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1 INTRODUCTION
A smart grid is a new approach to the integration of power generation, trans mission systems, distribution networks, and consumption. A smart grid should encompass features so as to be:
_ Adaptive;
_ Interactive;
_ Predictive;
_ Integrative; and
_ Optimized.
The smart grid should be able to adapt to all types of generation sources, including conventional large thermal power plants and intermittent renew able energy sources such as wind and solar PV generation without restriction. The smart grid should be able to connect such generation sources at all voltage levels and at any locations including distributed generation and micro-generation.
Arguably, the most innovative part in the smart grid is its demand response (DR), which is largely facilitated by the use of smart meters and an associated advanced metering infrastructure (AMI). Smart meters can pro vide real-time information on the demand and price from different suppliers to customers, so as to allow them to decide when they want to buy electricity, from whom, and at what price. This will not only provide "freedom of choice" but also allow customers to interact with the network operators and suppliers in, or near, real time.
The intention is that by applying the latest technologies, the information infrastructure will collect all necessary system operational and customer data in real-time. The open architecture information system and database will be able to store a vast of amount data and process this in near real-time. This will greatly help to make the power system behavior more predictive and easier to understand and control than historically.
The smart grid will collect the real-time power system data (at the milli seconds level) required by the protection and control systems. The integrated communications, protection and control systems will bring this data under one common domain and will share and process this as specified in IEC 61850.
By applying the latest technologies, the smart grid will be designed (and existing systems refurbished) to operate in an optimized manner under all conditions _ even when a disturbance or fault occurs, the network will be able to reconfigure and self-heal, so as to continue to supply the loads without interruption.
In summary, the objectives for introducing smart grids are to:
_ improve the efficiency of investments in power assets;
_ take advantage of the readiness of the latest technologies such as power electronics, communications, information storage and exchange and new materials;
_ integrate renewable energy generation sources such as wind, tidal and solar;
_ reduce emissions such as SF6 and CO2 loss and also reduce stray magnetic fields;
_ improve the quality and reliability of the power supply;
_ provide consumers access to affordable electricity;
_ ensure security of the power system operation and the overall safety of electricity delivery and
_ improve the efficiency of Transmission and Distribution (T&D) network operations.
FIG. 1 shows a vision for the development of Transmission and Distribution (T&D) networks _ moving from passively and centrally con trolled arrangements to actively and automated sub-network control under a modern smart grid arrangement.
2 THE CHALLENGES TO BE MET BY SMART GRIDS
2.1 Introduction
Network companies are reaching the limits of efficiency gains deliverable through existing assets and traditional control technologies. In addition, the electrical industry is moving from a hierarchical and top-down power flow management environment to one where bidirectional power flow is anticipated as a result of connection of distributed generators (DGs) at dispersed locations (DGs such as wind turbines). A smart grid is therefore intended to bring reliability, flexibility, efficiency and environmental responsibility to network operations.
FIG. 1 An illustration of a smart grid.
Electric vehicles' load (energy storage) Power stations' output Responsive and nonresponsive load Renewables' output Electricity market data Transmission and distribution monitoring
FIG. 2 Unidirectional and bidirectional power flow in a distribution
network. (a) Unidirectional power flow. (b) Bidirectional power flow.
FIG. 2 illustrates such unidirectional and bidirectional power flow in a distribution network.
The smart grid applies information, communications and control technologies for the monitoring and operation of generation, delivery and consumption intelligence. It provides the utility with near real-time data so as to manage the entire network as an integrated system. By actively sensing and responding to changes in power demand, supply, costs and emissions, greater efficiency, flexibility, reliability and environmental responsibility are intended to be brought to network operations. Goals of 10% reduction in consumer bills and 15% reduction in peak loads (thereby helping to offset new build costs) are being suggested as achievable. However, such goals will clearly require co-operation and co-ordination between governments, regulators, utility companies and technology providers, coupled with a radical change in approach to energy usage by customers and consumers.
