement. SCADA systems complexity resulted from adding

new components such as computers, operator stations, networks, and other types of resources.

Scalability is the ability of a system, network, or process, to handle a growing amount of work in a

capable manner or its ability to be enlarged to accommodate that growth. A perfectly scalable system is

one that has a fixed marginal cost to add additional components. There is a relation between scalability

and complexity because increased size means increased complexity.

Security is the degree of resistance to, or protection from, harm. It applies to any vulnerable and valuable

asset, such as a person, dwelling, community, nation, or organisation. For reasons of efficiency,

maintenance, and economics, data acquisition and control platforms have migrated from isolated in-plant

networks using proprietary hardware and software to PC-based systems using standard software,

network protocols, and the internet.

Reliability is the probability of a component or a system under certain conditions and predefined time, to

perform its required task. The main reason for the SCADA failure is the communication network failure.

Flexibility means that the SCADA system is not a point-to-point communication of fixed path, but a

communication that can take place between (among) any random two (or more) points at any time.


Enhancing information system flexibility can be achieved with flexible information technology

infrastructure and adaptable application systems.

Interoperability is a property referring to the ability of diverse systems and organisations to work

together (inter-operate). The capability to communicate, execute programs, or transfer data among

various functional units in a manner that requires the user to have little or no knowledge of the unique

characteristics of those units.

Robustness is the ability of a computer system to cope with errors during execution or the ability of an

algorithm to continue to operate despite abnormalities in input, calculations...etc.

Legacy systems are those that continue to be used despite relatively poor performance and a lack of

compatibility with other systems. Often, replacing hardware components is an expensive, unpalatable

option for the customer. [3]


CHAPTER 2

2. SCADA Fundamentals

2.1 SCADA Systems Architecture

A SCADA system consists of various devices that all of them are installed and configured in the samenetwork. The same network in terms of subnet or at least a router that can connect 2 subnets at Layer 3OSI or the same network in terms of serial connectivity with field devices. The main unit of a SCADAsystem is the CPU. The CPU collects all the signals and stores them locally for a minimum of timedepending on the buffer and RAM size of the CPU. The CPU is the main and critical unit of such a systembecause it can be configured for several logic or other functions and field devices data acquisition. TheCPU sometimes can act as server to client architecture and send signals to other 3rd party CPUs. Apartfrom the CPU, there are I/O peripheral units that can handle all the SCADA hardwired signals. These I/Ounits are very important and usually they can be connected with the SCADA with serial connection,network TCP/IP connection or directly in the same data electrical bus of the CPU such as a standard oldversioned PLC. These PLCs even represent the old fashion they are used till today in industrialautomation.

Going back to the I/O units they log the physical signal and the SCADA CPU stores all the data andalarms or events of these physical signals. The physical signal may consist of some sensors likemeteorological sensors or other sensors such as industrial pipelines pressure. Additionally, the SCADAsystems may collect data of other peripheral devices such as meters, protection relays of Medium andHigh Voltage lines, or solar inverters, generators and batteries. In order to connect all these devicestogether several things are needed such as routers, firewalls and switches to consolidate all of them inthe same network. Sometimes apart from the standard network material, fiber optics are used to get datato the SCADA from long distances. The data collected from the CPUs can be stored locally to an LPS, localplant server and in parallel send the data in a cloud based server such as Amazon or Google. Moreoveranother SCADA component is the GPS clock synchronisation device which is used to keep all system’sdevices aligned in terms of time synchronisation for data logging and events logging. The system usually ispowered through a UPS to make the SCADA flexible in power cut offs. Moreover the system is configuredeither to function in local mode through an HMI or remote from a laptop, tablet. This architectureconsists of a complete SCADA system. In Figures 2.1 & 2.2 a complete SCADA system is presented asdescribed more or less in the above section. The system consists of routers, firewalls and switches ormedia fiber converters and splice boxes for the network, I/O units for physical signals data logging, fieldsensors of all types, meters, cloud and loca servers, HMI units, GPS clock synchronisation device, PLCs andCPUs, as well as CCTV system cameras. In Figure 2.1 a complete SCADA System Hardware design isdepicted.


Figure 2.1: A complete SCADA System Hardware design

In the above rack system design the full SCADA hardware design of a SCADA system is depicted. As

observed, there are I/O units for the physical signals, CPUs for data logging, Local plant servers, switches

and routers-firewalls for VPN and cloud services as well as IP security, UPS for uninterruptible power flow,

sockets and fiber splice boxes, as well as at the rear view terminal blocks for serial connection or other

physical signals connection. In Figure 2.2 a complete SCADA System architecture is depicted.


Figure 2.2: A complete SCADA System architecture

2.1.1 CPUs in SCADA Systems

As we explained all the SCADA systems architecture we shall move forward with the main component of a

SCADA system which is the CPU. The CPU sometimes can be as a separate industrial controller with very

good hardware characteristics and high specification for industrial environment installations such as high

temperatures, high altitude, dust and humidity and sometimes can be as a traditional PLC. Initially the

CPU that is stand alone without any data bus connected with other I/O cards is presented in Figure 2.3

from Advantech S.A an ARK 2120F industrial computer. This kind of CPU is equipped with several serial

ports RS232, usb ports, ethernet, VGA for display and some of them are equipped with I/O interfaces. In

those stand alone CPUs the ethernet interface is double for bonded interfaces configuration and

redundancy in core switches. The serial ports sometimes can be used with RS485 interface, picking up

only the pins corresponding to this, and sometimes as the standard RS232 port for serial connectivity. A

disadvantage of this type of CPU is the necessity of installing I/O units and power supply units in an

enclosure and an advantage is that the several terminal blocks needed to terminate the respective cables

makes the procedure of the installation easiest. In Figure 2.3 a Stand alone CPU with Serial RS232

Connectors is depicted.

Figure 2.3: Stand alone CPU with Serial RS232 Connectors


The legacy - all in one CPUs - are equipped normally with all I/O units needed, they are rack mounted,

they have embedded the power supply unit needed and the I/O cards can be plug and play. It is all in one

SCADA PLC system to install and apply in any application depending on the needs. As we see in Figure 2.4

a legacy Scada PLC is consisted of, PSU at slot1, CPU at slot0, Analog Input I/O card at slot1, Digital Input I/

O card at slot2, RS485/RS232 card at slot4, and Digital Output I/O card at slot6. The advantage of this unit

is that less space needed to install in an enclosure and a disadvantage is that the CPU hardware

requirements are limited. In Figure 2.4 a Legacy SCADA System is depicted.

Figure 2.4: Legacy SCADA System

2.2 SCADA I/O Peripheral Units

The I/O peripheral units can be connected to a SCADA system either through serial communication or

TCP/IP. These units are used to gather all the information from the peripheral sensors, meteorological or

not, states of circuit breakers and switches or other on/off information needed from the SCADA. I/O units

play a significant role in the SCADA systems as the information sent can be calculated from the CPUs and

perform several logics. In the monitoring part of the SCADA systems, the data acquired can be broadly

classified into two categories: analog and digital. Pulse data also are acquired, as per the requirement, in

case of a count accumulation function, like energy meter data. [1] In Figure 2.5 A typical schematic of I/O

units in a SCADA system is depicted.

Figure 2.5: A typical schematic of I/O units in a SCADA system


2.2.1 Analog Inputs & Outputs

Analog values must first be converted into suitable range. This task is done by appropriate transducers.

Then the normalized values are converted to binary quantities by ADCs. AI modules always monitor these

binary quantities from FPGA inputs and when there is any change in these values; AI sends a pulse to CI

module and also delivers new values through the bus to it. The architecture of the AI module is simple

and effective. It consists of a register and a comparator. The combinational comparator always compares

the register's inputs with its outputs and if there is any change, it makes a pulse by a flip flop at its output.

Thus right at the moment that register loads new values on its outputs, a pulse will be generated to

inform the CI module to pick up the output of register and AI module as new values. The AI module

monitors inputs at each clock pulse rising edge and there is not any interruption in this. Therefore if we

choose FPGA's clock as 100MHZ, analog quantities would be monitored each 10 ns. [8] The analog values

can be accepted from a SCADA system in two physical modes, such as voltage mode or current mode. In

voltage mode there are several voltage inputs such as mVolts or Volts. These inputs can be as follows

0~150 mV 0~500 mV 0~1V 0~5 V 0~10 V ±150 mV ±500 mV ±1 V ±5 V ±10 V ±15 V. Analog data involve all

continuous, time-varying signals from the field, and are usually thought of in an electrical context;

however, mechanical, pneumatic, hydraulic, and other systems may also convey analog signals. Examples

are voltage, current, pressure, level, and temperature, to name a few. In power systems, the voltage

transformers step down the voltages from kilovolt level to 110 V, and the voltage transducer converts the

physical signals to milliampere current (normally 4 to 20 mA) range which is then used for further

transmission. Current output is preferred for transducers due to the ease of transmission over long

distances and because it is less prone to distortion by interferences. The output of a transducer that

measures the power is shown in Figure 2.6 where the range is from 4 to 20 mA. The threshold value of 4

mA was chosen for two reasons. The first reason is that zero input corresponds to 4 mA, not zero

amperes, which helps to identify a broken wire, which also will manifest as a zero output. The other

reason is that the output curve of the transducer is linear along the 4 to 20 mA portion, as seen from the

figure, which gives an accurate output. Errors are introduced in the measurement due to the saturation of

the current and voltage transformers, which creates a major problem in magnitude and phase angle

measurements. Errors can also occur due to the poor precision levels of the instrument transformers. The

characteristics can deteriorate with time, temperature, and environmental factors. [1] In Figures 2.6, 2.7

& 2.8 a typical schematic of I/O units in a SCADA system, Analog values converted to digital values and

routed to a SCADA CPU and A typical connection of an analog input/output signal to an I/O unit are

depicted.


Figure 2.6: Power scaling in to analog 4-20mA values [1]

Figure 2.7: Analog values converted to digital values and routed to a SCADA CPU

Figure 2.8: A typical connection of an analog input/output signal to an I/O unit


2.2.2 Digital Inputs & Outputs

A digital data signal is a discontinuous signal that changes from one state to another in discrete steps,usually represented in binary, or two levels, low and high. Digital signals include switch positions andisolator and circuit breaker positions in a power system. Digital signals can be directly accessed by theautomation system; however, for physical isolation, all digital signals come into the system via interposingrelays. Interposing relays initiate action in a circuit in response to some change in conditions in that circuitor in some other circuit, as illustrated in Figure 2.9 potential free contacts are used for bringing the datafrom the field. The coupling is electromagnetic from the circuit breaker contacts to the RTU, so that nophysical wiring from the field reaches the control equipment. Errors can be introduced here due to therusting of the contacts or maloperation.

Input signals to this module are divided into two categories, status signals and pulse signals.Status signals stand for state quantities which describe status of relays and other devices. Pulse signalindicates a quantity with its frequency. For example a power meter in a substation may modulate powerconsumption value on its output pulse. All signals will enter FPGA modules without any peripheral circuit.Status signals connected to register and comparator components directly while pulse signal first enters acomponent nominated as Pulse-counter. Pulse-counter counts pulses in a specific time period and infer abinary value, and delivers this value on its output to register and comparator input. In both DI and AImodules, we can generate adequate inputs. Also, it is possible to reconfigure FPGA in order to increaseinputs of DI and AI, or synthesis more than one of these modules whenever needed. A digital signalusually can be used to monitor the state of a switch or a circuit breaker providing status for both statessuch OPEN=true and CLOSE=true. The digital outputs can be triggered sometimes from the digital inputsto implement several logics and proceed with commands and sometimes the digital outputs work like apoint to point command for direct Open/Close of a system. In Figures 2.9 & 2.10 a typical connection of adigital input signal to an I/O unit is depicted and a typical connection of a digital output signal to an I/Ounit.

Figure 2.9: A typical connection of a digital input signal to an I/O unit


Figure 2.10: A typical connection of a digital output signal to an I/O unit

2.2.3 Pulse Signals

Pulse data refer to the periodic information to be acquired from the field. Pulse data captures the

duration between the changes in the value of a signal. This includes the energy data, rainfall, and so forth,

and the outputs could be the stepper motor pulse signals. Also, the pulse energy meters have an offset of

energy produced per pulse. As an example 1 pulse may be equal to 10KWh. So, from the other side a

SCADA system needs a pulse input I/O card and the appropriate configuration in the CPU in order to

display the energy exported correctly. [1]

2.3 SCADA Communication Networks

A robust communication infrastructure is the touchstone of a smart grid that differentiates it from the

conventional electrical grid by transforming it into an intelligent and adaptive energy delivery network. To

cope with the rising penetration of renewable energy sources and expected widespread adoption of

electric vehicles, the future smart grid needs to implement efficient monitoring and control technologies

to improve its operational efficiency. However, the legacy communication infrastructures in the existing

grid are quite insufficient, if not incapable of meeting the diverse communication requirements of the

smart grid. Therefore, utilities from all over the world are now facing the key challenge of finding the

most appropriate technology that can satisfy their future communication needs. In order to properly

assess the vast landscape of available communication technologies, architectures and protocols, it is very

important to acquire detailed knowledge about the current and prospective applications of the smart

grid. [9]


2.3.1 RS485 Serial Network

RS-485 allows multiple devices (up to 32) to communicate at half-duplex on a single pair of wires, plus a

ground wire, at distances up to 1200 meters (4000 feet). Both the length of the network and the number

of nodes can easily be extended using a variety of repeater products on the market. Data is transmitted

differentially on two wires twisted together, referred to as a “twisted pair.” The properties of differential

signals provide high noise immunity and long distance capabilities. A 485 network can be configured two

ways, “two-wire” or “four wire.” In a “two-wire” network the transmitter and receiver of each device are

connected to a twisted pair. “Four-wire” networks have one master port with the transmitter connected

to each of the “slave” receivers on one twisted pair. The “slave” transmitters are all connected to the

“master” receiver on a second twisted pair. In either configuration, devices are addressable, allowing

each node to be communicated to independently. Only one device can drive the line at a time, so drivers

must be put into a high-impedance mode (tri-state) when they are not in use. [10]

2.3.2 TCP/IP & Ethernet/Fiber Networks

Critical infrastructure systems, e.g SCADA and public telephone networks, have traditionally employed

specialized equipment and protocol stacks. Moreover, they were usually isolated from TCP/IP networks.

However, the proliferation of TCP/IP networks, along with the advanced services they provide and the

availability of inexpensive equipment, have caused several critical infrastructure protocol stacks to be re-

designed to use TCP/IP as a foundation for transport and network interconnectivity. [11] There are two

transport layer protocol standards defined over IP – Transmission Control Protocol (TCP) and the User

Datagram Protocol (UDP). However, some applications may not use either of these or any other L4

protocol. Many applications, including many Smart Grid applications, use TCP over IP. Sometimes, IP is

referred to as TCP/IP, inaccurately implying that TCP must be used where IP is used as the layer 3

protocol. UDP is a connectionless and lightweight protocol. It adds little additional overhead to packet

(called datagram in this context) delivery over that of IP. The delivery of a datagram is not guaranteed – it

may be lost in the network. TCP is considered a heavyweight protocol, since it requires a router and link

resources for support of its reliability features. TCP’s header is at least 20 bytes long and includes the

designation and source port numbers, sequence number and acknowledgment, checksum, and other

parameters. [12] Applications based on TCP/IP could be almost everything in a substation automation.

Almost all SCADA features are running on the TCP/IP protocol because it is crucial to confirm the delivery

of every single packet. Such applications could be the I/O signals modules, the protocols used in every

device, the data transfer to the cloud or local HMIs, almost everything. From the other side the UDP is

useful as well, as it is used in the CCTV systems as there is no problem to lose any packet from an image

or from the voice. All these protocols and applications along with TCP/IP protocol are built up in the OSI 7

layer system which consists of all the networking design globally either in WAN or HAN. As depicted in

Figure 2.11 we can see further and extensively what the OSI layer system provides.


Figure 2.11: Diagram of OSI 7 layers

All the TCP/IP communication can be based either in ethernet networks or fiber networks. Usually in

SCADA systems there are both of them consisting of an overall TCP/IP network. Ethernet was first

introduced in SCADA systems though later on with the need of high distance data transmission fiber optic

came to solve this problem. Moreover, the fiber optic networks can solve the problem of high bit data

rate, the noise problem of high frequency cables, and of course the data rate speed. The ethernet uses 4

wires to complete the full duplex communication of the 8 wires that are connected in the RJ45 socket.

From the other side the fiber is using glass cores to transmit the data, 2 glass cores are enough for 100

Gigabits per second data rate. Both of them can be installed in a layer 2-3 switch and provide network

flexibility in a SCADA system network design. The fiber optic requires splice boxes and other material for

splicing, then for the switch an electrical component called SFP is enough to install the fiber network.

Fiber optic networks can be designed either with point to point philosophy or loop philosophy. Fiber optic

networks can go up to 2 kilometers with multi mode glass fiber or up to 40 kilometers with single mode

glass fiber. Finally the ethernet networks are more simple in terms of splicing and can be easily used for

internal SCADA purposes or external till 100 meters distance. In external applications special ethernet

cables are used such as SFTP category 6 (Shielded foil twisted pair) which has more insulation and hard

components to be protected from the outside conditions. Finally, the TCP IP suite consists of the private

networks and the wide area networks as described in the RFC1918. The Internet Assigned Numbers

Authority (IANA) has reserved the following three blocks of the IP address space for private internets:

10.0.0.0-10.255.255.255 (10/8 prefix), 172.16.0.0-172.31.255.255 (172.16/12 prefix) 192.168.0.0-

192.168.255.255 (192.168/16 prefix). All the other IPs consist of the wide area networks. In Figure 2.12 an

overall SCADA network design with Ethernet and Fiber connections is depicted.


Figure 2.12: Overall SCADA network design with Ethernet and Fiber connections

2.3.2 Firewalls Routers & Switches

Firewall

The firewall router in a SCADA system is the most critical component in terms of system security and data

flow stability. A firewall can implement several rules to protect the internal devices of the SCADA system

and stop any vulnerable attacks. It is able to keep the system up and running with the accounts needed

only from the customer side and maintenance operator side and prohibit any unusual traffic. This can be

implemented with VPN clients and strong certificates. Not any port forwarding can be implemented as it

is not a good policy. The network administrator of a power station is responsible to install a firewall to

provide access control and cyber security measures. The firewall should meet all industry and national

standards and security industry best practices. The applications that can be covered from a firewall router

are: Layer 3 Routing, InterVLAN routing and implementation with LACP, Secure connections, VPN and

IPSEC, remote log-in, data traffic flows and users management, data security and secure server-client

connection.

Switch

The switch also forms a very critical component due to several reasons. The most important is that in a

SCADA system’s switch all the devices are connected point to point either with ethernet or fiber. All the


traffic must be routed through this switch and aggregated upon the firewall. So the switch is the core or

the heart of the SCADA network. The switch can either run in layer 2 mode with LACP upon the firewall,

or layer 3 and the firewall could act only as a gateway for internet and security. When a switch is working

in layer 3 mode it handles all the traffic and performs routing rules between the VLANs or between the

networks and the devices. The combination of firewall and switches along as the TCP/IP suite can provide

worldwide data flow and implement several SCADA systems for power stations in order to provide safety

and reliability until the energy reaches the consumer side as depicted in Figure 2.13.

Figure 2.13: Overall data flow for power station until consumer

2.3.4 Servers Historian Platforms & HMIs

A server in a SCADA system provides accurate data acquisition, validation, automated processing and

management delivered in real-time, giving to the users the ability to stay in control of the plant, be

informed on its performance in real time, identify trends, pinpoint the areas of concern and increase its

uptime. A SCADA platform is an open solution available today in the global market for monitoring and

control of solar, wind and storage installations. Using the breed M2M (Machine to Machine) and Server

based technologies, it is a highly accurate, reliable and cost-effective solution, with unique scalability and

expandability features, suitable for all kinds of renewables installations (large rooftops, utility, grid

connected, off-grid PV, Wind, hybrid plants, e.tc), designed to maximize return on investment. It offers

real time monitoring using data streaming techniques applying down to sub second sampling. All primary

data can be presented in real time in logs or in simplified SLD diagrams so as to aid the user to faster

understand and locate the issues. Fully fledged typical SCADA with advanced mimic representation of the

plant is also provided. In addition, the system offers the ability of visual representation of current and

past values of all derived parameters (KPIs) of the power plant. PV power plant overview, alarm and event

handling lists, real time values, and visual signals are some of the display graphics that are included in the

HMI of a SCADA system.

The SCADA Server offers the following functionality:


Handles the connections with the field-deployed controllers

Implements a database that stores the PV and storage plant-related parameters and events

Synchronizes the data between the field-deployed controllers and the database

Provides post-processing capabilities that can be performed on the data stored in the database

Provides notifications via either email or SMS (through an SMS gateway)

Last but not least, presents to the users the site HMI (through a web application).

Figure 2.14 presents the software architecture of the SCADA Server together with its external Interfaces.

The building blocks of the server software are: Database: The database stores all data necessary for the

operation of the solution in a centralized manner for all monitored sites. Synchronizer: that manages all

IP connections with the field-deployed controllers, collects data from them either periodically or event-

driven and relays any user action events from the front-end to the field-deployed controllers.Business

logic: that performs data processing to produce statistics, performance ratios, reports and alarms.

Notification server: that in case of critical alarms notifies selected users via email/SMS. Front-end: that

undertakes the structured presentation of the data to a multitude of users using web technologies. In

Figure 2.14 a SCADA server functionalities architecture is depicted.

Figure 2.14: SCADA server functionalities architecture


2.4 SCADA Communication Protocols

SUPERVISORY control and data acquisition (SCADA) systems are predominant among the electricity grids,

and the emergence of smart grids systems is revolutionizing the energy industry. Reports and research on

SCADA security have shown an increasing number of cyber incidents and attacks targeting critical

infrastructure that use SCADA systems. These incidents and attacks are expected to increase in number

and severity because legacy SCADA systems and protocols were not designed to work in insecure

environments such as the Internet. A SCADA network is composed of various components that range from

hardware (IEDs, PLC, RTU) to standard protocols. [13] A SCADA system is composed of many modules and

devices connected in the same area network or through the wide area network with the need always of

TCP/IP. Apart from that and based on the 7 layers of OSI the SCADA systems in the application layer they

need a communication protocol to exchange information and data between the subsystems of a SCADA.

The communication protocols in SCADA systems is a very critical part of the interoperability and

connectivity between the subsystems that the SCADA consists of. Without the protocols in the application

layer to exchange data there could not be a SCADA system, historians, HMIs platforms, servers calculation

data point, as the protocol is the language used between the machines in a specific system. Some of these

machine language protocols are very complicated and provide security, others are just for a specific field

of measurements and some others are very simple in the connection of 2 devices that are widely used

such as Moodbus. The basic protocols used in the market are the following: Modbus, DNP3.0, IEC61850,

IEC60870, DLMS, OPC UA/DA. These protocols can be used for the following applications: Substation

automation, SCADA data acquisition, Server data flow, HMIs, interoperability with the control centers,

Local SCADA integration with other 3rd party SCADA, Local SCADA integration with other SCADA

subsystems, energy metering, remote control.

2.4.1 Modbus Protocol

Modbus protocol was developed by Modicon in 1979. Modbus is a fundamental communication protocol

that is mostly applied in industries. It is universal, open and an easy to use protocol. New industrial

products such as PLC, PAC, I/O devices and instruments may have an Ethernet, serial or even perhaps

wireless interface, but Modbus is still the preferred protocol. The main advantage of Modbus protocol is

that it runs on all types of communication medium including twisted pair wires, wireless, fiber optics,

Ethernet etc. The Modbus devices have memory, where the plant data is stored. These memories are

divided into four parts as discrete input, discrete coil, input register and holding register. The discrete

input and coil are of 1 bit while input register and holding register are of 16 bit. The most commonly used

communication protocols are as follows: Modbus RTU, Modbus ASCII, Modbus TCP. Modbus RTU is a

point to point open serial communication protocol. It is used to develop Multi-Master Slave / ServerClient

communication between intelligent devices. In Modbus RTU RS-232, RS-422 or RS-485 can be used as a

physical layer based on the specification of the physical layer. Slave ID is one byte address field. We can

connect 256 devices to the Modbus network. Slave ID 0 is used for broadcasting or as a master. The


function code is 1 byte address field. The function code in question tells the slave device what kind of

action to execute. The data field is a single byte address field. Data field consists of one start bit, 8 bit data

and one or two stop bits. [14] In Table 2.1 the Modbus function code list is depicted.

Table 2.1: Modbus function codes table

Function Code Action

01 Read discrete output coils

02 Read discrete input contacts

03 Read analog output holding registers

04 Read analog input registers

05 Write single discrete output coils

06 Write single analog output holding registers

15 Write single analog output holding registers

16 Write multiple analog output holding registers

2.4.2 DNP3.0 Protocol

DNP3 is predominantly used in the electric utility industry. It carries information about power systems

and transmission parameters like voltage, current, active and reactive power etc. DNP3 is a request-

response protocol. Messages are exchanged between Master devices that are clients and Outstations that

are servers. [13] The DNP3 is an open protocol, with two classes of devices defined. The master stations

are usually devices with some processing power and storage of information. The outstation is devices

located in the field (transmission line, substations, transformers) in charge of collecting information from

the sensors and sending the station Master. The DNP3 standard was proposed by IEC (International

Electrotechnical Commission) with simplest implementation, a simplified Protocol of three layers, called

EPA (Enhanced Performance Architecture), uses layered architecture following the OSI model (Open

System Interconnection). The topology of the DNP3 protocol standard offers four types of architectures

that are: point-to-point, multi-point, and tiered data concentrator. In point-to-point Master station

performs communication with a single outstation, already in the multipoint Master station communicates

with various seasons outstation, communication is made point-by-point sequential manner between the

Master station and the outstation. [15]

The DNP3 protocol has three layers i.e. data link layer, pseudo transport layer and application layer. The

DNP3 data link header contains sync information, length of the DNP3 frame, destination address, source

address and CRC information. The payload of the DNP3 frame contains blocks of 16 Byte data followed by


2 Byte CRC. There can be at the most 16 blocks with the last block containing at maximum 10 data Bytes.

[16] In Figure 2.15 a DNP3.0 frame data structure is depicted.

Figure 2.15: DNP3.0 frame data structure [16]

2.4.3 IEC-60870-5-104 Protocol

IEC-60870-5-101/102/103/104 are companion standards generated for basic telecontrol tasks,

transmission of integrated totals, data exchange from protection equipment & network access of IEC101

respectively. There is a growing desire to use the IEC 60870-5 Standards to communicate between

telecontrol stations via Internet services in power telecontrol systems. [17] A companion standard called

IEC 60870-5-104 has been published by the IEC for this purpose. The IEC104 protocol, as called in the

market, is a very reliable and flexible protocol for substation automation, monitoring of power analyzers

and SCADA data aggregation of the RTUs. The IEC104 has the following features: On-demand

transmission, Spontaneous transmission time tagged, Direct command transmission (with select before

operate), Clock synchronization and File Transfer. The IEC104 protocol has Address Space of Common

Address of ASDU: 1..65535 and Information object address: 1..16777215. The ASDU is the RTU number

and the IOA is the object data point number. The message types offered from IEC104 for data points are

as follows: Commands: Single Command, Double Command, Setpoint, Regulating step command.

Measurements: Single indication [1 Bit] with quality, Single indication [1 Bit] with quality and time tag,

Double indication [2 bit] with quality, Double indication [2 bit] with quality and time tag, Measured scaled

value with quality, Measured scaled value with quality and time tag, Measured normalized value with

quality, Measured normalized value with quality and time tag, Measured floating point value with quality,

Measured floating point value with quality and time tag, [32 bit] with quality, [32 bit] with quality and

time tag, Counter value with quality, Counter value with quality and time tag, Step position value with

quality, Step position value with quality and time tag, Event of protection equipment with quality and

time tag. In Figure 2.16 a Data architecture with IEC104 protocol is depicted.


Figure 2.16: Data architecture with IEC104 protocol

2.4.4 IEC-61850 Substation Automation

IEC61850 is a common communication standard in power systems, which is proposed by the International

Electrotechnical Commission and widely used in smart grid now. The standard is designed for the

equipment and communication service in substation and provides principles for function modeling and

data modeling according to object-oriented methods. IEC61850 is featured of hierarchical information,

independent information model and communication protocol, self-description of data, object oriented

modeling. [18] IEC61850 SA (Substation Automation) put a SCADA (Supervisory Control and Data

Acquisition), RTU (Remote Terminal Unit), control and protection relays consolidation and their

functionalities into a single system taking into account the digital communication and the interaction

among themselves. The arrival of IEC61850 standard leads main manufacturers in the SA area to adopt

this standard, due to the possibility of Ethernet and TCP/IP (Transmission Control Protocol/Internet

Protocol) providing the great speed and quality of service. One of the great benefits from the IEC61850

standard was the real time communication for high priority messages. Applications now can have a very

good solution from IEC61850 GOOSE (Generic Object Oriented Substation Event) messaging. In fact, the

exchange of GOOSE messages requires a very strict performance requirement, such as the need for a

worst case 4 ms application-to-application delay requirement that we have to surely fulfill the

requirement. [19] In Figures 2.17 and 2.18 Data modelling with IEC61850 protocol is depicted.


Figure 2.17: Data modelling with IEC61850 protocol [20]

MMXU represents current; XCBR represents Switch position; PTOC represents over current fault; and

CSWI represents control of Switch. [20]

Figure 2.18: Data modelling with IEC61850 protocol [20]

There are multi levels of FA architecture. Figure 2.16 shows a typical FA architecture which has three

levels: Terminal Level, Slave Station Level and Master Station Level. Terminal Level mainly includes

devices such as Feeder Terminal Unit, Distribution Terminal Unit and Transformer Terminal Unit. Terminal

Level and Slave Station Level of FA architecture is similar to Substation Automation Architecture. Master

Station Level is a special one, e.g. it connects more than one Slave Station. If it wants to represent the real

substation, then it needs to extend the IEC61850 standard to cover more than one substation. [20]


2.4.5 DLMS Energy Metering

The Device Language Message Specification (DLMS) is an application layer specification which is designed

such that it does not depend on supporting layers. It also specifies data exchange procedures and data

access services for the smart devices. Moreover, it also provides interoperability among metering and

reading devices, even their models or vendors are different. The CO Companion Specification for Energy

Metering (COSEM) defines data models and functional processes in an object oriented notion for the

DLMS layer. An object consists of two important parts, which are attributes and methods. According to

COSEM, every object is instantiated from an interface class. The first attribute of all objects is a logical

name that is defined by OBIS code. It is the index for referring to an object. Moreover, the logical name

clearly indicates what those objects are. All the smart devices conform to DLMS/COSEM standard which

specifies an application layer for metering. An advantage of this standard over others is that it supports

many communication technologies such as infrared, ZigBee, PLC, TCP/IP, GPRS, UMTS, etc. Furthermore,

its interface models do not depend on lower protocol layers. In this paper, a PC-based data concentrator

unit employs the DLMS/COSEM standard with HDLC as the data-link layer. For simplicity, a GSM modem is

employed as a medium in the physical layer. [21] In Figures 2.19 and 2.20 a DLMS Communication profile

is depicted.

DLMS ZMQ vH03 - Reference data points mapping of a DLMS Meter

<ShortNames for HDLC>: (<OBIS CODE>) <Object Definition>

0x1CE0 : ( 1-1:1.8.0) Energy +A

0x1CE0 : Logical Name (OBIS ID) 1-1:1.8.0

0x1CE8 : Value 23132614

0x1CF0 : Unit and Scaler -1|30|active energy

0x1D98 : ( 1-1:2.8.0) Energy -A

0x1D98 : Logical Name (OBIS ID) 1-1:2.8.0

0x1DA0 : Value 3552288

0x1DA8 : Unit and Scaler -1|30|active energy

0x1A18 : ( 1-1:5.8.0) Energy +Ri

0x1A18 : Logical Name (OBIS ID) 1-1:5.8.0

0x1A20 : Value 5162897

0x1A28 : Unit and Scaler -1|32|reactive energy

0x1AC8 : ( 1-1:7.8.0) Energy -Ri

0x1AC8 : Logical Name (OBIS ID) 1-1:7.8.0

0x1AD0 : Value 129617

0x1B10 : Unit and Scaler -1|32|reactive energy

0x1B78 : ( 1-1:6.8.0) Energy +Rc

0x1B78 : Logical Name (OBIS ID) 1-1:6.8.0


0x1B80 : Value 1290609

0x1B88 : Unit and Scaler -1|32|reactive energy

0x1C28 : ( 1-1:8.8.0) Energy -Rc

0x1C28 : Logical Name (OBIS ID) 1-1:8.8.0

0x1C30 : Value 0

0x1C38 : Unit and Scaler -1|32|reactive energy

Figure 2.19: DLMS Communication profile [22]

Figure 2.20: Extensive DLMS Communication profile [23]


CHAPTER 3

3. SCADA Based Smart Grids

3.1 SCADA & Smart Grid Architecture

The existing grid architecture has been continuously updated in several countries, most of them in the

North of Europe, Canada and China as the smart way to deliver the energy demand is getting more and

more important. The energy should be generated and delivered in such a smart way that we can meet the

demand exactly as the load, we don’t create any grid HV transmission fluctuations, we have reduced

losses, and all of them in respect of the environment always. The concept is as explained above, so in

order to go more and more close to that all the old equipment and installations must go through an

update, with smart components. The smart components are equipment related with power generation

such as generators, solar inverters, advanced gas turbines, battery storages. Other equipment has to do

with the transmission and the distribution network such as flexible AC transmission systems, TCSC &

UPFC, to support the HV lines with better performance. The smart meters and the smart protection relays

will play a significant role as well. Additionally, communication infrastructure and data lines must have an

update in terms of security and technology evolution such as the upcoming IoT. The IoT technology will

play a significant role on this as it offers several advantages with long distancing wireless technology and

long battery life of IoT gateways. We can connect meters or other devices from long distances in the

transmission network. So, the grid architecture and equipment as long as the power generators itself has

to be updated with the smart ones, this is the long way to Smart Grid Concept.

3.1.1 Smart Infrastructure Analysis

The whole smart grid concept shall be based on the new smart infrastructure of the grid transmission

lines and power generation plants as well as the intelligent data networks, including remote login with

security, remote control, data cloud storage and historian. These networks will be based on ethernet,

fibre and internet connections of the latest applied technologies. The distribution network as well, has to

be updated to deliver in a smart way the energy demand. About the grid transmission, we may have

several changes on the way the transmission lines are loaded, the power control at the point of common

coupling and the smart meters installed at those crucial positions as well as the protection relays. The

following updated sections are part of the Smart Grid Concept. In Figure 3.1 a Smart Grid Infrastructure

end to end is depicted.


HV Transmission Lines

MV Distribution Lines

LV Consumers Lines

Power Generation (all included with renewable energy and non renewable)

Energy Market

Electric Vehicles

Smart Meters and protection relays (Energy Metering & Power Analyzers)

ICT infrastructure (cloud computing, data logging, historian, IP security)

IoT technology

Figure 3.1: A Smart Grid Infrastructure end to end [24]

3.1.1.1 HV Transmission Lines Smart Infrastructure

At the HV Transmission network we can have the following updates in order to serve the smart grid

concept for energy transmission:

Fast acting high voltage and current protection relays with auto reclosing.

Smart Transformers with many points of control and crucial alarms.

Smart meters in crucial points with IoT technology or direct fibre network.

Flexible AC transmission systems such as Thyristor Controlled series Capacitors TCSC or UPFC,

Unified power flow controllers for line charging, impedance and active/reactive power flow

control.

AVR control installed, automatic voltage regulation, through a Scada System in power plants.

Active/Reactive power control installed through a Scada System in power plants.

Evolved substation automation with Scada Systems for Transformer Protection and High Voltage

cells.


A SCADA system can be on top of these mandatory evolutionary things, and take the overall control of an

HV transmission line system with several controllers in the field and many other smart components

connected in the same LAN/WAN network.

3.1.1.2 MV Distribution Lines Smart Infrastructure

The medium voltage distribution system is coming directly after the transmission line systems as the

system to serve the energy demand in the local areas. The system is working through step down

transformers in the areas around that have to be fed. There are 2 smart components added in these MV

sections to help in the smart grid concept. The auto-reclosers for MV areas with power generation and

the Mini capacitors.

Mini Capacitors

The MiniCaps allow the distribution networks to benefit from this technology in a reliable and

economically viable way. MiniCap in the distribution network eliminates the steady-state voltage drop

along the distribution line as well as the voltage fluctuations associated with start-up and operation of

large loads at the feeder end such as saw mills, rolling mills, crusher motors, mining loads, ski lifts,

pipeline pumping stations and large induction motors. [25]

The MiniCaps can help the Smart Grid concept as follows:

Increased power transmission capability through decreased total line reactance

Improved voltage profile along the line

Reduced line losses

Improved continuous and instantaneous voltage regulation and reactive power balance

Easier starting of large motors

Increased power factor at the utility source

Improved load sharing along parallel lines

Reduced voltage fluctuations (flicker) [25]

Auto-Recloser

One of the ways to maintain power system reliability is by maintaining transmission lines reliability using

Auto-reclose (AR). If fault occurred in a transmission line, then the relay will order the transmission line to

open. If the fault is temporary then after a few milliseconds the transmission line will close again

automatically due to implementation of AR. Auto-reclose employed in power systems could be Single Pole

Auto-reclose (SPAR) and Three Pole Auto-reclose (TPAR) depending on system necessity.

Auto-recloser technology consists of a control and communication cubicle based on microprocessors

providing the following functionalities: Directional overcurrent, distributed generation interconnection,

earth fault relay, auto reclosing relay, renewable energy integration, feeder protection, instantaneous

metering, event log, demand logger and remote terminal unit (RTU) for remote control. Automatic circuit


reclosers are designed for use on overhead distribution lines as well as distribution substation

applications for all voltage classes up to 15kV, 27kV and 38kV respectively. Auto-reclose relay is an

important relay used to re energize a line after the line was tripped by the main protection relay due to

fault occurrence. Failure of auto-reclose relay to reenergize the line will make power can’t be transmitted

through the line and the power system will be in stress condition. [26] - [27]. In Figure 3.2 a Smart Grid

Recloser protection is depicted.

Figure 3.2: A Smart Grid Recloser protection

3.1.1.3 LV Delivery Lines Smart Infrastructure

This section could be combined with the Smart meters installation along the consumers’ lines. This a key

installation for direct load demand as long as with MV distribution lines. At the same time, the lighting

structure can be equipped with the latest technology LED lamps and IoT wifi microchips for direct

information of energy consumption and better performance. The low voltage consumers can have direct

access to their daily consumption profile and they can participate in the LV to MV distribution lines with

net metering with their own production. The net metering procedure offers to the LV client the ability to

produce energy and equalise the energy produced with the energy consumed every billing period. That

way, sometimes the LV consumers don't pay any energy bill. Smart metering will play a significant role on

this.


3.1.2 Smart ICT Infrastructure

Supervisory control and data acquisition (SCADA) systems are a subset of the Industrial Automation and

Control Systems (IACS) that monitor and control Essential Services such as power grids, water distribution

facilities and automated factories. They include sensors and actuators, Programmable Logic Controllers

(PLCs) / Remote Terminal Units (RTUs), Human-Machine Interfaces (HMI)s and all the related servers,

arranged in several network segments and levels. Different types of communications, using specific

SCADA network protocols, occur between those levels, both vertically and horizontally. [28] Based on

that, critical commands are being sent through the control centers for power plants. Data logging also is

very critical as live data are being sent to the stock exchange energy market about the capacity or

availability of each plant. So all these data historians, cloud data, commands or live market data are very

important not to be attacked. The IP security technology will play a significant role. The smart ICT

infrastructure will be based on local servers for secondary data logging, cloud servers for primary data

logging, in order to have back up data of the power plants.

3.1.2.1 IP Security

IP security is the most important thing that must be developed in the Smart Grid World. There are several

techniques and quality of service standards to maintain the data stability and network connectivity. Some

quality assurance services are the MQTT service from the RTUs to the server as a protocol needed for

data transmission. Additionally, the ssh key authentication or unique key exchange can protect all the

field RTUs from any undesirable attack and let only authorised computers for remote login. Network

security is not only just keeping a perfect firewall setting with computers; rather this is the biggest matter

of how to save and access sensitive data in and out of the computer system around the internet. The

absolute access of computers is to follow instructions and perform tasks without asking any question to

us. Through the internet, security issues come into computers through some kind of instructions only.

Even these instructions can ask our computer to perform delete, copy and transfer to an unauthenticated

address or to hide any sensitive data and even it may order computers to perform self destruction too.

Network Security is the term “A policy needs to articulate this and enforce how to practice with these sort

of problems with well defined and defending solutions uniformly”. Applying security in networks is an

enormous matter nowadays. So many algorithms are doing security with more concepts. The matter is

how to apply security algorithms as a rule to make computers learn by itself. Artificial intelligence is doing

a vital role in making rules for the learning process. Rule based machine learning techniques are using

existing data sets as input to produce expected output in supervised machine learning concepts. Whereas

unsupervised machine learning from every hit occurs. Based on the gathered data sets and behaviors

from the frequent collection of activities, unsupervised. [29,30] In Figure 3.3 a Network Security

Architecture is depicted.


Figure 3.3: Network Security Architecture – TCP/IP Model. [29]

3.1.2.2 IP Security & IoT

The widespread use of the internet is causing more cyber-attacks using IP spoofing. The security for IoT

devices to prevent IP spoofing involves validating the source address of received IP packets at the

gateway. This is required to prevent an unauthorized user from using IP address as source address and

flooding packets to the gateway there by using the bandwidth allocated to authorized users. A solution

could be a pool of IP address assignment to smart IoT devices (which communicate using TCP/IP) and

validation of source IP address in the received IP packets from the IoT Device at the Gateway device. IP

spoofing involves flooding of IP packets by unauthorised users by replicating the source address of

authorised users. The internet devices (routers) examine only the destination IP address and source

address is generally not validated. In the IP spoofing scenario destination has no knowledge of who the

real user is and when it sends packets back to the source IP address and the real user will not receive the

expected data. Also, the unauthorised users can hog the network which will deprive the real users of the

network bandwidth. [31] In Figure 3.4 an IP communication between SMart IoT devices is depicted.

Figure 3.4: IP Communication between Smart IoT devices and Gateway. [31]

3.1.2.3 Cybersecurity and access control

Besides the firewall, communications between the site and remote Control Systems are protected by

proven, industry standard, best practice methods. Furthermore, SCADA systems must be certified with


ISO 27001, the global information security management standard, conforming to the latest global security

protocols and technologies adopted across the platforms and systems portfolio. ISO27001 certifies the

adherence of related operating procedures of information and data management as well as day to day

platform operations to ensure protection of sensitive, mission critical infrastructure.

Authorization and Authentication: SSH key management lets administrators authorize access to specific

hosts, managing control and visibility to manage remote host authorization centrally, with built-in

auditing for compliance. Access control is based on associations between users, hosts, remote users and

remote groups. Associations can be as coarse or fine as needed. Security and Audit: Full audit trail history

of permissions authorization, removal, delegation is logged automatically. All SSH logins on managed

hosts are tracked and logged centrally along with all related metadata. Server-side security is configurable

to either local or LDAP. Clients communicate with servers using HTTPS. Data in Transit protection: SSL-

encrypted traffic between all MSSU/PSSU/PPC and Local SCADA / Historian Servers or Cloud SCADA Public

key infrastructure management enables both-way end point verification. (MSSU Main Substation Unit /

PSSU Peripheral Substation Unit) The SCADA Control System should include a robust access control

process, offering also additional capabilities for two factor authentication. By using two-factor

authentication, the solution creates an additional layer of protection against anyone seeking to obtain

unauthorized access. In Figure 3.5 a Central Management System Secure Redundant Controller Access is

depicted.

Figure 3.5: Central Management System Secure Redundant Controller Access


3.1.3 Smart Infrastructure on Power Generation

The smart infrastructure on power generation consists of smart meters, smart circuit breakers and

protection relays, smart FACTS, new innovative solar inverters, evolutionary wind generators, advanced

gas turbines and other smart components used in the power generation that are included in the electrical

circuits.

3.1.3.1 Flexible Alternating Current Transmission Systems (FACTS)

In power systems, the flexible alternating current transmission system (FACTS) devices, a technology

based on power electronics, have an important role for improving transmission system reliability,

management, dynamic control of real and reactive power at buses and quality of power supply for

sensitive industry. FACTS proposes an opportunity to improve, stability, and power transfer capability of

AC transmission systems. FACTS devices used for Grid efficiency are some of the following, Static VAR

Compensator (SVC), static synchronous series compensator (SSSC), unified power flow controller (UPFC),

static compensator (STATCOM), thyristor controlled Series Reactor (TCSR) and thyristor controlled series

capacitor (TCSC). The FACTS is a technology of smart controllers and electrical high voltage components

equipped with IGBTs mosfets used on power stations, transmission stations and transmission lines

providing the following: [32]

Simultaneous Dynamic Control of Active and Reactive Power

Dynamic Voltage Control in transmission and distribution

Power Quality Improvement in transmission and distribution

Increasing grid transmission capability

Reducing fault currents

Active filtering of harmonic currents

Reducing transmission losses

Minimizing line circuit breaker stress

Meeting the increased energy demand [32]

In Figure 3.6 a UPFC Structure for HV Transmission Lines Support is depicted.


Figure 3.6: UPFC Structure for HV Lines Support [33]

3.1.3.2 Smart PV Inverters

Smart Inverters (previously known as Advanced Inverters) represent a paradigm shift in the integration of

Distributed Energy Resources (DER). These inverters can perform multiple functions involving both

reactive and real power control in addition to their main task of converting DC power to AC power. These

functions include voltage regulation, power factor control, active power controls, ramp-rate controls,

fault ride through, and frequency control, etc. Various grid support functions offered by smart inverters

are presently being demonstrated on real distribution and transmission systems in different countries, to

motivate their rapid deployment. [34] There are three common grid interactive PV systems: the

centralized inverter system, the string inverter system and the module integrated inverter system, also

known as the micro inverter system. The major part in each system is the conversion stage and its

characteristics dominate the behavior of the overall solar PV system. [35] The smart inverters can be used

for several strategies when producing in a solar plant, and the main thing is that they are fully controllable

via the software installed, and the hardware that supports this smart technology. The smart solar inverter

can either absorb or produce reactive power when needed, Q at night or automatic voltage regulation, or

perform frequency control through active power. This feature is very useful when massive solar power

plants are connected in the high voltage network and they cannot export continuously but they have to

follow commands of the control center depending on what the PPC company requires each day. In Figures

3.7 & 3.8 a Smart PV Inverter control scheme is depicted.


Figure 3.7: Smart PV inverter control scheme [33]

Figure 3.8: Flow chart of Smart PV inverter control [28]

Modes of the solar inverter are: the full PV mode (M=0) full active power generation, the Partial

STATCOM (M=1) mode both active and reactive power generation and the full STATCOM mode (M=2)

which is the full reactive power generation for AVR.


3.1.3.3 Next Generation Gas Turbines

Gas turbine engines derive their power from burning fuel in a combustion chamber and using the fast-

flowing combustion gases to drive a turbine in much the same way as the high-pressure steam drives a

steam turbine. A simple gas turbine consists of three main sections: a compressor, a combustor, and a

power turbine. The gas turbine operates on the principle of the Brayton cycle, where compressed air is

mixed with fuel and burned under constant pressure conditions. The resulting hot gas is allowed to

expand through a turbine to perform work. One big advantage of gas turbines is their fuel flexibility. They

can be adapted to use almost any flammable gas or light distillate petroleum products such as gasoline

(petrol), diesel, and kerosene (paraffin) which happen to be available locally, though natural gas is the

most commonly used fuel. Crude and other heavy oils can also be used to fuel gas turbines if they are first

heated to reduce their viscosity to a level suitable for burning in the turbine combustion chambers. Gas

turbines can be used for large-scale power generation. Examples are applications delivering 600 MW or

more from a 400 MW gas turbine coupled to a 200 MW steam turbine in a cogenerating installation. Such

installations are not normally used for baseload electricity generation, but for bringing power to remote

sites such as oil and gas fields. They do however find use in the major electricity grids in peak shaving

applications to provide emergency peak power. Low-power gas turbine generating sets with capacities up

to 5 MW can be accommodated in transportation containers to provide mobile emergency electricity

supplies which can be delivered by truck to the point of need. [36-37] Power generation turbines for the

electrical grid are generally used in one of two different configurations: (1) combined cycle to meet base

load power demand, and (2) simple cycle to meet transient and peak power demand. A combined cycle

power plant employs both gas turbines and a steam turbine together to produce up to 50 percent more

electricity from the same fuel than a simple cycle plant. The waste heat from the gas turbine that escapes

through the exhaust in a simple cycle gas turbine is routed to a heat recovery steam generator, where the

heat of the exhaust gas is used to generate steam for the steam turbine. In a combined cycle

configuration, two gas turbines are often paired with a single steam turbine. Combined cycle power plants

are generally designed for base-load (full-power) operation because they lack the agility to ramp up and

down rapidly. It is challenging to efficiently integrate a plant designed for base load with renewable

energy sources that provide intermittent power. Although the plant efficiency of a gas turbine operating

in simple cycle is less than a gas turbine operating in combined cycle, a gas turbine operating in simple

cycle has far greater operational flexibility in terms of its ability to accommodate swings in power while

operating under partial load. The five power generation goals below are relevant to simple cycle and

combined cycle gas turbines. Each of these goals directly addresses a key criterion used to select

aggressive goals for gas turbine development: Efficiency, Compatibility with Renewable Energy Sources,

CO2 Emissions, Fuel Flexibility, Levelized Cost of Electricity. [36-37] In Figures 3.9 & 3.10 a simple and

combined cycle gas turbine system is depicted.


Figure 3.9: Simple gas turbine system [36]

Figure 3.10: Combined Cycle gas turbine system [36]

3.1.3.4 Battery Energy Storage Systems (BESS)

Energy storage systems provide what is exactly needed within the last decades increasing penetration of

renewables in the electricity mix. With storage systems, energy can be stored when not needed, can be

generated on demand at the time it is required, and generation output can be accurately controlled to

serve grid requirements. Energy storage is the key means to improving the flexibility, economy and

security of the power system. It is also important in promoting new energy consumption and energy on

the Internet. Therefore, energy storage is expected to support distributed power and micro-grid, promote

open sharing and flexible trading of energy production and consumption, and realize multi-functional

coordination. In recent years, with the rapid development of the battery energy storage industry, its

technology has shown the characteristics and trends for large-scale integration and distributed

applications with multi-objective collaboration. As a grid-level application, energy management systems

(EMS) of battery energy storage systems (BESS) were deployed at utility control centers as an important

component of power grid management in real-time. Based on the analysis of the development status of

BESS, introducing its application scenarios such as reduction of power output fluctuations, accordance to

the output plan at renewable energy generation side, power grid frequency adjustment, power flow

optimization at power transmission side, and distributed and mobile energy storage system at power


distribution side. [38] The BESS system can serve the stability of the grid frequency in principle, and

export active power within 600 msecs. This flexibility is very important and plays a key role in grid

stabilization. A BESS system consists of several battery modules connected to each other creating a dc

string which is protected through a DC circuit breaker. Then, this dc string is connected to a well known

DC to AC converter or inverter with technology more or less the same as the pv inverters. Then from the

AC inverter module and through a transformer the BESS system injects into the grid. The cost of battery

energy storage systems (BESS) is steadily decreasing and they are able to provide very fast response

times. BESS have therefore been attracting a great deal of attention in recent years. Although BESS can be

used in different applications to provide a range of services to the power system, the provision of

frequency control is the most cost-effective service for the BESS operator in the current ancillary service

markets. [39] In Figure 3.11 a BESS system is depicted.

Figure 3.11: Battery Energy Storage System

3.1.3.5 Wind Generators

Wind energy has experienced a great increase in the last few decades. The technology has evolved

significantly while the cost of power generated has decreased. The objective of the EEC in 2020 is to

achieve 12% of all energy produced from wind power. This development rises from a global need for

cleaner energy and a move away from fossil fuels. [40] More recently, the increasing size of the turbines

and the greater penetration of wind energy into the utility networks of leading countries have

encouraged the use of electronic converters and mechanical actuators. These active devices incorporate

extra degrees of freedom into the design, allowing for active control of the captured power. Static

converters, used as an interface to the electric grid, enable variable-speed operation, at least up to rated

speed. Due to external perturbations, such as random wind fluctuations, wind shear and tower shadows,

variable speed control seems to be a good option for optimizing the operation of wind turbines. [41] Most

modern turbines incorporate onboard supervisory control and data acquisition (SCADA) systems for

control and monitoring. As these systems are already installed as standard, wind farm operators are


increasingly interested in better exploiting this data for condition monitoring, fault diagnostics, and fault

prognostics. [42]

Technical Details of Wind farm generators

The wind turbines can be classified based on their orientation and their axis of rotation, into horizontal

axis wind turbines (HAWT) and vertical axis wind turbines (VAWT), which can be installed on the land or

sea. The HAWT features higher wind energy conversion efficiency due to the blade design and access to

stronger wind, but they need a stronger tower to support the heavy weight if the nacelle and its

installation cost is higher. The VAWT have the advantage of lower installation; however, their wind energy

conversion efficiency is lower due to the weaker wind on the lower portion of the blades and limited

aerodynamic performance of the blades. Another form to classify the wind turbines is by speed control

methods and power control methods. The wind energy conversion is divided into fixed and variable

speeds. As the name suggests, fixed speed wind turbines (FSWT) rotate at almost a constant speed, which

is determined by the gear ratio, grid frequency, and number of poles of the generator. The maximum

conversion efficiency can be achieved only at a given wind speed, and the system efficiency degrades at

other wind speeds. The wind turbine is protected by aerodynamic control of the blades from possible

damage caused by high wind gusts. On the other hand, variable speed wind turbines (VSWT) can achieve

maximum energy conversion efficiency over a wide range of wind speeds. The turbine can continuously

adjust its rotational speed according to the wind speed. In doing so, the tip speed ratio which is the ratio

of the blade tip speed to the wind speed can be kept at an optimal value to achieve the maximum power

conversion efficiency at different wind speeds. [43]

3.1.3.6 Smart Metering

Smart meters are powerful tools which fundamentally change the operation of power grids. In addition to

performing the functions of a traditional meter, smart meters can be used as sensors across the entire

distribution grid. When an Advanced Metering Infrastructure (AMI) is in place, smart meters can measure

and record actual power usage during a day at a certain time interval. These collected data are sent to a

central data management system over a secure network via wireless communication. In addition, these

sensors can be used by the utilities to detect fault and send outage or restoration notifications. Use of this

information allows the utilities to provide more reliable power supply. It also allows better planning,

operation, and faster outage response of the grid. These meters also allow increased resolution of data on

various measurement parameters across the grid and these data can be used by utilities for the following

applications: Reduce energy costs - Increase equipment utilisation - Comply with environmental and

regulatory requirements - Improve power quality and reliability - Improve customer satisfaction and

retention - Monitor and control equipment - Integrated utility metering - Allocate or sub-bill energy costs

to departments, processes or tenants. Moreover it provides,

Faster outage detection, response, and restoration by providing data to the field operations

timely.


Keeping customers better informed about the status of the power grid. Utilities can communicate

relevant information, e.g., cause of outage, field-estimated restoration time, and public safety

notice.

Improving resilience against disruptions, reducing potential outages, reducing frequency and

duration of outages by enhancing accuracy of the grid asset planning and management. [44]

Figure 3.12: Smart Meter front view and back view with SCADA communication card


3.2 SCADA & Smart Grid in Renewable Energy Generation

The concept in large scale power plants in Renewable Energy Generation is hard related to power control.

This is true for several reasons. Firstly because large scale power plants are connected to the high voltage

transmission lines which is the crucial part of the grid. So, remote power control should be always

enabled to avoid several possible power fluctuations due to sun or wind vast changes that may cause grid

instability. Another reason is the need of the aggregated control from the maintenance operators to shut

down remotely with ramp up/down the whole power plant. Also, another reason is that the large scale

power plants perform and serve several services into the grid so in that case the power plant is connected

to a Control Center. With this feature, the power plant can participate in the spot energy market for MWh

bidding or perform automatic voltage regulation and other services for the grid.

3.2.1 SCADA & Smart Grid in PV Power Plants

As the portion of electricity that is produced by solar photovoltaic (PV) systems increases, it is important

for PV systems to help provide many of the grid support functions that are traditionally performed by

conventional rotating machines. Historically, electric power system operators have seen photovoltaic (PV)

power systems as potential sources of problems due to intermittency and lack of controllability. However,

the flexibility of power electronic inverters allows PV to provide grid friendly features including volt-VAR

control, ramp-rate control, high-frequency power curtailment, and event ride-through. These

technologies offer power quality improvements and enable wider penetrations of PV systems.

Commercially available smart PV inverters can further provide frequency down-regulation by curtailing

power, but they are unable to provide true frequency regulation through active power control (APC)

because they are unable to increase power on command. The development of inverters capable of APC

for primary and secondary frequency regulation without the need for energy storage has the potential to

transform the way grid operators view high PV penetration levels. [35] In PV plants the control system

software is very crucial for plant’s power efficiency and stability as well as the maintenance. In such a

way, that the power control software must be very intelligent and responsive within seconds. This can be

achieved by installing fiber optic networks between the field stations connected with the main station and

a good internet connection for data exchange with the control center and data clouding. Also, it is very

important that the solar inverters installed are very responsive in power setpoints and the protocol of the

inverter is updating at least every second. Additionally and the most significant is the vast updating

feature at the main control meter used for the power control setpoints in closed loop. There is a need at

least 500msecs in protocol data update.

The controls of a PV plant to serve the grid in an efficient way are the following:

Active Power Control (APC)

Reactive Power Control (RPC)

Power Factor control (related to RPC)


Automatic Voltage Regulation (AVR) (related to RPC)

Frequency Support (related to APC)

In Figure 3.13 a SCADA system for PV Power Control is depicted.

Figure 3.13: SCADA System for PV Power Control

Though in SCADA systems in order to achieve the desired output setpoint in all control methods above,

there are a lot of hardware components that have to be involved and co-operate with each other. The

most important is the software and the programming that is running inside the SCADA RTUs. Moreover,

the material needed to be installed has been explained in the SCADA fundamentals chapter. A graphic

data flow diagram will be presented to give a complete view on how we achieve the smart grid concept

with solar plants control. In Figure 3.14 the components of a SCADA system are depicted to achieve the

Smart Grid concept.


Figure 3.14: SCADA System data flow for PV Power Control

The schematic above describes how the overall power control will be accomplished in a large scale PV

project. There are 2 modes: SCADA in Remote, where the setpoint arrives at the PPC controller through

the Control Center in a specified protocol with specified signals. SCADA in Local, where the setpoint

either arrives at the PPC controller through the server cloud or the local plant data logging server. The

local RTUs in each station are connected through the fiber network to the PPC controller, so they can be

instructed to execute several commands to the solar inverters. The solar inverters are monitored from the

local RTUs in each station. In that way the data path goes as follows: at both modes the respective power

setpoints pass through the PPC and through the fiber network at the local RTUs in each station and the

command is executed through a specific protocol to the inverters. Each inverter has a protocol mapping

described in the operation manual sent by the manufacturer. This is very important as it is the guideline

to implement the control settings in the RTU’s software. A simple data path for the control commands will

be like this: Remote mode: The grid operator calls the control center or sends an email -----> The control

center executes the power control commands (P,Q) through the communication channel set up in the PV

power plant with the PPC RTU, usually through a VPN -----> The PPC executes the command to the local

stations’ RTU in closed loop with the feedback of the power quality meter installed at the output of the


high voltage transformer -----> The local stations’ RTUs execute the commands (P,Q) through the

inverters’ protocol directly to the inverters. Same at SCADA local mode.

The concept with SCADA Local/Remote

Each SCADA configured for power control setpoints must be flexible in terms of modes available. If the

maintenance operator has a need of stopping the whole PV plant then the SCADA must be switched in

Local mode in order not to cause any conflict with the Control Center. Same in the Remote mode, if the

SCADA is listening only to the Control Center then nobody from the Local HMI screens or from the cloud

can operate the PV in terms of power setpoints or circuit breakers on/off or inverters on/off. The user

may configure the PPC for either Local or Remote operation using the PPC Local Mode parameter. When

in Local mode (PPC Local Mode set to 0) control may be performed only by the Plant Operator, when in

Remote mode (PPC Local Mode set to 1) control operations may be performed only by the Grid Operator

systems. In grid integration cases where the Grid operator requires automatic PPC control through grid

operator RTUs and SCADA, the PPC Mode is set to Remote Mode and normally no change should occur

for reasons other than maintenance or grid operator instructions. In cases where PPC is not controlled

automatically by the grid operator systems, then the PPC Local Mode is enabled and the user may

perform any control and monitoring operations through the PPC user interface.

The concept with the Control Center

It is used almost exclusively in all large scale PV power plants because the grid operator of each country

cannot take the responsibility to control the PV. That’s why there are a lot of private companies with data

centers that have the responsibility to accept via email or phone calls the PV power setpoint sent by the

Grid Operator and execute them via the communication channel explained above.

The available PV controls through the SCADA

The SCADA can be configured to apply controls in any point of the PV plant depending on the software

running in the RTUs. Also, it can perform logics that have specific inputs and outputs controlling several

devices in the project. The available PV controls usually used in a large scale PV is: Inverters ON/OFF,

Circuit Breakers ON/OFF, Power Control (all modes), Capacitor banks or STATCOMs ON/OFF, Tracker

System Control.

The available Power control services through a SCADA

In Figure 3.15 we can see all the available control services provided from a SCADA platform and perform

PV power control either from a local HMI as we can see below or through a protocol and a control center

as mentioned above. The control services are : Active power control with ramp up/down feature, Reactive

power control, Power factor control (cosphi) & voltage regulation with reactive power.


Figure 3.15: SCADA System PV Power Control Services

3.2.1.1 PV Active Power Control (APC)

Overview

The Active Power Control (APC) application is part of the Power Plant Control (PPC) applications. It is used

to set a plant's export active power or regulate the grid frequency by controlling the active power

exported by its inverters. The application of the SCADA system may control the plant's inverters either

directly or through other intelligent devices, called in general "slave PPCs". If this is the case, then all

following references to "inverter" should be changed to "slave PPC". The control functions provided by

the application are: Direct (setpoint) active power control, Active power reserve, Active power ramp

rate control, Frequency control, Apparent power limitation. The active power control service named as

APC can execute any setpoint based on the maximum setpoint that the PV plant can execute, related to

the maximum AC power of the inverters. It functions always in closed loop mode with PID control and the

feedback is coming through the PQM. The PQM should be very fast in terms of protocol update at least

500msec (applies to all countries grid specifications). The PPC controller when performing a P,Q command

takes the feedback in a closed loop mode from the PQM in order to reach the desirable setpoint. If the

desirable setpoint is not reached for any reason then the PPC controller has to calculate the error in

percentage or in MWs in order to correct this error with a new setpoint. Usually the new setpoint is

referred to some specific solar inverters that are available and they are producing and can go more up or

down to meet the setpoint of active power. Active power control is performed in the range of plant

nominal power or contract limit, with any analogue or discrete setpoints provided by the plant or the grid

operator. Ramp rate limitations may be enforced either at inverter or PPC level. Depending on the grid

requirements, over-frequency or under-frequency response may be configured based on grid code

specified P(f) curves. The Active power control setpoint may be set either by the grid operator or the

plant operator, through a user interface, IP or serial protocols (DNP3.0, IEC 60870-5, Modbus), as well as

digital or analog contacts or using the grid code P(f) curve. The setpoint accepts values in the unit that the


plant operator has selected in the design process, either KW or % of the maximum permitted active

power. The Plant Operator may change the setpoint through Setting “Active power setpoint”. The plant

may be set to zero Active power generation quickly using the setting “Plant power off”, using value 1 for

normal plant generation and value 0 to set active power generation to 0. The plant operator may enable

or disable the active power control service that affects the settings above, using the Setting “Active power

control mode”, with value 1 to enable or 0 to disable. The current status of active power service is

monitored through State Active power control mode with values “Disabled” or “Enabled”. The active

power control may be performed using either a closed-loop PID algorithm - where setpoints are applied

to the inverters continuously to achieve the expected power level - or an open loop scheme where an

Active power setpoint is distributed equally in all inverters, based on the nominal power of their PV

modules. The plant operator may select the control scheme using the Setting “Active power control

algorithm” using value 0 for open-loop and 1 for closed-loop and monitor the current status in the

respective State “Active power control algorithm” (closed-loop or open-loop). The selection of the control

algorithm is normally Closed Loop. In order to enforce zero active power export, the PPC “Active power

setpoint” should be set to 0, while “Active power control algorithm” should be set to “Closed-loop” as

presented above. In order to enforce zero active power generation from the inverters though, “Active

power control algorithm” should first be set to 0 (Open loop) and then the “Active power setpoint” should

be set to 0, just distributing the active power setpoint to the inverters.

Apparent power limitation is performed in the range of plant nominal power or contract limit, with any

analogue or discrete setpoints provided by the plant or the grid operator. The Apparent power setpoint

may be set either by the grid operator or the plant operator, through a user interface, IP or serial

protocols. The setpoint accepts values in the unit that the plant operator has selected in the design

process, either KVA or % of the maximum permitted apparent power. The Plant Operator may change the

setpoint through Setting “Apparent power setpoint”. The plant operator may enable or disable the active

power control service that affects the settings above, using the Setting “Apparent power control mode”,

with value 1 to enable or 0 to disable. The current status of apparent power service is monitored through

State Apparent power control mode with values “Disabled” or “Enabled”.

Ramp rate up & down

Ramp rate limitations are enforced in the control actions or normal active power ramp up by gradually

applying the power control functions or limiting the possible active power ramp up while continuously

monitoring the produced power. Active power gradient control is significant for the grid stability,

minimizing voltage fluctuations from ramp up or ramp down active power commands, as well as solar

irradiance variability. In order to enable Ramp rate control, the Plant Operator may change the Setting

“Active power ramp rate control mode” (1=enable 0=disable) for use in Local Mode and check the

corresponding State “Active power control mode” representing the actual service status for both Remote

and Local modes. The ramp rate limitations are applied through Settings “Active power ramp up rate

setpoint” and “Active power ramp down rate setpoint” with values either in KW/min or %/min.


Open-loop control

This control mode is intended for testing purposes and is available to operator 0 only. The upper limit of

input setpoint is 100% or Pmax. No low limit exists. The output setpoint sent to the inverters (or inverter

applications) is calculated as: PSP_o = PSP0_S * OutScale, limited in [0, PSP_olim] where PSP_o is an

analog output of active power setpoint (array) set to the inverters (% of Pnom), PSP_olim the output

setpoint limit applied when closed-loop control is enabled (% of Pnom), and PSP0_S an analog output of

operator 0 active power setpoint (kW or % of Pmax).

Closed-loop control

This control mode is enabled if the following conditions also are satisfied: Valid P measurement, Valid

input frequency at startup if frequency control is enabled, Inverter availability (InvAvl) not below

InvAvlLow.

PID control

The PID controller's anti-windup mechanism is driven by the PFB which is the measured active power

(array) produced by the inverters (% of Pnom). When closed-loop control is enabled, the PID controller

initializes its accumulated error (PID_ErrSum) to: PID_ErrSum = (PFB - P) / Ki, where PID_ErrSum the PID

controller's ErrSum output. The resulting output setpoint will be: PSP_o = (PSP_eff - P) * OutScale + _PFB,

limited in [0, PSP_olim] where PSP_eff the "effective" active power setpoint, i.e. the setpoint fed to the

PID controller (% of Pmax). The functions require the PFB inputs to be responsive and have valid and

accurate values. Otherwise the system performance may degrade significantly.

Availability

Calculation of the inverter availability based on communication and generation. An inverter is considered

as available (availability is 100%) when it is communicating with the controller and at the same time the

irradiance measured is greater than 20W/m^2 (low irradiance threshold) and it is generating power

greater than zero. In case where the inverter is not generating any power while the irradiance is above

the low irradiance threshold, an extra check is performed if there is a control signal (active power setpoint

= 0) commanding the inverter to have zero production then the inverter is still considered as available.

Error calculation

The setpoints per inverter cannot be the same for all due to damaged strings or other reasons, such as

maintenance and some other inverters have to support this power gap. This is why an error is calculated

per inverter so as to proceed with individual control for every inverter to reach the desirable setpoint.


3.2.1.2 PV Active Power Control on 50MW AC Plant

The Grid operator in each country could decide at any moment for several reasons to curtail the PV power

plant, which means that the power will go from up to down within minutes either directly or through a

ramp. in Figure 3.16 is depicted a power control real case in which the PPC controller of a 50 MW

maximum AC power solar plant receives active power setpoints from the control center. The control

center will report this to the grid operator and the official billing process can start as the project is

certified to be added in the high voltage transmission system. The graph is showing that the plant is

producing 50MW when the first setpoint arrives to 40MW. The power POI displays the power measured

by the smart power analyser at the point of the interconnection and the power sp is the setpoint that

comes from the control center. The setpoint also can be set up and in local mode too, through the local

plant HMI. The site goes from 50MW with direct setpoints to 5MW and then back to 50MW and lastly

from 50MW to 0MW to check the direct curtail. In Figure 3.16 and Table 3.1 active power control with

direct setpoints is depicted along with the active power setpoints and grid response measurements.

Figure 3.16: Active power control with direct setpoints

Table 3.1: Active power setpoints and grid response

TIME P – POI(KW)

PF – POI(-1,1)

Q – POI

(KVar)

F – POI (Hz)

V – POI (Volts)

P – SP (KW)

08:55:19 50172.332 0.999674 1282.360 49.92000 135523.32 50000

08:55:20 50148.910 0.999677 1275.900 49.91000 135480 40000

08:57:50 40130.051 0.999695 991.920 49.99000 135126.671875 20000

09:00:09 20122.160 0.999684 506.280 49.99000 133856.671875 10000

09:02:33 10106.350 0.999839 181.490 50.03000 133456.671875 5000


09:04:50 5087.230 -0.999976 -35.140 49.97000 132756.671875 15000

09:07:03 14942.329 -0.999797 -301.380 50.14000 133536.671875 25000

09:09:16 24953.090 -0.999922 -311.420 50.16000 134416.671875 40000

09:11:25 39856.320 -0.999619 -1101.180 50.01000 134696.671875 50000

09:13:35 49893.012 -0.999874 -793.520 50.03000 135703.328125 0

09:15:49 0.000 1 0.000 50.08000 132820 50000

09:16:22 50001.895 -0.999536 -1524.180 50.16000 136026.671875 50000

The observation from the above measurements is that the pv power plant can execute massive MW

changes within 2 minutes. This is acceptable in most of the countries worldwide. However sometimes this

depends on the local network configuration and the inverters, PQM interval update time. Finally, there is

always a small error on reaching the setpoint and the maximum acceptable can vary from 5 to 10%+/-. On

the other hand, the SCADA system can execute massive MW changes with gradient steps from one to

another as depicted in Figure 3.17. The PPC controller receives the setpoint of 10MW and the system

starts to decrease/increase power with 2MW per step. In that way the system will reach the desirable

setpoint in 2 minutes. Later on, the setpoint is again from 50MW to 10MW but with a different approach

of ramp up/down, 1MW per step and as it was expected it requires 4 minutes to complete and achieve

the power setpoint.

Figure 3.17: Active power control with gradient setpoints


3.2.1.3 PV Frequency Control (FC)

Active power control may be used to automatically support the grid in overfrequency or underfrequency

events, based on grid operator P(f) curve and grid code requirements. The frequency support is enabled

using the Setting “Frequency control mode” with values 0 for disabling and 1 for enabling, affecting only

in Local mode. The current service status (Enabled or Disabled) is monitored through the respective State.

The grid code curves are configured during PPC design and all settings may be changed also using the user

interface. In Figure 3.18 a Frequency support through active power control graph is depicted.

Figure 3.18: Frequency support through active power control

An overfrequency event is triggered when the frequency exceeds frequency setting “Overfrequency

control base”. At this point the current power generation level is stored as reference value (Pref), so that

it may be used as the basis for P(f) control during overfrequency. An overfrequency event is eliminated

when frequency measured gets below the “Overfrequency control reset” frequency value, after which

active power control is restored to its prior to the overfrequency event state (no control, active power

control at a specific level, dynamic active power control based on apparent power limitation or active

power ramp rate control). During the overfrequency event, active power is controlled at a level specified

by the grid operator defined slope. The slope may be defined using one of the following three

configurations:

“Overfrequency control slope”, specifying the active power reduction per Hz (% of Pref /

Hz)

or “Over Frequency control droop”, specifying the generator statism equivalent in %:

100*(Δf/fnom)/(ΔP/Pref).

or “Overfrequency control zero”, specifying the theoretical frequency at which the P-f

curve line would result in setting active power to 0.

In order to select one of the three mechanisms, the other two settings should be set to

zero value.


Pref may be replaced if needed by the plant nominal power (or active power export limit if this applies).

This selection may be performed using the “Overfrequency curve dynamic” setting: value 1 in this setting

would specify that the slope is dynamic, using Pref as described. Value 0 (static) specifies that Pref used in

the calculations is set to the plant nominal power (or active power contractual export limit). Similar

configuration applies for the underfrequency events when applicable, with Settings “Under Frequency

control base”, “Underfrequency control reset”, “Underfrequency control slope”, Underfrequency control

droop”, Underfrequency control max” and “Under Frequency curve dynamic”. When an overfrequency or

under frequency event is detected, the current active power measurement is saved as active power

reference Pref. When the frequency is back again under cover-base but over-dover-reset the active power

will be limited at this saved power limit. The same applies for underfrequency events. After the frequency

event is eliminated, active power is again controlled according to the prior to the event active power,

apparent power limitation and active power ramp rate control. Both frequency events take priority over

active power ramp rate limitations. Since frequency events are rare, any new P(f) setup may be validated

with frequency emulation. Frequency emulation may be enabled with a dedicated Setting for test

purposes named “Frequency control source” (value 0 for normal operation and frequency measurements

used in P(f), or value 1 for frequency measurement emulation). When “Frequency control source” is set to

1 (emulation), then Setting “Frequency control setpoint” may be used as the value emulating the current

frequency and causing any active power curtailment. Example of the figure: a plant generates active

power of 80% of each nominal power, and has overfrequency slope of 50%/Hz, dynamic and frequency

base at 50.5Hz. If the frequency measurement gets to f=51.5Hz, the current active power generation

would be stored as Pref=80%. If “dynamic” (1) was selected, an active power reduction of 50% of Pref

would be affected (that is 40% of nominal power would be the new active power limitation). If the

“Overfrequency dynamic” was set to static (0) then the active power reduction would be 50% of Pnom,

that is the new active power limitation would be set at 30% of nominal power.

3.2.1.4 PV Frequency Control on 50MW AC Plant

Frequency control is used to set the active power production of the plant when the input frequency gets

out of the specified limits. The input frequency is obtained either from the measured frequency F or from

the frequency setpoint FSP. The input frequency passes first through a "deadband filter" with deadband

value FDB. Frequency control is enabled when both En0_S (Operator 0 setpoint enable/disable) and

FCEn0_S (Operator 0 frequency control enable/disable) are set to 1. While enabled but not active (i.e. the

input frequency is within the specified limits), the effective active power setpoint is obtained from

PSP0_S, (Operator 0 active power setpoint (kW or % of Pmax)) RPSP0_S (Operator 0 active power reserve

setpoint (% of Pexp)). If enabled and FARP (FARP Select activation of frequency control between "reset"

and "base" points) is 0, frequency control is activated when FOEn (Enable overfrequency control) is 1 and

F rises above FBase_S (overfrequency) (Overfrequency "base" point (Hz)) or when FUEn (Enable

underfrequency control) is 1 and F drops below FUBase_S (underfrequency). If FARP is 1, frequency

control is activated when FOEn is 1 and F rises above FReset_S (overfrequency) (Overfrequency "reset"

point (Hz)) or when FUEn is 1 and F drops below FUReset_S (underfrequency). At this instant, the


measured active power P is sampled and used as reference active power (Pref). Regardless of the value of

FARP, frequency control is deactivated when F gets within FUReset_S and FReset_S. The underfrequency

slope is taken from FUSlope (Underfrequency "slope" value (%/Hz)) if not zero, else it is calculated from

the following formula (if FUDroop (Underfrequency "droop" value (% of Fnom) is not zero): slope =

10000 / (Fnom * FUDroop)

The overfrequency slope is taken from FOSlope if not zero, else it is calculated from the following

formula (if FODroop is not zero): slope = 10000 / (Fnom * FODroop)

If FUMode is set to 0 (called "fixed"), the effective active power setpoint is calculated from the

following formula: Psp = Pref + slope * (FUBase_S - F)

If FOMode is set to 0 (called "fixed"), the effective active power setpoint is calculated from the

following formula: Psp = Pref + slope * (FBase_S - F). In Figure 3.19 three characteristic curves for three

different Pref values are depicted.

Figure 3.19: Three characteristic curves for three different Pref values.

If FUMode (Select between underfrequency "fixed" (0) or "dynamic" (1) active power increase) is set to 1,

the effective active power setpoint is calculated from the following formula:

Psp = Pref * (1 + slope * (FUBase_S - F) / 100)

If FOMode is set to 1 (called "dynamic"), the effective active power setpoint is calculated from the

following formula:

Psp = Pref * (1 + slope * (FBase_S - F) / 100).

In Figure 3.20 three characteristic curves for three different Pref values are depicted.



If F becomes less than FUMax_S (Underfrequency "max" point (Hz), then PSP (The combined active power

setpoint feedback (% of Pmax)) is set to 100. This is optional and can be disabled by setting FUMax to 0. If

F becomes greater then FZero_S (Overfrequency "zero" point (Hz)), then PSP is set to 0, even if Pref is

invalid. This is optional and can be disabled by setting FZero_S to 0. If both FUSlope and FUDroop are set

to zero, then the underfrequency slope is implied from frequency points FUBase_S and FUMax_S. If both

FOSlope and FODroop are set to zero, then the overfrequency slope is implied from frequency points

FBase_S and FZero_S. In Figure 3.21 Three characteristic curves for three different Pref values are

depicted.


If FOMntn (Enable overfrequency curve "monotonic" behavior) is set to 1, then the overfrequency

response is "monotonic", meaning that---while in overfrequency---P may decrease but may not increase.

The blue line in Figures 3.19, 3.20 & 3.21 shows this behavior. If---while frequency control is enabled---the

input frequency becomes invalid, the effective active power setpoint will retain its last value. If this


happens at system startup, the PID controller will not be enabled and no active power control will be

performed. When active power reserve is enabled (REn (The combined active power reserve

enable/disable) set to 1), then parameters RFOSlope, RFODroop, RFOReset, RFOBase, RFOZero, RFUSlope,

RFUDroop, RFUReset, RFUBase and RFUMax are used instead of FOSlope, FODroop, FReset_S, FBase_S,

FZero_S, FUSlope, FUDroop, FUReset_S, FUBase_S and FUMax_S. Finally, while frequency control is

active, the rate controller's mode is set to "limit" and the ramp-up and ramp-down rates are obtained

from FCRateUp_S and FCRateDown_S respectively. Inverter interface: The setpoint (array) sent to the

inverters is PSP_o, which expands internal signal _PSP_o. When closed-loop control is enabled, PSP_o is

limited in the range [0, PSP_olim]. If common_invsp is set to "False", an "individual inverter control"

function further distributes the setpoint, according to the current production level of each inverter. In

Figure 3.22 active power control with frequency setpoints is depicted. Also, in Table 3.2 active power

setpoints in relation to grid connection point are depicted.

Figure 3.22: Active power control with frequency setpoints

Table 3.2: Active power setpoints, Frequency and grid response

TIME P – POI(KW)

PF – POI(-1,1)

Q – POI

(KVar)

F – POI (Hz)

V – POI (Volts)

F – SP (Hz)

P – SP (KW)

11:09:49 50151.660156 0.999089 2142.320068 49.830002 134980 50 50000

11:11:49 50132.230469 0.999634 1357.27002 49.950001 135386.67187 49 50000

11:13:59 50114.300781 0.999362 1791.02002 50.09 135270 48 50000

11:16:08 50181.125 -0.999992 -196.990005 50.080002 135996.67187 47 50000

11:18:29 50164.21875 0.999979 326.980011 50.060001 135906.67187 50 50000

11:32:02 50145.800781 -0.999997 -112.290009 50.07 136150 50.5 50000


11:32:03 50157.199219 -0.999998 -96.570007 50.07 136220 51 50000

11:32:04 33935.03125 0.99504 3392.640137 50.060001 136303.32812 51 33442.386719

11:34:59 16812.949219 0.989783 2422.030029 50.150002 134733.32812 51.5 16721.193359

11:36:02 16805.519531 0.967435 4396.97998 49.919998 134410 52 16721.193359

11:38:00 0 1 0 49.990002 132486.67187 52 0

3.2.1.5 PV Reactive Power Control (RPC)

Reactive power control is performed in the range of reactive power limits specified by the grid operator,

in a static or dynamic manner. Equipment controlled include inverters of any vendor and nominal power,

mechanically switched capacitors and reactors. The setpoint may be set either by the grid operator or the

plant operator user interface, through IP or serial based protocols (DNP3.0, IEC 60870-5, Modbus), digital/

analog contacts or grid code curves. The setpoint “Reactive power setpoint” accepts values in the unit

that the plant operator has selected in the design process, either KVAr or % of the maximum permitted

active power. The Plant Operator may change the setpoint through Setting “Reactive power setpoint”.

The plant operator may enable or disable the reactive power control service that affects the settings

above, using the Setting “Reactive power control mode”, with value 1 to enable or 0 to disable. The

current status of reactive power service is monitored through State “Reactive power control mode” with

values “Disabled” or “Enabled”. The reactive power control may be performed using either a dedicated

closed-loop PID algorithm where setpoints are applied to the inverters continuously to achieve the

expected power levels, or an open-loop scheme where a Reactive power setpoint is distributed equally in

all inverters, based on the nominal power of their PV modules. The plant operator may select the control

scheme using the Setting “Reactive power control algorithm” using value 0 for open-loop and 1 for

closed-loop and monitor the current status in the respective State “Reactive power control algorithm”

(closed loop or open-loop). The selection of the control algorithm is normally in Closed Loop, and this

setting is universal for both Remote and Local modes. The sign used for “Reactive power setpoint” is

positive (+) to denote that the plant should export (generate) reactive power from the grid at the point of

connection, and negative (-) to denote the plant should import (absorb/consume) reactive power from

the grid at the point of connection. When open loop mode is used and the measurements of the point of

connection have no significance, the signs indicate whether the inverters or reactive power compensation

resources should export or import reactive power.

3.2.1.6 PV Reactive Power Control on 80MW AC Plant

The Reactive Power Control (RPC) application is part of the Power Plant Control (PPC) applications. It is

used to set a plant's export/import reactive power or regulate the grid voltage by controlling the reactive


power exported/imported by its inverters. The application may control the plant's inverters either directly

or through other intelligent devices, called in general "slave PPCs". If this is the case, then all following

references to "inverter" should be changed to "slave PPC". The control functions provided by the

application are: Direct (setpoint) reactive power control, Reactive power ramp rate control, Voltage

control (slope-based), Emergency voltage control. The RPC application is also used by the Automatic

Voltage Regulation (AVR) application and optionally by the Power Factor Control (PFC) application. In

Figure 3.23 Reactive power control setpoints are depicted along as with Table 3.3.

Figure 3.23: Reactive power control setpoints

Table 3.3: Reactive power setpoints and grid response

TIME P – POI(KW)

PF – POI(-1,1)

Q – POI

(KVar)

F – POI (Hz)

V – POI (Volts)

Q – SP (Kvar)

P – SP (KW)

09:48:30 57183.261719 -1 -29.309999 49.830002 135526.67187 0 67900

09:51:42 57051.824219 0.932782 22045.599609 50.02 136450 22399.998047 67900

09:54:09 57377.394531 0.999996 172.050003 50.080002 139590 0 67900

09:57:20 57291.296875 -0.913044 -24592.27929 50.02 136106.67187 -22399.99804 67900

09:59:49 57466.238281 0.999155 2363.629883 50 130703.33593 0 67900

As observed from the test above with an 80MW PV Plant, the SCADA sends the reactive power setpoints

to the power system and within seconds the desired reactive power has been exported onto the grid. The

power system must export or import the respective reactive power depending on the sign each time of

the setpoint --- as (+) in full inductive mode and reactive power export --- as (-) in full capacitive mode and

reactive power import.


3.2.1.7 PV Power Factor Control (PFC)

Power factor control is performed in the range of power factor or reactive power limits specified by the

grid operator, in a static or dynamic manner. The control is performed with a similar strategy as reactive

power control and a dedicated PID controller, with PPC maintaining the specified power factor at the

point of connection. The setpoint may be set either by the grid operator or the plant operator user

interface, through IP or serial based protocols (DNP3.0, IEC 60870-5, Modbus), digital/analog contacts or

grid code curves. The setpoint “Power factor setpoint” accepts values from - 1.0 to 1.0. The Plant

Operator may change the desired setpoint through Setting “Power factor setpoint”. The plant operator

may enable or disable the power factor control service that affects the settings above, using the Setting

“Power factor control mode”, with value 1 to enable or 0 to disable. The current status of power factor

service is monitored through State “Power factor control mode” with values “Disabled” or “Enabled”. The

power factor control may be performed using either a dedicated closed-loop PID algorithm where

setpoints are applied to the inverters continuously to achieve the expected power factor, or an open loop

scheme where a power factor setpoint is sent to all inverters. The plant operator may select the control

scheme using the Setting “Power factor control algorithm” using value 0 for open-loop and 1 for closed-

loop and monitor the current status in the respective State “Power factor control algorithm” (closed-loop

or open-loop). The selection of the control algorithm is normally in Closed Loop, and this setting is

universal for both Remote and Local modes. Power factor control using cosphi(P) curve may be

configured for the most complex scenario using four different cosphi-P points with the Settings: “Power

factor Active power min”, “Power factor Active power low”, “Power factor Active power high”, “Power

factor Active power max” which are the Active power points for which the values of power factor should

be set to “Power factor for active min”, “Power factor for active low”, “Power factor for active high”,

“Power factor for active max”. In Figure 3.24 Power factor control graph as a function of active power is

depicted.

Figure 3.24: Power factor control as a function of active power

The sign used for “Power factor setpoint” is positive (+) to denote that the plant should export

(generate) reactive power from the grid at the point of connection, and negative (-) to denote the plant


should import (absorb/consume) reactive power from the grid at the point of connection. When open

loop mode is used and the measurements of the point of connection have no significance, the signs

indicate whether the inverters or reactive power compensation resources should export or import

reactive power.

3.2.1.8 PV Power Factor Control on 80MW AC Plant

The Power-Factor Control (PFC) application is used to achieve a desired power-factor from a plant by

controlling either the power-factor or the reactive power exported/imported by its inverters. The

application may control the plant's inverters either directly or through other intelligent devices, called in

general "slave PPCs". If this is the case, then all following references to "inverter" should be changed to

"slave PPC". The control functions provided by the application are: Direct (setpoint) power-factor control,

Active power based power-factor control (denoted PF(P)). The Q calc is the Kvar SCADA calculated value

that has to be set to the inverters in Kvar totally related to the power factor setpoint from the user each

time. In Table 3.4 Power factor setpoints with grid response are depicted.

Table 3.4: Power factor setpoints and grid response

TIME P – POI(KW)

PF – POI(-1,1)

Q – POI

(KVar)

F – POI (Hz)

V – POI (Volts)

Q – calc (Kvar)

PF – SP [-1,1]

10:24:20 56568.601562 -0.999981 -348.049988 50.029999 135366.67187 0 1

10:24:21 56553.792969 -0.99999 -252.47998 50.029999 135353.32812 0 0.95

10:24:22 56339.550781 0.949729 18572.009766 50.029999 135330 18588.333984 0.95

10:26:51 56589.308594 1 0.8 50 138576.67187 0 1

10:29:13 56755.015625 -0.937844 -21002.66015 50.119999 136133.32812 -18661.90429 -0.95

10:31:33 57003.011719 0.999547 1716.199951 50.080002 132033.32812 0 1

3.2.1.9 PV Automatic Voltage Regulation (AVR)

SCADA PPC provides two modes of Voltage Control at the point of connection: slope-based or direct

voltage regulation. Direct voltage regulation is a form of continuously acting closed loop voltage

regulation that controls the voltage level at the point of connection, within the plant design and grid code

limitations. It may be enabled using Setting “Automatic voltage control mode”, with value 0 to disable and

value 1 to enable when in Local Mode. Current service status (Enabled or Disabled) may be monitored

using the respective State “Automatic voltage control mode”. The voltage setpoint to be achieved is

configured through Setting “Automatic voltage control setpoint” and values in Volts or p.u., monitored

through the respective Parameter “Automatic voltage control setpoint”. In Figure 3.25 voltage control

with a slope is depicted.


Figure 3.25: Voltage control with a slope

Slope-based voltage control is a form of feed-forward reactive power control, where based on the voltage

control setpoint and the voltage measurement the PPC applies certain reactive power closed loop

operations. Slope-based voltage control may be enabled using Setting “Voltage control mode”, with value

0 to disable and value 1 to enable when in Local mode. Current service status (Enabled or Disabled) may

be monitored using the respective State “Voltage control mode”. The droop value of the voltage control

may be configured using Setting “Voltage control droop” (p.u. change causing Qmax export). Voltage

control may be configured to be enabled automatically in cases of undervoltage or overvoltage events.

The respective limits may be configured using “Voltage low limit” and “Voltage high limit” in p.u.. The

functionality may be enabled/disabled through setting “Emergency voltage control mode” (0 to disable, 1

to enable). The voltage setpoint to be used as input to calculate the reactive power may be provided

through Setting “Voltage control setpoint” and values in Volts or p.u. and monitored through the

respective Parameter “Voltage control setpoint”.

3.2.1.10 PV Voltage Control & AVR on 80MW AC Plant

Automatic voltage control

The Automatic Voltage Regulation (AVR) application is part of the Power Plant Control (PPC) applications.

It is used to set the grid voltage level by controlling the exported/imported reactive power of the plant.

Operation: The AVR application operates always in closed-loop, using a PID controller to calculate an

output voltage setpoint (VSP_out) which is then converted to a reactive power setpoint (QSP), fed as

input setpoint to the Reactive Power Control application. At the time the AVR function is enabled and

whenever VSP changes, the AVR PID controller's cycle is interrupted and the output setpoint is calculated

as: QSP = Q + Qmax * (VSP - V) / A During normal operation (i.e. while VSP remains stable), the output

setpoint is calculated as: QSP = Qmax * (VSP_out - 1) / A. In Figure 3.26 along with Table 3.5 AVR

setpoints are depicted.


Figure 3.26: AVR control with Q setpoints

Table 3.5: Voltage setpoints and grid response

TIME P – POI(KW)

PF – POI(-1,1)

Q – POI

(KVar)

F – POI (Hz)

V – POI (Volts)

Q – calc (Kvar)

V – SP (Volts)

10:36:11.251 56815.128906 0.997054 4370.709961 50.009998 135040 4036.567139 136000

10:40:13.251 56926.804688 0.989557 8292.160156 50 136913.32812 8347.725586 138720

10:42:17.251 57003.292969 0.993008 6776.27002 49.950001 137223.32812 6741.3125 138720

10:45:35.251 57189.808594 -0.996071 -5084.75 49.919998 134666.67187 -5121.176758 133280

3.3 SCADA & Smart Grid in Battery Energy Storage Systems

The BESS system functionality is very similar to a PV plant. A DC power source is coming through an

inverter and transformed to an AC wave, though the DC source differentiates in this particular occasion.

The DC source is not a string with pv modules connected in a row, but small battery cells that consist of a

DC string or DC rack. The battery cells could be either from lithium or from lead acid. The aggregated DC

strings are protected through a DC switch and connected at the MPPT input of the battery inverter as

indicated below. The PCS in this occasion is the battery inverter. In terms of SCADA in the BESS system,

there is the BMS module that can act as a fail safe system for the battery or provide all useful information

exported from the battery cells, battery room and information such as temperature, humidity, power, cut

off currents, state of charge. This does not mean that every BESS system carries this management

module; it depends on the project each time. The BMS acts like a SCADA in the BESS system protecting

the battery from any unwanted situations or provides information about the status and measurements of

the whole BESS system. An unwanted situation could be the high cell temperatures or high

charge/discharge currents. Though if the BESS system is not provided with a SCADA BMS module the


battery control must be performed from a third party SCADA. The SCADA developer must take into

consideration all the failsafe scenarios provided by the manufacturer and has to develop the BMS system

requirements and the SOC balancing as well, the state of charge of each battery handled directly from a

third party SCADA. In Figures 3.27, 3.28 and 3.29 electric circuits and overview of a BESS system is

depicted.

Figure 3.27: Electric circuit of a Battery System

Figure 3.28: Battery System with BMS


Figure 3.29: Overall Electric circuit of a Battery System

3.3.1 SCADA BESS control & Grid Services

The SCADA systems will play an important role in the integration of the BESS systems into the grid. A

SCADA system can provide the following services when it is combined with a BESS system.

Frequency Response services

Auto charge/discharge services

SOC Management, Limits avoidance

Feed forward control loop, Availability based, Closed loop

Control schemes

PCS-grouped battery protection extending BMS functionality

Control actions Scheduler

Frequency Support, Capacity market, Real-time market

Ancillary services

Market interface

More specifically the control services to be provided by the SCADA system include:

a) Firm Frequency Response service: control active power as a function of frequency as per Grid’s FFR

service requirements.

b) Power Factor control: control reactive power to deliver the expected power factor.

c) Power Export, Time or Energy bound: export with a specific active power setpoint, until a specific

period has passed or the energy exported limit. (AutoExport)


d) Power Import, Time or Energy bound: export with a specific active power setpoint, until a specific

period has passed on the energy imported limit. (AutoImport)

e) SOC Control: manage the system SOC to reach a specific setpoint, always or at a specific point of time.

(AutoSOC in the original spec) Setpoints that only occur when the upper or lower SOC limits are hit -

designed to bring SOC back into an acceptable range.

f) SOC Limits Avoidance: management of control actions to ensure Site SOC stays within the specified

limits. Calculates adjustment to the System P/Q Setpoints to try and keep SOC within limits. Applied when

SOC is between upper and lower limits, as a modifier to the control mode setpoint intended to prevent

hitting limits.

g) SOC Limits Reaction: reaction of system to Site SOC exceeding the limits (SOC Management in the

original spec)

h) External setpoint: capability to import/export active power as per external system request

i) Closed loop control of Site active and reactive power with feedback at the Point of Connection through

the Power Quality Meter.

j) Inverter availability calculation based on modules status, temperature and SOC.

k) Inverter P/Q setpoints distribution: divide the Site setpoint to setpoints to available inverters

l) SOC Balancing: advanced distribution mechanism of Site active power control to all inverters trying to

balance their SOC. Split System P/Q Setpoint amongst inverters based on a variety of factors to balance

SOC.

m) Scheduling of control functions, with repetition and selected values: program control functions for the

future, cancel edit programmed tasks, get notified for the schedule status.

3.3.1.1 High level control logic of BESS

The Control system will implement the logic of enabled control services, in an on demand or scheduled

manner. The system designed follows in principle the initial requirements and architecture that follows in

Figure 3.30:


Figure 3.30: High Level Control Logic Diagram

The Control Logic sits within the PLC. It uses inputs from the site devices, in particular the PCS (inverters)

and battery management system, combined with system rules and uses these to calculate an Active

Power (P) and Reactive Power (Q) setpoint that the battery system needs to deliver. There will be various

services that the battery will be required to deliver, and each of these will have different calculations

(Service Calculations). For this development, this will be limited to four services; FFR, Auto Charge, Auto

Discharge and Auto SOC. The service in operation at any given time will be defined by a signal from the

SCADA platform provided by others. There will be a State of Charge management function that kicks in if

the battery charge is too high or too low, and this will typically override or augment the P/Q setpoint

coming from the service calculations. The PLC will also include a “master controller” function which splits

the P and Q signals into individual setpoints to each PCS. The PCS then exports or imports to deliver these

setpoints. The net P and Q delivered by the battery system is measured by a Power Quality Meter (PQM)

and fed back into a PID loop (or open loop) within the PLC which rapidly adjusts the P and Q setpoints

until the delivered P and Q are at the required values.

3.3.1.2 Firm Frequency response in BESS

Overview of FFR (Firm Frequency Response)

FFR is the change in active power delivered as a response to a change in system frequency. This change in

active power could either be from its initial state or a predicted demand level (baseline). It is available in

two variants: Non-Dynamic (also referred to as Static) & Dynamic. With Non-Dynamic response, the


change in active power is a specified value and occurs when the frequency rises through 50.3Hz or falls

through 49.7Hz, depending each time on the grid requirements and specifications. (Figure 3.31) There are

2 services: Low Frequency with Primary & Secondary, and High frequency. The non-dynamic low and high

frequency tests aim to monitor the capability of the provider to deliver the minimum contracted level of

response. Pass criteria for test: The SCADA should do the following: The relay (or equivalent) operating

point of the plant/unit(s) occurs at the correct contracted trigger frequency and within the permitted

tolerance (±0.01Hz). Sustain the response for the 30 minutes. The standard deviation of active power

error over a 30 minute period must not exceed 2.5% of the contracted active power change.

Figure 3.31: Example of a Non-Dynamic Response to a Varying Frequency

In Dynamic response the change in active power is proportional to the change in frequency as shown in

Figure 3.32. There are 2 services: Low Frequency with Primary and Secondary Response & High Frequency

Response. A SCADA test is designed to ensure the system responds when the frequency moves outside of

the +/- 0.015Hz deadband. The step injections are shown in Figure 3.33 with corresponding values in

Table 3.6. Each step is sustained for 180 seconds to verify the response. The frequency will then be

returned to 50Hz for a minimum of 30 seconds, or until the output is stable, before the next injection is

applied. The injections and expected responses for each test are shown in Table 3.7. These tests are

designed to ensure a change in power when the frequency moves outside the deadband. Pass criteria for

test: Delay in response of active power due to a change in frequency is no greater than 2 seconds.

Minimum of the sampled values of active power within primary, secondary and high frequency timescales

are within the allowable tolerances given in Table 3.7 and shown graphically in Figure 3.34. The standard

deviation of load error at steady state over a 180 second period must not exceed 2.5% of the maximum

contracted active power. Active power should progressively change to its contracted output. For the tests

a noticeable change in power in the correct direction is observed.


Figure 3.32: Example of a Dynamic Response to a Varying Frequency

Table 3.6. Frequency Injection Table Corresponding with Times


Figure 3.33: Injection Profile

Table 3.7. Frequency Injection and Expected Response values


Figure 3.34: Allowable Power Tolerance for a Negative Gradient Active Power Response

The Figure 3.34 has one more reversed figure that corresponds to allowable power tolerance for a

Positive Gradient Active Power Response. From -0.6, -100% to 0.6, 100%.

Connection into Grid Test

This test investigates the SCADA system’s ability to respond to the system frequency. The active power

response of the system and the system frequency will be recorded for 1 hour. The sample rate should be

10Hz for this test. An example is shown in Figure 3.35. Pass criteria for test: Provide an active power

response consistent with the contracted performance within Primary, Secondary and/or High frequency

response timescales. In Figure 3.35 an example of frequency simulation for the SCADA test is depicted.


Figure 3.35: Example of frequency simulation for SCADA test

3.3.1.3 Close loop control in BESS

The system setpoint is applied to the Site with open or closed loop: in open loop mode, the control

system affects the setpoint once, unchanged or with a feed forward mechanism (multiplying by a factor

and adding an offset); until a new setpoint is generated from the control functions and SOC limits

avoidance/management mechanisms. In closed loop mode, the control system affects the setpoint

continuously while compensating for the error between Site Setpoint and measurement at Point of

Connection – when the error exceeds 0.5%. The error compensation comes by simple proportional

reaction (P) or proportional and integral algorithm (PI). In any case, a feed forward mechanism will be

required in order to achieve the setpoint at the Point of Connection with the first loop.

3.3.1.3 State of Charge Algorithm in BESS

SOC Management

The SOC Balancing mechanism described is an advanced distribution mechanism of a BESS Active power

control setpoint to all Power Converters, aiming to balance their batteries average SOC. The controllable

asset is the Power converter. Each Power converter consists of one or more PCS modules, each one

connected to one or more battery strings. It refers to batteries as a group of strings for each PCS. SOC

Balancing performed amongst the batteries of a specific PCS is always a BMS scope. The goal is to utilize

PCS batteries' average SOC and PCS availability in order to calculate the setpoint distribution per PCS.

When the site is discharging, batteries with highest SOC are discharged in a higher rate (larger active


power setpoint), batteries with lowest SOC are discharged in a lower rate (smaller active power setpoint,

still positive). When a site is charging, batteries with lowest SOC (less charged) are charged at a higher

rate, batteries with highest SOC are charged at a slower rate.

An overview of the algorithm:

Calculate PCS availability based on SOC and BESS setpoint (not available for discharge if SOC = 0

for example)

Calculate AL-normalized SOC average, in order to provide an energy-based distribution. In the

future this can be enhanced with energy capacity.

From min and max SOC of PCS calculate the range of SOC for distribution

From site setpoint, min and max setpoints, calculate the min range of active power setpoint

distribution

Calculate a SOC Balancing slope (Active Power setpoint deviation per SOC deviation)

Calculate the active power for each PCS based on their AL-normalized SOC

Calculate the actual active power for each PCS

The Site control loop output is distributed to the inverters with the following options: Distributed to all

inverters that are available, using a common setpoint to all inverters (setpoint as a percent of nominal

output of each inverter). Distributed to all inverters that are available, using a setpoint (as a percent of

nominal output of each inverter) normalized by inverter batteries nominal energy capacity. Distributed to

all inverters that are available, using a setpoint (as a percent of nominal power of each inverter)

normalized by available energy capacity (inverter SOC) against total energy capacity. When charging, the

inverters with the highest DOD are charged more. When discharging the inverter with the highest SOC is

discharged more. Distributed to all inverters that are available, using a setpoint originating from SOC

Balancing. The max inverter setpoint is always taken into account, by utilizing the reactive power setpoint

instructed by reactive power control loop - to calculate the max active power per inverter – or by the

power factor setpoint output – to calculate the max active power per inverter.

3.3.1.4 SCADA BESS Control in 57MWh Capacity Site

The Battery Energy Storage System Control (BESSC) in a SCADA system controls the active and reactive

power exported or imported by (the inverters of) a Battery Energy Storage System (BESS). Apart from the

top-level application, BESSC incorporates sub-applications from the family of Active Power Control and

Reactive Power Control applications. The BESS APC provides the following services:

Direct (setpoint) active power control.

Battery charge management.

Frequency response.

The BESS RPC provides the following services:


Direct (setpoint) reactive power control.

Direct (setpoint) power-factor control.

Operating mode The system may operate in 3 modes: Manual: In this mode, the effective active and

reactive power setpoints are provided directly by the user. Continuous: In this mode, the effective

setpoints are calculated by the enabled function(s), whose settings are provided by the user. Scheduled:

In this mode, the effective setpoints are calculated by the enabled function(s), whose settings are

obtained from the respective (and currently active) schedule(s). In Figure 3.36 a BESS system with SCADA

is depicted.

Figure 3.36: A BESS system with SCADA

A SCADA systems for a battery site could be considered with the following components:

Equipment Function List of Materials: Power Controller - One controller to house the control logic and

provide setpoints to the PCS and one for dynamic redundancy. (Modbus/ TCP interface is embedded)

Data loggers for onsite data capture to monitor switchgear and substation equipment, as well as any

parameter not directly used by the core control algorithms (CPU Line Cards, Power Supply Line Cards).

Modbus Interface cards to receive digital signals from the BMS in Modbus TCP/IP format RS-485 Line card.

Digital and Analogue interface cards to send and receive hardwired signals from site devices such as

transformers and circuit breakers. Digital inputs Line cards, Digital Output Line cards, Analog inputs Line

cards, GPS clock to synchronise time stamps of all equipment GPS Synchronized Network Time Server,

Network switch, Firewall To deliver security rules and monitoring for ingoing and outgoing network traffic,

Broadband router with 4G/3G auto changeover on failure to send and receive commands and data from

the remote user interface. Screen, keyboard and mouse KVM Console for the local server. KVM Console

Local Management Server. Local server for full control and monitoring functionality on site.

Uninterruptible power supply (UPS) to power the above equipment in the event of a loss of mains power.


Power Supply 24V DC Units. Diode Module Redundant operation of power supply units. Miniature Circuit

Breaker for rack 10A AC. All the above shall be hosted in a FAN aired 42U server rack. Figure 3.37 shows

the standard architectural approach of a SCADA system for control and monitoring Power Plants, both on

Site and Centrally:

Cloud servers and storage

Plant Router/Firewall

PPC (Control System) - with optional connectivity to the grid operator

Local Management System (LPS) and workstation

Main Substation Units (MSSU) and Peripheral ones (PSSUs.

Different networks for Control & Monitoring and CCTV/Security.

Figure 3.37: Central Management System integration to Site Equipment

The working modes of the SCADA systems can be directly configured from the platform. When the SCADA

system works in scheduled mode the client can configure the scheduled program for FFR export from the

calendar below. The system then starts automatically to deliver FFR service into the grid. In Figure 3.38 a

SCADA platform for a BESS site is depicted.


Figure 3.38: SCADA Platform for a BESS site

When the SCADA system works in FFR Dynamic mode (scheduled or not) it should be sending setpoints to

the power converters based on the test figures and tables shown (Table 3.7 and Figure 3.34). In Figures

3.39 & 3.40 there is a real case with Dynamic FFR with 57MWh capacity BESS site. As observed, the

SCADA system works perfectly. The setpoints sent when the frequency is in the deadband limits, which is

49,925 and 50,085, are zeros and the system is in standby mode. That is totally correct. Also, when the

frequency goes up the power of the BESS should turn in import mode (charging (-)) and when the

frequency goes down the BESS system should turn in export mode (discharging (+)) which is true on the

real BESS as shown in Figure 3.38. The SCADA system executes the following rules for the DYNAMIC &

STATIC FFR events:

If GridFrequency_Adj < 49.5 ACR_FFR = PMax(Export). Delivers maximum export if frequency is

lower than 49.5.

If 49.985 > GridFrequency_Adj >= 49.5 ACR_FFR = [PMax(Export) x (GridFrequency_Adj –

49.5)]/(50 – 49.5). Interpolates linearly to calculate AC response.

If 50.085 >= GridFrequency_Adj >= 49.925 ACR_FFR = 0. Delivers no response in the deadband.

If 50.5 >= GridFrequency_Adj > 50.015 ACR_FFR = [-PMax(Import) x (GridFrequency_Adj –

50)/(50.5 – 50)]. Interpolates linearly to calculate AC response.

If GridFrequency_Adj > 50.5 ACR_FFR = -PMax(Import). Delivers maximum import if frequency is

lower than 49.5.


Figure 3.39: Active power export/import on real BESS site based on frequency fluctuation

Figure 3.40: All power converters SOC (charge/discharge) during Dynamic FFR mode


3.5 SCADA & Smart Grid in Micro-Grid Systems

Microgrids, also characterized as the “building blocks of smart grids”, are perhaps the most promising,

novel network structure. The organization of microgrids is based on the control capabilities over the

network operation offered by the increasing penetration of distributed generators including

microgenerators, such as microturbines, fuel cells and photovoltaic (PV) arrays, together with storage

devices, such as flywheels, energy capacitors and batteries and controllable (flexible) loads (e.g. electric

vehicles), at the distribution level. [45] A microgrid is a group of interconnected loads and distributed

energy resources within clearly defined electrical boundaries that act as a single controllable entity with

respect to a grid. Such systems can be operated in a non-autonomous way, if interconnected to the grid,

or in an autonomous way, if disconnected from the main grid. The operation of microsources in the

network can provide distinct benefits to the overall system performance, if managed and coordinated

efficiently. There are three major messages delivered from this definition:

Microgrid is an integration platform for supply-side (microgeneration), storage units and demand

resources (controllable loads) located in a local distribution grid.

A microgrid should be capable of handling both normal state (grid-connected) and emergency

state (islanded) operation.

The difference between a microgrid and a passive grid penetrated by microsources lies mainly in

terms of management and coordination of available resources.

One major advantage of the microgrid concept over other “smart” solutions lies in its capability of

handling conflicting interests of different stakeholders, so as to arrive at a globally optimal

operation decision for all players involved. [1]

From a SCADA perspective, there is always a big challenge. Microgrid systems are well connected with

SCADA systems due to the complexity of the system and the hard situation of controlling all sources in

parallel. Considering the different power generation systems included in a microgrid system the software

must be smart enough to deal with the several scenarios and fault situations that the system could face.

Apart from that, the SCADA system should deliver flexible modes and settings in order to keep the

microgrid up & running always, especially in the off-grid microgrids. Concluding, SCADA is mandatory for a

microgrid system for the steady operation of it and the participation of the microgrid system in the energy

market in a smart way through a multiagent system.


3.5.1 SCADA & Micro-Grid Control

A microgrid is a localized grid section, consisting of interconnected distributed energy resources and loads

under a common control scheme. Energy resources may be renewables like solar and wind, diesel

generators, gas turbines, battery storage, electric vehicles and demand response. Microgrids may serve

applications ranging from Industrial & Commercial, Campus/Institutional, Communities and Military, in an

autonomous or grid connected manner:

Autonomous: Off-grid systems where generated power is consumed to meet the needs of the local

demand. Partly autonomous systems are also covered.

Grid Connected: Generate and distribute power within the local grid and import/export power from a

utility source.

In Figure 3.41 a Microgrid control scheme with SCADA is depicted.

Figure 3.41: A Microgrid control system with SCADA

A Microgrid control system is responsible for the coordinated control of all microgrid energy resources. It

consists of the central and peripheral controllers, data loggers and communication equipment required,

measuring instruments as well as a SCADA/EMS server for proper system management. A SCADA Control

system for Microgrid applications should be able to integrate Battery Storage, PV, Wind, Diesel and Gas

generators. Moreover, it should be flexible to satisfy the requirements of any microgrid, fully

autonomous, partly autonomous or grid-connected, scalable for use by microgrids of any size.


3.5.1.1 SCADA features for off-grid applications

In terms of Microgrid control and especially for a system which is not grid-tied the following features are

mandatory for a SCADA system:

Grid, power quality, loads monitoring: Monitor microgrid power quality, loads monitoring.

Scheduling, dispatching and management of all energy resources: Operate Gensets, PV and

Batteries in a coordinated and scheduled manner.

Coordinated reactive power control: Utilizing Battery Power Converters, PV Inverters, Diesel

gensets.

Optimize energy mix: Maximize renewables share, minimize diesel participation via direct diesel

generators control.

Energy shifting: Coordinate charging batteries from excess PV and discharging later.

Load tripping (optional): Trip non critical loads in emergency cases.

Black start capability: Via use of grid forming battery power converters

Accordingly there are features provided from a SCADA for all microgrid subsystems.

Generators Control

Gensets integration, status and power monitoring: Monitor state of gensets, power and alarms,

through direct communications or dedicated meters.

Gensets dynamic control: Remote setpoint control in case of other grid forming device,

connection and disconnection of gensets.

Gensets reserve management: Power reserve by dynamically disconnecting/connecting gensets.

Gensets minimum load management: Most gensets should not be operated below a certain load

to avoid inefficient operation.

PV Generation Control

PV Active power control: Fast, accurate and steady control.

PV Active power ramp rate: Limit the ramp up of PV inverters.

Reactive power from PV: Support reactive power compensation.

Battery Storage Control

Energy Shifting: Excess energy from PV that would be curtailed charges the battery during day and

discharges at night.

State Of Charge Management: Ensure that the battery SOC is sufficient, avoiding low and high

limits, SOC-based AC balancing.

Grid forming: Enable operation without diesel/other generator. Power converter operates as

voltage source, regulating frequency and voltage.

Frequency support: Balancing mode to support frequency and active power deviations.


Voltage support: Support voltage by reactive power control from battery inverters, during day

and night.

Ramp Rate Control: Absorb sudden active power changes caused from PV plants. Gradually

decrease to allow other sources to undertake control.

Genset Start Avoidance: Avoid unnecessary genset starts for small load spikes, by utilizing

batteries for small periods.

State Of Charge Calculation: Calculates the battery’s state of charge when the battery vendor

does not provide direct measurement.

Scheduled battery participation in energy shifting and balancing: A group of batteries for grid

balancing/forming and a group for energy shifting.

Battery protection: Battery management algorithms for SOC limits, cycle limits, high temperature,

high currents duration.

3.5.1.2 Intro to Micro-Grid systems operation with SCADA

Modern microgrid systems need to incorporate high levels of solar photovoltaic PV to the annual energy

contribution as well as addressing the safe and reliable control of the system. As the price of PV drops

compared to the price of diesel fuel, the PV to load ratio in new systems is increasing on an economic and

sound financial basis. This solar PV power and other types of renewable inputs together with batteries

and conventional power generation units, can be connected all together to supply efficiently a local load

with or without a grid connection. System events such as load loss or variations in supply options are

managed in an orderly manner. SCADA EMS should incorporate closed loop fast control techniques

whereby short-term power events in the PV supply, the battery system and the diesel generators are

managed to ensure power quality. Best practice microgrid operation occurs when the solar energy is

maximized, the use of the diesel is minimized and the battery life is maintained to its highest level. The

local load should receive continuous 24 hour power and at good voltage and frequency regulation. The

control features of SCADA EMS are classified based on the priority of the control function and also the

necessary response speed of the control. Some controls must be very fast to react to sudden variations

whereas others can be slower and are more related to the scheduling of equipment in the system over

several hours. It is also essential that the controller used has suitable performance in warm, humid and

dirty environments and has a proven life without intermittent crashes or downtime. Among others,

SCADA EMS should provide inbuilt active/reactive control, power factor control, voltage and current

regulation. When the controller deems that the battery state of charge (SoC) is too low or the connected

load is too high on any one phase, it will issue a command to start a generator. While there is at least one

active battery converter (grid forming), the active controller (Generator) from the totalizer panel will

phase lock (synchronize) its frequency to that source. This frequency information from battery-converter

is also transmitted to all the solar inverters (slaves) via modbus RS485 communication. The EMS allows

the generators online if needed according to certain procedures. All inverters will move into a source


track mode that defines them as current controlled inverters. The EMS will be able to issue curtailment of

power export through appropriate Modbus commands to all solar inverters and battery converters, which

will slew their exported current (power) to lower values, allowing the genset to take part or all of the

connected site load if needed to ensure power quality and stability.

Regarding the battery system (BESS), SCADA EMS depending on certain parameters such as SoC, battery

availability etc, will command the battery converters to import/export power as required to

charge/discharge the battery or support PV-based charging. Temperature monitoring is a critical factor for

battery operation. The SCADA EMS should always consider the temperature of the battery system and

issues the necessary actions for stable operation. Regarding the diesel generators, when all the genset

stop criteria such as minimum genset run time and minimum genset loading have been met, the genset

will be taken off line, cooled down and stopped allowing the battery converters to continue supplying

power to the site.

High PV Penetration Aspects of Microgrid System

The High Penetration (Zero Daytime Diesel ideally) microgrid requires the system stopping the generators

during the daytime and mainly starting them for a minimum time during early mornings and evenings. In

the event of prolonged cloud cover when the battery cannot sustain the load energy requirements or the

inverter cannot sustain the load power requirements, the generators may be operated. The generator

scheduling will be programmed in the SCADA EMS controller. Cloud events or sudden load feeder changes

will cause aberrations on the local grid. Assuming there is no BESS, these transients will cause high step

load changes or ramp rates on the generator array. The generators have a specific maximum ramp rate

level over a specified period of time they can handle without affecting its output power quality. This level

will be often reached in high penetration systems. Generators are mechanical devices that have a specific

response time with regards to their speed control. The speed of the generator has to be constant to

maintain a constant frequency on the alternator voltage output. The generator speed is controlled by the

governor, which in its turn controls the throttle of the diesel engine. These mechanical aspects, coupled

with turbochargers that are increasingly being used on engines to improve engine efficiency, compromise

the reaction time to step load. Rapid changes in PV power affect the loading on the generator, which in its

turn affects the speed of the engine runs and therefore the output frequency of the alternator. Therefore,

the high PV penetration systems have to be able to handle the power quality variations introduced by

cloud cover effects or sudden changes on the PV production. The typical solution is to have an energy

storage buffer to cater for storing the solar power and the system transients. This is solved using a power

battery bank in conjunction with the parallel operation of battery converters. In this case, the battery

must serve two purposes:

• PV storage mode: Energy storage of the solar PV for use mainly at night-time.

• Load Balancing mode: Power transient capability to address cloud events and load transients.


The main control inputs of such a microgrid system would be the line frequency and line voltage. The

output power of the energy buffer is controlled according to the frequency calculations. The added

benefit of such a system with BESS, is that it will also take into consideration other events affecting power

quality such as the loss of feeders and others. To enhance microgrid control and ensure a sustainable

operation, the SCADA EMS will have a direct connection through Modbus TCP protocol with the installed

power analyzers at site. The power analyzers should be able to provide high resolution measurements

(<100ms) to the SCADA EMS, allowing for fast control (<500 ms).

3.5.1.3 SCADA for an autonomous Micro-Grid system (PV/Battery/Diesel Generators)

In the previous section above some applications of the SCADA EMS controller have been explained.

Though in this section, there is a real microgrid situation controlled by a SCADA system which is installed

in a university in Nigeria. This microgrid system consists of the following electrical power sources:

2x PV plants of 1751,4 KW dc installed capacity each one, with 50 string inverters of 60 KW AC

nominal power. Total PV installed in nominal AC 3.5 MW and nominal DC 3502,8 KW. Each PV

plant is connected to a 1800KVA step-up transformer of 0.38KV/11KV ratio.

3x Battery converters of 800KVA max AC power, with 2 battery containers each one, so in total 6

battery containers with max energy capacity installed of 6x1200Ah (1200Ah per container) =

7200Ah total energy capacity. Each battery converter is connected to a 800KVA step-up

transformer of 0.38KV/11KV ratio.

2 groups of Diesel generators with 3 generators in each group, totalling 6 gensets. The maximum

ac power of the generators goes as follows: 1st=635KVA, 2nd=500KVA, 3rd=350KVA. Each group

of diesel generators are connected to a 1600KVA step-up transformer of 0.415KV/11KV ratio.


In Figure 3.42 an Electrical single line drawing of a Microgrid System is depicted.

Figure 3.42: Electrical Single line drawing of the Microgrid system

Microgrid system Operational Flow Chart

It is described in depth the fundamental operation of microgrid system in Nigeria, which comprised of the

following five (5) subsystems: Solar PV production, Battery Energy Storage System (BESS), Battery

converters, Battery modules, Conventional diesel generator units → 2 x sets of parallel diesel gensets,

Energy Management System (EMS), Load consumption to be supplied.

A typical operational flow chart of a microgrid system during PV production, which combines all of the

aforementioned subsystems is as follows in Figure 3.43


Figure 3.43: Microgrid operation flow chart

During the day the AC coupled PV meets the load and also charges the battery groups (in PV storage

mode which will be described later) through the battery converters. As a high solar contribution system

the battery groups will be charged through the day and meet the lower loads at night time on most days.

THE EMS will also determine when to turn on/off the diesel generators as a prime or backup power

system.

Microgrid control modes

Load balancing mode (BL)

The battery group is used to cover instantaneous system power imbalances, either by absorbing the

excess PV production (charging) or supplying the deficit of instantaneous power demand (discharge). The

battery group will be charged/discharged (depending on system's requirements) based on specific

indicators and battery's max power capabilities in both directions (dis, cha) for at least 1 minute. If the

battery group goes beyond the limits, then step back action should be considered.


PV-storage mode (PV)

The excess power generation from PV will be stored for later use within the day (e.g to cover night loads).

The battery's internal temperature is mainly increased during the charging phase. The deeper the

discharge is the higher (approximately proportional) the expected rise in temperature during charge. If

during discharge the battery's temperature is high, then proactively, the EMS must restrict the depth of

discharge to lower levels than the default 60%. One of the most critical parameters for a BESS is the high

temperature. Preferably, the operating temperature in a typical discharge-charging cycle is:

Average 24-hour cycle temperature <30 Celsius (Ideally 25 Celsius degrees)

Maximum temperature at end of charge <35 Celsius (Ideally 30 Celsius degrees)

The following states for charge/discharge are foreseen during PV-storage mode.

Operational Discharge Phase (OD)

The battery is discharged during the afternoon or night, replacing or assisting the diesel generators, until a

predetermined desired discharge depth is reached. This phase of programmed discharging is called

Operational Discharge. For the BESS it is safer to discharge with low C-rates over a longer period (eg

coverage of small loads during night) rather than discharge with high C-rate for a short time (eg peak

demand coverage during afternoon). If, during OD, the battery is used to support the peak loads for a long

period then this can be done up to a certain current limit beyond which the generators will be forced to

supply the loads.

Idle after OD

At the end of the OD, the generators are activated and supply the loads while the BESS stays in idle state.

Normal Charge (NC) with PV

During sun peak hours, the battery groups in PV storage mode, absorb excess power from PV generation

(normal charge). Ideally, for optimal operation (economic perspective) the BESS should be able to absorb

all this “free” excess PV power. The only restriction to be set from EMS, for battery safety, is the charging

current. The limit is a function of the charging voltage.

Mode 1: 100% Solar Power utilization + BESS charging

Solar production exceeds local demand and supplies 100% of the load. Diesel generators are shut down.

The battery converters are responsible for grid forming. Intermittent behavior of solar production should

be considered. Therefore, BESS will support the system, maintaining stability by injecting extra power to

cover instantaneous peaks (for a limited period up to 5 minutes), or drawing excessive power from the

system. That part of the BESS (one battery group) will remain on balancing load mode to be ready to

support short-term disturbances of the system, while the remaining battery groups (if available) will be in

PV storage mode. Due to intermittent character of PV generation, PV output will be variable with output


drops that need to be compensated (eg. when a cloud passes over the site). Appropriately sized diesel

generators can cover the variability of PV output but this requires continuous operation of diesel gensets

(spinning reserve) respecting the minimum loading of 30-40% of rated power. On top of that, ramping up

and down the diesel generators typically increases the operational wear and fuel consumption.

Battery Availability

The EMS should be able to know the exact state of each battery group to optimize the operation of the

BESS and ensure continuous power supply to cover local loads. Each battery group consists of two (2)

parallel containers with 360 battery cells in series each. There is always the possibility to lose one

container due to failure of the battery cells or for safety reasons. In such a case, the EMS should be able

to adjust the BESS capabilities accordingly. For example, when a battery group loses one out of the two

containers, it will not be able to absorb or inject power with the same rate as if the battery group is

complete. The EMS should be able to calculate the BESS availability factor per group, which will be

multiplied with maximum & minimum limits.

For example, battery group A loses one container then BA_1 = 1/2. Thus, the security limit for maximum

charge current should be degraded by BA_1. The same also for the other limits. The EMS should be aware

also of the number of active battery groups and will assign a BL or PV mode accordingly. For example the

current microgrid system has three (3) battery groups. If the number of the active battery groups is higher

than one, then one battery will be used for BL mode, while the remaining two/one will be used in PV

storage mode. If the number of active groups equals one, then it will provide BL only or mixed PV-BL

services, according to battery's limitations. If no battery group is available, then the EMS should command

the diesel generator controller to activate the appropriate number of diesel generators, considering

minimum load per generator. In such a case, the EMS will be responsible to curtail part of the PV

production if needed.

Security Limits

The voltage and current safety limits are set to protect the battery in case of faults or uncontrolled

situations. They should be applied regardless of the charging state and are independent of each other. In

practice, they are guaranteed, in any case, by the EMS protection and the limited operation window of

the Converter. The maximum temperature limit is also set to protect the battery in uncontrolled

situations. If the battery system exceeds the max temperature limit, then the battery is immediately

switched off and is only manually reconnected by the system operator.

Mode 2: Hybrid Solar Power and Diesel Generators production

A blended arrangement of solar power production while diesel generators are synchronized and support

the system. In this option, solar production suffices local demand (e.g cloudy day) and BESS is not fully

charged. The diesel generators will be set online to provide the required power and maintain system's

stability. The battery inverter will be again (as in mode 1) responsible for grid forming. In such a case, the


EMS will determine if it is economically better to charge the batteries from diesel generators or not. More

in detail, a diesel generator reduces fuel consumption when it operates close to max efficiency (~80% of

rated power). Considering these as well as minimum loading limitation, sometimes it makes sense from

economical scope, to charge the battery from diesel gensets when there is no PV production on site.

Mode 3: 100% Diesel Generators production

When there is no solar PV production and the battery groups are not available, the only power source at

site are the diesel generators. This mode could be managed either by the EMS system in conjunction with

the diesel generator controller, or the diesel generator controller only. On the other hand, when there is

no available battery converter, the diesel generators are the only power source which form the grid. The

diesel generator controller detects no power generation on AC bus (like there is no grid available), which

results in the automatic transfer switch to close and the diesel generators will provide power to the

system. The diesel generator controller will be set automatically in load sharing mode. In this case, the

operation control and the communication parameters of each power generator unit, will be managed by

the controller, which will optimally determine which gensets should be powered on/off according to local

demand. Different combinations of diesel generators units will be used according to load profile at each

time for optimal operation. Two or more sets of generators in parallel operation are equal to one set of

large power generators to supply the load. They can balance the load over various circuits and

supplement the peak to valley mutually. During low demand periods, the smaller diesel gensets will be

utilized, operating close to the optimal point and reducing fuel consumption, which is critical. When the

gensets are at the operating condition by 80% of the rated load, the fuel consumption is minimum).

During peak hours, when there is no solar or BESS availability, bigger diesel units will be powered on to

supply the system.

In figure 3.44 we can see the Nigerian Microgrid project in operation through the SCADA system. The

chart displays one day of operation of the microgrid system and applies the modes discussed above when

needed. In Figure 3.44 we can see clearly 3 different situations to meet the load of the university. The first

one is early in the morning, the second one is during the day, and the third one is during the night.

During the night: The load is almost 750KW and must be served from the system. So, the BESS is

exporting about 200KW, with purple color, and the rest of the power needed is coming from the

generators, with green color. The BESS system is always in operation due to grid forming reasons.

During the day: The load is almost 1000KW at 10:00 o’clock in the morning, and the PV is producing more

than 1500KW. So the excess power from the PV is going directly to charge the batteries, as shown in

purple color with -500KW. Generators are out of production shut off.

During PV start up: The load in start up operation is slightly increasing and at this point the EMS should

decide to shut down the generators as the PV is penetrating with production. BESS is starting to charge

the batteries. Same procedure but with opposite signs in the shut down operation of the PV.


Figure 3.44: Microgrid operation through the SCADA system

The microgrid electrical status and operation can be monitored as well from the schematic page of the

SCADA system providing information to the user for more electrical oriented components. Also, the user

can proceed with any switch or circuit breaker operation through this page and monitor several electrical

faults. The overall electrical overview of the system as shown in Figure 3.45, is very helpful to check the

normal operation of the whole project. There are only few data presented just to give this simple view of

the system and make it easier to be handled by the user. In Figure 3.45 a Microgrid overall electrical

SCADA Schematic (Mimic) diagram is depicted.

Figure 3.45: Microgrid overall electrical Schematic SCADA page


The electrical schematic page above depicts all the transformers and feeders of the microgrid system as

well as the different power sources that participate in the microgrid control in order to meet the load of

the university. The feeders are the medium voltage cells rated for the specific project in Amps at 11KV.

The circuit breaker of each transformer is hosted there protected from a protection relay and also a

meter is installed for power metering reasons. At the end of the feeders’ lines there is an outgoing feeder

which is the most important as it hosts the main load meter for power consumption, basic component for

microgrid control operation.


CHAPTER 4

4. Energy Management & Control Centers

The EMS along with the control centers shall play a significant role for the smart grid evolution as they are

capable to provide concentrated capacity or energy in a software web based graphic interface. The energy

produced from the power stations are transmitted over large distances to meet the load of the customers

so the SCADA systems are the medium tool for implementing and aggregating all this information to a

human machine interface. The collected information in several points or the management of a power

source from a remote location can be called as an EMS energy management system. The first section

appeared in the market for such a system is the integration of a power station with a control center. This

helped a lot in the remote control of the power station and the energy management produced from it.

For the controlled station meanings like DA and DMS were introduced, distributed automation and

distributed management systems. For energy management the VPP meaning was introduced called a

virtual power plant. The systems connectivity and the ICT infrastructure is implemented with intelligent IT

systems with IP security and special SCADA protocols as referred in Chapter 2. In Figure 4.1 an EMS &

Control Center framework with SCADA is depicted.

Figure 4.1: EMS & Control Center framework with SCADA [1]


4.1 Control centers

A Control center is the basic station of managing power stations end to end. The control center systems

can provide all the flexible services needed to implement forecasting, power station dispatch, monitoring

of power generation, KPIs calculation, distributed substation automation, full power and voltage control

as well as data from the meters of the consumers side. Control centers also are monitoring step up or

step down transformers and they perform remote control with online tap changer features. A control

center consists of servers and HMIs along with SCADA field RTUs which are connected to the servers of

the control center. The field SCADA RTUs collect information from all substation peripheral devices

needed for all control center applications. A control center infrastructure could be as follows: A smart ICT

infrastructure in the control center with an RTU and servers based in a network and a VPN for each plant

connection to collect data and control the power plants. The control center RTU shall be connected with

the respective SCADA RTU in the field. In Figure 4.2 overall control center architecture is depicted. A

typical diagram is shown in Figure 4.3 form an Australian PV plant that is designed to be connected in the

local grid operator’s data control center.

Figure 4.2: Overall Control center architecture [12]


Figure 4.3: PV plant Control Center connection with local SCADA

4.2 Energy Management Systems (EMS)

Energy Management System is an intelligent vendor independent system providing dynamic optimization

of generation and revenues from a cluster of renewables plants within real time energy markets, utilizing

one or more Battery Energy Storage Systems. The renewable plants controlled could be composed of only

one plant (PV, Wind or Hydro) or a combination of them sharing the same grid connection and contract.

The optimization of generation involves the use of storage for minimizing curtailed energy: charging

within curtailment actions, discharging within other periods. Energy spot markets present opportunities

for energy arbitrage purchasing electricity from the electricity grid when it is cheap, and storing it for later

use when grid electricity is expensive. The optimization of revenues involves the use of price forecasts

from the market operator in order to plan, measure and control charge and discharge cycles and achieve

the optimum energy arbitrage scheme. EMS should continuously plan the optimum intra-day use of

storage, using the storage plant controller (Power Management System), the generation plants’ SCADA

systems, plant generation and availability forecasts and market pricing forecasts. In Figure 4.4 an EMS

architecture is depicted.


Figure 4.4: EMS Architecture

Communication with grid operator systems, plant SCADA and forecast services is performed using a

number of standard IP or RS-485 protocols (IEC 60870-5-104, DNP3, Modbus) as well as web-based

interfaces. The EMS objective is to provide stable, reliable, secure, and optimal power to consumers

efficiently and economically. Generally generation and transmission automation systems are termed

SCADA/EMS systems. The EMS system is hosted in the control center applications. The power flows in the

transmission systems are monitored and managed by the system operators in the centers. The

functionalities included in each of the subsystems are: [1]

A. Generation operation management

Real-time economic dispatch and reserve monitoring (ED)

Real-time automatic generation control (AGC)

B. Transmission operations management: real time

Optimal power flow and security constrained optimal power flow (OPF, SCOPF)

Islanding of power systems

C. Study mode simulations

Power flow (PF)

Short-circuit analysis (SC)

Network modeling

D. Energy services and event analysis

Event analysis


Energy scheduling and accounting

Energy service providers

4.3 Virtual Power Plant (VPP)

The virtual power plant (VPP) connects contracted renewable resources, batteries and flexible generation

assets in one system that can be optimised and steered remotely. The idea of VPP is to address the

integration issues related to DER through aggregation. Since VPP is more software dependent and can be

implemented under current regulatory structures, more and more attention has been paid to this idea in

recent years. [46] The main concept is based on a centralized control structure which connects, controls

and visualizes a work of distributed generators. Combined heat and power generators (CHP), fuel cells

(FC), photovoltaics (PV), heat pumps (HP), solar collectors and any other sources of power and heat might

be aggregated and cooperate together in the local area. This is a good solution for harnessing Renewable

Energy Sources (RES). VPP provides an opportunity to lower the load in the power network. More power

is generated locally and is shared by participants without needing to transmit it over long distances at

high tension. Therefore one energy loss factor is either minimized or eliminated. VPP causes a sea-change

in energy relations. VPP places more attention on local generation, meaning that central generation can

operate in more stable conditions.[47] For the optimisation of flexible generation assets a Dynamic Asset

Optimisation platform is used which reads the forecasts for the gas cost, carbon cost and power prices,

the availability schedule and technical parameters as well as live prices and trades to create an optimised

schedule for when to dispatch the power from the site. This schedule is regularly sent to the asset and the

latest schedule is stored locally either in the control system or a VPN Router. [46] In Figure 4.5 on

overview of services of a VPP provides is depicted.

Figure 4.5: Overview of VPP


The VPP aggregates many heterogeneous Distributed Energy Resources (DERs) to function as a single DER.

It also has the inherent capacity to include the influence of the system on the aggregated DER output. In

order to participate in the electricity market, the VPPs have non dispatchable and dispatchable power

plants including renewable and nonrenewable ones, storage units such as batteries and pump storage,

and responsive loads that have some flexibility in their consumption energy levels. [48]

4.3.1 SCADA Systems & VPP

A SCADA system can integrate and play the role of VPP aggregating different power sources like

renewables and non renewable. In Figure 4.6 we can see a very extensive paradigm of a SCADA system

playing the role of VPP. Different power sources like Wind power plants, PV power plants, BESS,

Microgrids, and Gas turbine projects all in the same HMI page providing flexibility for the operator to

handle the energy market requests as well as to perform the demand and production forecast. The

SCADA system can provide information regarding the availability of each power plant, the available

energy capacity and power. Apart from that the control features to dispatch the systems is also important

as it is the next step of the energy market bidding system. All the power plants have been integrated into

the SCADA platform via specific secure protocols and they provide all control features related with the

VPP. In Figure 4.6 VPP services through scada are depicted.

Figure 4.6: SCADA & VPP


The SCADA features of the VPP implementation could have the following: Safety and Priority of Input

Signals: The priority of the control signals needs to be programmed into the SCADA. In all cases inputs

with health and safety or operating permit and permission implications must have a higher priority than

the schedule from the VPP. The suggested priority is as follows: Safety, Network Operator, O&M, Owner,

VPP. Data Connection Requirements: VPN to be established with low bandwidth requirements,

Broadband router with high uptime, hardwire preferred, Redundant internet connection preferred.

The VPP will transmit the Facility’s schedule based on the output of the Dynamic Asset Optimisation

platform and trades made (including input from the Intraday trading team). As short term electricity

markets are often volatile this schedule will be updated regularly. At any time the Facility’s latest schedule

should be stored locally either in the remote control box or in the site’s control systems. This way if the

plant loses internet connection this latest available schedule will be delivered by the Facility provided it is

safe to do so. It is important that you implement any safety requirements, as the site operator the safety.

Remote Control Boxes: Each control box (RTU) installed in each power plant to establish the connection

with the VPP SCADA. It can work in parallel with the Main Plant SCADA and use the same internet

connection channel to set up and initiate the IPSEC from the site to the VPP SCADA side.

Scheduling: The Facility engines can be given a set point as a binary on/off or with a defined KW output.

For a Facility with multiple engines it needs to be agreed whether we should schedule the individual

engines or the site as a single asset. For safe operations the minimum load per engine needs to be

specified. Lost connection to remote control boxes proposes that engines will shut down if they lose

communication with the remote control box to avoid any penalties in exceeding the agreed limits in the

gas supply. The warning alarm will be set to 5 seconds and the reset to 2 seconds and the Engine

Shutdown to 10 Minutes.

Default signals list for engines: Connection heartbeat, Individual engines: 1. Reading availability (on/off),

2. Reading active power (kW or MW), 3. Send set point (kW or MW), Site: 1. Read availability (MW or % of

total capacity), 2. Read active power (kW or MW), 3. Send a set point (kW or MW), Watchdog from box to

engine or vice versa.

4.3.2 VHP Ready Protocol

The VPP implementation includes a TCP/IP communication and specific points data list in order to

integrate a power system in the VPP SCADA Platform. In this point the VHP ready protocol standardizes

the communication procedure between the power plant and the control centers. So, the VHPready

standard applies to the communication path between a control center (CC) and a distributed energy

resource (DER) or technical unit (TU). The VHPready standard should create security and interoperability

for the connection of technical units. The objective is to minimize the effort/cost for the integration of

new technical units. Changing a technical unit from one control center to another, for instance in case of a


marketer switch, should become very simple. In Figure 4.7 a Schematic description of the VHPready 4.0

scope is depicted.

Figure 4.7: Schematic description of the VHPready 4.0 scope

If a control center meets the VHPready specifications, it is called a VHPready-compliant control center. If a

technical unit meets the VHPready specifications, it is called a VHPready-compliant technical unit. After

successful certification, the technical unit or control center becomes VHPready-certified. The VHPready

compliance is based on three preconditions that have to be met by the control center and technical unit:

1. Communications between control center and technical unit use a Virtual Private Network (VPN) that

follows the VHPready specifications. The technical unit creates a VPN connection to the control center.

The VPN connection is IP-based. Which medium is used to transmit IP packages between the technical

unit and the control center is not part of the VHP standard's scope and can be chosen freely.

2. The remote access connection between control center and technical unit has to be realized with one of

the remote control protocols allowed for VHPready. Data has to be transmitted by TCP/IP within the VPN.

The remote access connection from the control center to the technical unit is created.

3. The data points of the remote access connection between control center and technical unit have to

follow the VHPready specification. The defined response behaviour also has to be observed. During the

VHPready certification process, all requirements are verified by an independent third party and a

VHPready certificate is issued if these are all met. The response characteristics with regard to the

generation or consumption of electricity as well as the actual responses for other energy carriers are

explicitly excluded from the VHPready specification. The VHPready specification exclusively concerns the

specification of communications behaviour. In Table 4.1 the VHP ready signals are depicted.


VHP ready Data points for CHP/Wind/PV/HeatPump/Battery/ElectricalHeating/Boiler/HeatStorage

with IEC 60870-5-104 protocol

Table 4.1: VHP Ready Signals

Signal Type IEC104 format Signal description

Standby (ready / not ready) Binary 30 (M_SP_TB_1)not ready stands for malfunction of combined heat and power (CHP) unit

Status (on / off) Binary 30 (M_SP_TB_1)On any power level != 0: „plant is on“ stands for binary value 1, plant is then connected to grid

Starting sequence finished Binary 30 (M_SP_TB_1)

Although the starting sequence has been finished, the plant could still be unconnected to the grid

Fault Code Bit mask 33 (M_BO_TB_1)various malfunctions, please refer to the fault code overview

positive installed capacityFloating PointNumber 36 (M_ME_TF_1)

positive installed capacity, positive for energy production units

negative installed capacityFloating PointNumber 36 (M_ME_TF_1)

negative installed capacity, negative for power consumption units

generated/absorbed electrical powerFloating PointNumber 36 (M_ME_TF_1)

In case of separate measurements of active power and idle power then active power, otherwise idle power; positive for feed in

idle powerFloating PointNumber 36 (M_ME_TF_1) idle power, positive for power input

current on L1Floating PointNumber 36 (M_ME_TF_1)

current on L1, positive in case of of feed in, negative in case of consumption





voltage between L1 and L2Floating PointNumber 36 (M_ME_TF_1) voltage between L1 and L2




voltage between L1 and NFloating PointNumber 36 (M_ME_TF_1) voltage between L1 and N



grid frequencyFloating PointNumber 36 (M_ME_TF_1) measured grid frequency

phase angle cos(phi)Floating PointNumber 36 (M_ME_TF_1)

Value indicates deviation from cos(phi)=1. For overexcitation positive values, for under excitation negative values.

Communication protocols

Communication between the technical unit and the control center is encrypted and takes place via IP

networks, either based on standard IEC 60870-5-104 or the series of standards IEC 61850 (in particular IEC

61850-7-420). Time synchronization takes place via SNTP/NTP. The following protocols are used for

communications: either IEC 60870-5-104 or IEC 61850-7-420, TCP/IP, TLS, SNTP/NTP.

Operation modes: Any technical unit is in one of three different operation modes. As long as the technical

unit is not externally controlled it remains in the autonomous mode. As soon as the control station takes

over control, the technical unit transits into either the scheduled mode or the power setpoint mode. The

individual operation modes are described below in more detail.

Autonomous mode: In autonomous mode the technical unit has no external control impetus. The system

operates as defined by the system control.

Scheduled mode: In scheduled mode the technical unit follows the schedule transmitted from the control

station to the gateway. A future schedule may be transferred to and stored in the gateway at any time.

Parts of or the full schedule may be deleted from the gateway or overwritten there. The information is

contained in the information objects “working point schedule transmission part 1 and 2 for absolute

schedule values”.

Power setpoint mode: In power setpoint mode the control station provides a nominal power setpoint to

be delivered by the technical unit. This nominal setpoint describes an actual demand value. Due to this it

is not possible to transmit upfront any future setpoint differing from the recent nominal power value. The

information is contained in the information object “power setpoint determining an absolute value”.

Loss of connectivity: In case the technical unit loses connection to the control station during scheduled

operation mode, the scheduled operation mode remains active. In case of a connection loss during power

setpoint operation mode, the technical unit drops back into scheduled operation mode.


4.4 CIM (Common Information Model)

Distribution companies often use different information technology (IT) platforms from separate vendors

to implement functions like OMS, AMI, and GIS. These systems generally use proprietary formats for data

exchange, and ensuring the data exchange between different systems is a formidable task. Developing

special adaptors for this purpose consumes a lot of money and manpower in a utility IT department. The

common information model (CIM) is an attempt to establish a uniform language and domain model for

energy management systems and related data structures. CIM builds an integrated platform to connect

the different applications in a distribution utility and is defined in IEC 61970. The core package defining

the CIM is IEC 61970-301. IEC 61970-501 and IEC 61970-452 define XML format for network model

exchange. IEC 61968 defines the distribution-related data integration for DMS, OMS, AMI, GIS, CIS, and

planning. [1] In Figure 4.8 SCADA and smart grid protocols in use and under development in CIM model

are depicted.

Figure 4.8: SCADA and smart grid protocols in use and under development [1]

4.5 Grid compliance

The grid compliance procedure can take place in any renewable power station, and nonrenewable, in the

frame of a power station to be certified to inject into the grid. This is a procedure that certifies a plant to

connect through a SCADA system to be able to respect the grid requirements. The SCADA system is

mandatory in this procedure as the smart grid concept cannot be either achieved. The SCADA system will

perform all commands required in the power station when it injects into the grid to regulate active and

reactive power or voltage control. Concluding, grid codes specify the electrical performance that

generation assets must comply with in order to obtain the required approval for its connection to a grid.

Demonstrating grid code compliance and achieving a grid connection agreement are, therefore, essential


milestones in the development of a power plant project. [49] The grid code is different from country to

country so this is a hard procedure every time for a SCADA engineer to set up the appropriate software

that complies with the grid code requirements. Grid code compliance verification has a double objective.

On the one hand, plant owners are responsible for demonstrating compliance of the grid code to the

relevant network operator. And, on the other hand, network operators have to assess the compliance in

order to ensure that the new plant will not adversely affect the secure operation of the power system.

[50] As a SCADA procedure, the power station must be connected through a data transmission protocol

DNP3, modbus TCP/IP or IEC 60870-5-104 to the control center. The control center will accept commands

through a telephone line or through an email from the responsible operator of the grid operations center

each time. The control center shall execute these commands through the specified data transmission

protocol as it has been described between them in a file. Some typical exchange data points between a

power station SCADA and the control center can be as follows in Table 4.2:

Table 4.2. SCADA & Control center data points for Grid Compliance with IEC104 protocol

Description Engineering Units IOA Number ASDU ID Type

Plant Active Power Setpoint MW 201 30 Analog Output

Plant Reactive Power Setpoint MVar 202 30 Analog Output

Plant busbar voltage Setpoint KV 203 30 Analog Output

Plant Circuit breaker Status 0/1 204 30 Binary bit

4.6 AI in SCADA systems

The evolution of the AI has already been in the SCADA systems technology giving a new era for the

systems themselves as well as the servers database. These two systems can work with each other and use

the computational power of the server to perform several AI tasks and present them in the web consoles

or other HMIs. This feature can be used to perform production forecasts of a renewable energy source

such as a PV or Wind, based on the weather forecast of the previous years and the next few days. AI has

several advantages when running on the servers and not as a daily procedure through a computing

program. It delivers automation and flexibility for the users and the operators. As depicted in the

following Figure 4.6 the system’s marginal price of Greek market is calculated through the SCADA system

with ftp data import. What has been exported from Henex is an input to the SCADA system in order to

provide historian functionality, database, graph features and overall aggregated information. However,

Figure 4.9 could be the same output of the SCADA system when the SMP shall be calculated from an AI

procedure. It presents the day ahead pricing on a 24 hour basis with one value every hour and the graph

could be something like Figure 4.9. The SMP calculation provides flexibility and cost effectiveness of the


utilities dispatch of the producers. They can schedule the day ahead production with the SMP calculation.

In Figure 4.9 a System’s Marginal Price computation with ftp data import to SCADA is depicted.

Figure 4.9: System’s Marginal Price computation with ftp data import to SCADA

The prediction of System's Marginal Price (SMP) has become a crucial issue that the Independent Power

Producers(IPPs) are facing since electricity industry privatization. A neural network model can be used to

predict SMP at each Settlement Period on the next Scheduling Day. Moreover, the Greek Energy Market is

structured as a mandatory pool where the producers make their bid offers on a day-ahead basis. The

System Operator solves an optimization routine aiming at the minimization of the cost of produced

electricity. The solution of the optimization problem leads to the calculation of the System Marginal Price

(SMP). Accurate forecasts of the SMP can lead to increased profits and more efficient portfolio

management from the producer’s perspective. The analysis can give machine learning model, artificial

neural networks for the prediction of the SMP of the Greek market. Machine learning algorithms are

favored in predictions problems since they can capture and simulate the volatility of complex time series.

[50]. In Figure 4.10 an overview of SCADA structure with SMP calculation is depicted.


Figure 4.10: Overview of SCADA structure with SMP calculation

4.6.1 SCADA Systems advanced features

4.6.1.1 KPIs

The latest technology of the SCADA systems is related to the usage of a very strong data server that can

execute several hard computational tasks. These tasks are related to data written in the database of the

server and called when the server wants to calculate a specific formula. This formula is called a KPI. Key

Performance Indicators (KPIs) are of two (2) types: Primary parameters (measurements) & Derived

parameters, calculated by the cloud server. KPIs can be calculated and presented in the SCADA platform

over different time periods (main recording period, day, month etc). A KPI could be for example, the

performance ratio of a PV plant according to the IEC61724. The performance ratio of a PV plant is the

value that confirms optimum production of the utility and can be accepted from the clients and investors.

This has to be up to 80% when tested in order the PV to be accepted.

Raw PR = (Exported Power Site/ Nominal Power DC) / (Irradiance PoA Average/1000). In Figure 4.11 a

performance ratio KPI of a SCADA system is depicted.


Figure 4.11: Performance ratio KPI of a SCADA platform

Other useful KPIs for a power station could be the following:

Exported Energy Site : The site’s energy exported at the point of common coupling (PCC)

BESS total cycles : the ratio of the site’s total energy (sum of exported and imported energy)

divided by the twice the nominal energy capacity of the site

Batteries SOC Average [%]: The average state of charge of all batteries installed in the site

Site inverters availability [%]: The weighted average (per nominal energy capacity) of all the

inverters installed in the site


4.6.1.2 Inverters Heatmap

In the SCADA systems we can find powerful servers that can calculate several hard formulas and tasks.

Hence, sometimes the representation of the data with different ways can give more flexibility in the

operator and maintenance engineers to sustain a reliable system. As an example, and as depicted in

Figure 4.12, we have the daily inverters power in a photovoltaic system in KWs which is a very critical

daily value for the operators. Instead of making graphs daily with the inverters active power the heatmap

provides a better visualization of the existing problems. It uses a scale from 0 to 1. 0 means that the

system is in halt due to no production, all the values until the 0.75 is the production rising and the 1 is the

full production and the healthy state. So, if there is a problem with an inverter’s production when all the

other inverters producing the heatmap will show this extensively. As depicted in Figure 4.12 there is a

yellow continuous line which means that this particular inverter is not following the correct production as

the others. The power of each inverter is always correlated with the active irradiance value in order to

show the real problem. If the production is more than 80% the green color is used.

Figure 4.12: SCADA heatmap feature for PV inverters


CHAPTER 5

5. SCADA Based Smart Grids Conclusion

5.1 Overall Conclusion

The purpose of this document is to describe the ways that a power system can be handled, in terms ofpower control, through a SCADA system and if the SCADA systems are mandatory in order to convert theexisting grid in a Smart Grid. Also, the techniques of the power control of each power station aredescribed thoroughly. The term “power control” is not as simple as it can be heard but much morecomplicated and it shall be explained thoroughly below. The purpose of the power control is to give thegreen light of a power production station to export in the Grid and convert the existing transmissionsystem to a smart transmission system. When the power production station can export under certaincircumstances and values respecting the grid requirements then the SCADA system can do the job anddeliver energy as requested from the Grid. From the other side, a power station as mentioned severaltimes can be either a power station in renewables or a typical battery storage power station or amicrogrid power station. A renewable power station is much more uncertain in terms of production andthe SCADA system is 100% mandatory in order for the station to be connected into the grid. All of themconsist of the future of power production in the smart cities and in the distributed generation. The SCADAsystems must be installed along with the power stations. Then, the data of the power systems have theability to be connected with the VPP aggregators or the control centers in order to proceed with powercontrol and motivation setpoints, and this is a major advantage because that way the systems can beunder the Grid operator’s responsibility and export on demand depending on the forecast of each day.Additionally, the term power control as referred above can be splitted in many ways as required eachtime from the Grid operator such as volt-var control, watt control, ramp rate control of the power systemand watt control with frequency. All these features can be provided from a SCADA system connected tothe power station.

Finally, the overall output of this research is the following: The SCADA systems are representingthe critical parts of the Smart Grid System. The SCADA systems are mandatory for the good operation ofthe grid transmission lines, the substations and the good operation of the power production stations.Every new large scale project that is being built in any country has to be controlled and has to respect thegrid and so that means that the SCADA system is mandatory to provide these services. The SCADA systemmust provide flexibility, controllability, interoperability, user friendly services for operations andoperators, and secure network connectivity with the outer space in the power station and perform allfunctionalities required to transform the existing grid into a SMART GRID. In Figure 5.1 a complete SmartGrid with Scada system is depicted.


Figure 5.1: A Complete SMART GRID with SCADA System [51]

The ongoing integration of more renewable energy resources and new technology, like energy storage

systems, into smart grids requires the full integration of ICT into power transmission and distribution

systems. To guarantee a stable power grid, many approaches propose Decentralized Energy Management

(DEM), which relies on Supervisory Control and Data Acquisition (SCADA) networks to communicate

sensor readings and commands between the individual components and their control server. Due to the

increasing number of Distributed Energy Resources (DERs) such as PhotoVoltaic (PV) panels, real-time

monitoring and control is required also at medium and low voltage levels. [52] SCADA empowers the

consumer by interconnecting energy management systems to enable the customer to manage their own

energy use and control costs. It allows the grid to be self-healing by instantly responding automatically to

outages, power quality issues, and system problems. [51] As depicted in the image 5.1 above the SCADA

systems in the SMART GRID world will export enormous amounts of data in the cloud servers of the VPPs

or the Control Centers and that’s because we want to achieve the energy demand scenario and create

models of forecast and profiles of consumers. Also, the energy market requires data storage because they

must feed the neural networks with a vast amount of data in order to proceed with forecast prices for

systems marginal price calculation and more.


5.2 Concept of SMART GRID conclusion

The stable quality of energy generation is an essential parameter for energy utilization and financial

improvement. SmartGrid is an innovative concept for energy systems that involve sophisticated

communication and advanced control technologies for Implementation. Key features and Smart Grid

along with SCADA systems technology include: [53]

self-healing

incorporates and authorize the user

tolerates safety attacks

offers the improvement of the energy quality

hosts several sources of generation

Fully Supports The Energy Market

Optimize the use of resources and reduces the operating costs of the system and maintenance.

All the large scale power stations connected at high voltage transmission lines must be installed along

with a SCADA system to provide all features of power control. The features of power control can be as

follows both for renewables and non renewables power production stations: Active power control with

setpoints through a control center or VPP or a local operator, Active power control with ramp up rate in

KWs or MWs, Reactive power control with direct setpoints, Power factor control along with reactive

power control, Frequency control with active power import or export, Voltage control through reactive

power. Each power station shall provide the services that are expected each time into the Grid. More

specifically: For PV power plants the operator and the owner have the obligation to install a smart SCADA

in their production station and respect the grid requirements through it. A large scale PV plant shall be

connected through the SCADA to the control center and shall obey the rules and the setpoints of the grid

with ramp ups and downs. For a battery storage site: It shall be instructed once from the energy market

or from the VPP (the SCADA shall be instructed) in order to provide the grid services, and the most

common service for a battery site is the firm frequency response. The battery site shall automatically start

exporting or importing accordingly, to balance each time the frequency in the HV transmission network

(132 KV as an example). Finally the microgrids are the smart grids themselves: Either off or on grid these

power production stations can balance their fluctuations automatically running a very smart software.

They can perform self-healing and satisfy the load any time in different ways. They consist of many

technologies and power sources fine tuned with a smart software which is the most important part of a

microgrid. Microgrids can work totally independently and stand alone feeding a small village with energy

and if needed to be connected and support the grid with excess power.

The VPP aggregators shall play a significant role in the near future as they use the SCADA systemsto aggregate power capacity. The concept of SCADA and power station connection with a control centerfor grid compliance will always be present in large scale power stations due to the certification that canbe obtained to the power station to export and start making profit. All the interconnection concept fromthe site to the VPPs and control centers is related always with the interoperability procedure needed eachtime to certify the SCADA protocol running in a plant with the corresponding protocol of the control


center of the grid operator. The grid compliance is a procedure that will become significant in the nearfuture in the evolution of the smart grid.

The smart and evolved SCADA systems shall be equipped with strong data servers to performseveral tasks. Apart from the data logging of the servers the KPIs function calculation is important as well.As explained, the servers can do the job on such cases performing AI in the SCADA platforms. AI can beused either for energy/power forecasting or energy market for SMP calculation. Another advancedfeature of a SCADA system equipped with a strong data server can be the calculation of some advancedmetrics. An advanced metric can be useful for the plant operators or the grid operator or the VPP who ishandling the energy market. Such a metric can be a plant availability calculation or plant availablecapacity of the next day depending on the weather forecast, or the energy stored in a battery storage sitewith SOC and Ah capacity measurements or the SMP calculation for the energy market. Finally, The AI inSCADA systems is something that is still growing using several methods in the servers to calculate difficultand hard functions.


References

1. Power Systems Scada and Smart Grids - Mini S. Thomas Jamia Millia Islam a University New DelhiIndia John D. McDonald GE Energy Management - Digital Energy Atlanta, Georgia, USAhttps://ieeexplore.ieee.org/author/37276382400

2. Process Automation Systems- History and Future Christer Rameback Vice President Head ofProcess Automation ABB Automation Technologies SWEDEN https://ieeexplore.ieee.org/abstract/document/1247680

3. Future SCADA challenges and the promising solution: the agent-based SCADAhttps://www.researchgate.net/publication/269984583_Future_SCADA_challenges_and_the_promising_solution_the_agent-based_SCADA

4. EVOLUTION OF SCADA SYSTEMS Alexandru UJVAROSI http://webbut.unitbv.ro/BU2015/Series%20I/2016/BULETIN%20I%20PDF/Ujvarosi_Al.pdf

5. Two Decades of SCADA Exploitation: A Brief History Simon Duque Anton, Daniel Fraunholz,Christoph Lipps, Frederic Pohl, Marc Zimmermann and Hans D. Schotten Intelligent NetworksResearch Group German Research Center for Artificial Intelligence DE-67663 Kaiserslauternhttps://ieeexplore.ieee.org/document/8270432

6. Design of a system solution that modernizes legacy supervisory control and data acquisitionsystems as an early detection system Beşir Demir, Ahmet Tumay, Mehmet Efe Ozbek and EnverCavushttps://www.researchgate.net/publication/325856572_Design_of_a_system_solution_that_modernizes_legacy_supervisory_control_and_data_acquisition_systems_as_an_early_detection_system

7. Adaptive Agent-Based SCADA Systemhttps://www.researchgate.net/publication/277404667_Adaptive_Agent-Based_SCADA_System

8. RTU Hardware Design for SCADA Systems Using FPGA Soroush Shirali, Shahab Ensafi, MahsaNaseri Electrical and Computer Engineering Faculty, Shahid Beheshti University Evin, 1983963113,Tehran, Iran phone: + (98) 9121034736, fax: + (98) 212417940, email [email protected] Web:www.sbu.ac.ir

9. A comprehensive review of the application characteristics and traffic requirements of a smart gridcommunications network Reduan H. Khan, Jamil Y. Khan School of Electrical Engineering &Computer Science, The University of Newcastle, Callaghan NSW 2308, Australia

10. BASICS OF THE RS-485 STANDARD 11. A comprehensive review of the application characteristics and traffic requirements of a smart grid

communications network Reduan H. Khan , Jamil Y. Khan School of Electrical Engineering &⇑Computer Science, The University of Newcastle, Callaghan NSW 2308, Australia

12. Communication Networks for Smart Grids Kenneth C. Budka Jayant G. Deshpande Marina ThottanMaking Smart Grid Real

13. Securing DNP3 Broadcast Communications in SCADA Systems Raphael Amoah, Member, IEEE,Seyit Çamtepe, Member, IEEE, and Ernest Foo, Member, IEEE

14. Implementation of Modbus RTU and Modbus TCP Communication using Siemens S7-1200 PLC forBatch Process


15. Simulation of the DNP3 Protocol Over TCP/IP on a Network IEEE 802.11g Ad-hoc With SmartMeter.

16. Flexi-DNP3 : Flexible Distributed Network Protocol Version 3 (DNP3) for SCADA security.17. Implementation of IEC 60870-5-104 Protocol Based on Finite State Machines18. Application of IEC61850 in Energy Management System for Microgrids19. Implementation Techniques of the IED and Network Monitoring System in IEC61850 SA20. Feeder Automation Modeling in IEC61850 Zhao Wang, Lei Jing, Wenxiao Ma21. An Emulation of Data Concentrator Units Conformed to DLMS-HDLC Protocols Siwarat

Limpaphayom, Wanchalerm Pora22. A Simulation of a Communication between a Smart Meter and a Data Concentrator Unit

Conformed to DLMS/COSEM upon an HDLC Profile 23. Packet Transfer of DLMS/COSEM Standards for Smart Grid24. https://www.researchgate.net/publication/

331314006_European_Union_legislation_for_demand-side_management_and_public_policies_for_demand_response

25. https://library.e.abb.com/public/ea9369892f3743f582fed9f57216301b/MiniCap%20Brochure- June2015-final.pdf

26. Effect of Three Pole Auto-Reclose to Power System Transient Stability (Case Study: Jawa Timurand Bali System) https://ieeexplore.ieee.org/document/8710957

27. Auto-reclose Relay Simulation for Research and Education *Muhd Hafizi Idris, Mohd Rafi Adzman,Mohammad Faridun Naim Tajuddin, Melaty Amirruddin and Mohd Alif Ismail Centre of Excellencefor Renewable Energy (CERE) School of Electrical System Engineering Universiti Malaysia PerlisArau, Malaysia *[email protected] https://ieeexplore.ieee.org/document/8703542

28. A Comprehensive Security Analysis of a SCADA Protocol: From OSINT to Mitigationhttps://ieeexplore.ieee.org/document/8672892/versions

29. IDS Based Network Security Architecture with TCP/IP Parameters using Machine Learning https://www.researchgate.net/publication/332430659_IDS_Based_Network_Security_Architecture_with_TCPIP_Parameters_using_Machine_Learning

30. A Thin Security Layer Protocol over IP Protocol on TCP/IP Suite for Security Enhancementhttps://ieeexplore.ieee.org/document/4085435

31. Security with IP Address Assignment and Spoofing for Smart IOT Devices S Rajashree1, Soman KS2, Dr. Pritam Gajkumar Shah3 1 Research Scholar, Department of Computer Science andEngineering, Jain University, Bangalore, India 2 Software Consultant 3 Ph.D, Department ofComputer Science, Jain University, Bangalore https://ieeexplore.ieee.org/document/8554660

32. FACTS – Flexible AC Transmission Systems An extended analysis of FACTS for Grid stability &transfer reliability on Power Systems. Lambros Tsintzouras – Department of Electrical & ComputerEngineering - University of Thessaly – Volos Greece email: [email protected]

33. FACTS Flexible Alternating Current Transmission Systems Gabriela Glanzmann EEH - PowerSystems Laboratory ETH Z¨urich 14. January 2005.https://pdfs.semanticscholar.org/f7df/176825535496e089651eaeda8a53d9db9c94.pdf

34. PV-STATCOM: A New Smart Inverter for Voltage Control in Distribution Systems Rajiv K. Varma,Senior Member, IEEE and Ehsan M. Siavashi,Member,IEEE, https://ieeexplore.ieee.org/document/8586325


35. Solar Photovoltaic Inverter Requirements for Smart Grid Applications M. Bouzguenda (IEEE S.Member), A. Gastli (IEEE S. Member), A. H. Al Badi (IEEE S. Member) and T. Salmihttps://ieeexplore.ieee.org/document/6220799

36. Gas Turbine Working Principles March 2015 DOI: 10.1007/978-3-319-15560-9_7 In book:Combined Cycle Driven Efficiency for Next Generation Nuclear Power Plantshttps://www.researchgate.net/publication/300857212_Gas_Turbine_Working_Principles

37. https://www.nap.edu/catalog/25630/advanced-technologies-for-gas-turbines 38. A review on energy management, operation control and application methods for grid battery

energy storage systems https://ieeexplore.ieee.org/document/873543139. Optimum Operation of Battery Storage System in Frequency Containment Reserves Markets Poria

Hasanpor Divshali and Corentin Evens https://ieeexplore.ieee.org/document/910313440. Strategies for Reactive Power Control in Wind Farms with STATCOM Francisco D´ıaz Gonzalez 1,

Marcela Mart´ınez-Rojas2, Andreas Sumper12, Oriol Gomis-Bellmunt12, Llu´ıs Trilla1https://core.ac.uk/download/pdf/41759511.pdf

41. Power Control Design for Variable-Speed Wind Turbines Yolanda Vidal 1;*, Leonardo Acho 1,Ningsu Luo 2, Mauricio Zapateiro 1 and Francesc Pozo 1https://www.researchgate.net/publication/277441209_Power_Control_Design_for_Variable-Speed_Wind_Turbines

42. Exploiting SCADA System Data for Wind Turbine Performance Monitoring Shane Butler1, JohnRingwood1 and Frank O’Connor2 https://core.ac.uk/download/pdf/297020404.pdf

43. Modeling and Control of Wind Turbine Luis Arturo Soriano,1 Wen Yu,1 and Jose de Jesus Rubio 21 Departamento de Control Automatico, CINVESTAV, National Polytechnic Institute, 07360Mexico City, DF, Mexico ´ 2 Seccion de Estudios de Posgrado e Investigación, ESIME Azcapotzalco,National Polytechnic Institute, 02250 Mexico City, DF, Mexicohttps://www.hindawi.com/journals/mpe/2013/982597/

44. Smart Metering and Functionalities of Smart Meters in Smart Grid - A Review Gouri R. Barai,Student Member, IEEE, Sridhar Krishnan, Senior Member, IEEE, and Bala Venkatesh, SeniorMember, IEEE https://ieeexplore.ieee.org/document/7379940

45. MICROGRIDS ARCHITECTURES AND CONTROL Edited by Professor Nikos Hatziargyriou NationalTechnical University of Athens, Greece.

46. Developing Virtual Power Plant for Optimized Distributed Energy Resources Operation andIntegration You, Shi Publication date: 2010

47. Virtual Power Plants – general review: structure, application and optimizationI ŁukaszNikonowicz , Jarosław Milewski Warsaw University of Technology, Institute of Heat Engineering)∗21/25 Nowowiejska Street, 00-665 Warsaw, Poland

48. A Review on the Virtual Power Plant: Components and Operation Systems Sahand Ghavidel and LiLi, Jamshid Aghaei, Tao Yu, Jianguo Zhu.

49. Current procedures and practices on grid code compliance verification of renewable powergeneration Agurtzane Etxegarai, , Pablo Eguia, Esther Torres, Garikoitz Buigues, Araitz Iturregi∗Department of Electrical Engineering, University of the Basque Country UPV/EHU, Bilbao https://www.researchgate.net/publication/312413618_Current_procedures_and_practices_on_grid_code_compliance_verification_of_renewable_power_generation


50. Short-term forecast of System's Marginal Price (SMP) for Greek electricity market SoldatosStavros & Lambros Tsintzouras – Department of Electrical & Computer Engineering - University ofThessaly – Volos Greece email: [email protected] [email protected]

51. https://www.researchgate.net/publication/ 331314006_European_Union_legislation_for_demand-side_management_and_public_policies_for_demand_response

52. An integrated testbed for locally monitoring SCADA systems in smart grids Justyna J. Chromik1*,Anne Remke and Boudewijn R. Haverkort.

53. A Review of the Smart Grid Concept for Electrical Power System.


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