2.2 Efficiency
There are two facets. One is the investment efficiency in power assets such as power networks and generation plants. The high electricity demand during the system peak-time requires a system operator to source sufficient generation plants to provide 'peaking capacity' so as to meet the demand. The number of peaking unit operating hours during the whole year is small. Therefore the utilization and investment efficiency of such peaking power plants are low. Similarly, the transmission and distribution infrastructures required to meet the peak demand also introduce investment inefficiencies as the systems are normally under-utilized during normal, lower demand, operational hours.
The other aspect of efficiency is the operational efficiency of the network itself. The total technical energy losses across transmission networks are relatively low. However, technical losses in the generation sector and across distribution networks are higher (due to technical limits on generation efficiency, maintenance regimes, and greater voltage drops at lower voltage levels). In particular, the efficient integration of distributed generators is unlikely with out changes to transmission and distribution network structure, planning, and operating procedures. In future, the challenge will be to introduce a wider participation in active demand (consumer) management and generation, trans mission and distribution control. It is anticipated that there will need to be less of a distinction between these power system types (generation, transmission, and distribution) in order to achieve higher overall efficient control.
Such integrated networks and participating consumer loads will all have an input to support the balance between demand, generation, and system frequency subject to the regulatory environment, commercial interconnection agreements, and supply transmission distribution demand incentives.
2.3 Flexibility
Additional modes of transmission and distribution network operation are intended to improve the opportunities for management to make better economic decisions.
Smart grid technologies can provide different means of demand side management and associated generation control with the goal of achieving flexibility and improved reliability as well as offering better environmental performance and increased economic targets.
2.4 Security and Reliability
Greater system security and reliability can be achieved through the use of real-time communications which enable the exchange of system control information between generation, transmission, distribution, and consumers in the network. This could reduce the need for human intervention in making decisions to protect the system. A particular example might be the reduction in system failure such as a blackout caused by sudden changes in system characteristics which manual intervention alone is too slow to control.
2.5 Low Carbon Emissions and Connection of Renewables
Broadly speaking, smart grids could help to reduce carbon emission in the electricity supply chain in two ways. One is to reduce greenhouse gases used in the networks. The other is to connect more power plants which generate electricity from renewable sources such as wind and solar.
Regulators place an obligatory duty on most network operators to minimize their negative impact on the environment (reducing their carbon foot print). This is a very broad topic within the Transmission and Distribution industry and covers such aspects as reducing call-outs (and associated vehicle fuel usage) to minimize the leakage of SF6 in gas-insulated switchgear.
Smart grid technologies are intended to provide a faster automated service for items such as automated meter reading (in contrast to a meter reader having to visit consumer premises), automated outage management (in contrast to technicians and engineers having to visit the sites etc.).
The location of large-scale renewable energy power generation is determined by the availability of the main source of energy. Large scale hydro resources and offshore wind farms are generally a long distance from load centers. Small wind farms with a total generation capacity (from many individual windmills) of up to, say, 60 MVA are normally connected at distribution voltage levels. Wind farms above this capacity are normally connected into transmission networks at 145 kV or equivalent voltage levels. In the case of large offshore wind or hydro schemes, they may be connected through HVDC and UHV links as described in Section 26. As such, Transmission and Distribution operators are anticipating the need to resolve network connection issues; especially, in remote and rural areas. In addition, embedded generation installed in a remote area at a weak point in the power network may result in voltage rise issues. In contrast, micro Combined Heat and Power (CHP) generation installed close to load centers could result in high voltage and increased fault currents. Further, a system with a generation mix of inflexible power plants such as nuclear and run of-river hydrostations may have difficulty to also integrate with or adopt intermittent wind power.
3 SMART GRID TECHNOLOGIES
3.1 Introduction
Advanced information, telecommunication and control technologies play a critical role in making a grid 'smart'. The smart grid technologies and their applications could also be considered in the three dimensions of:
_ functional characteristics such as integrated communication, protection and control infrastructure IEC61850;
_ device technologies such as meters and phasor measure units (PMU); and
_ application use cases such as customer engagement, demand response incentive and dynamic pricing.
3.2 Smart Metering
The smart meter or advanced metering infrastructure (AMI) is intended to provide a real-time communications link between the consumers and utilities so as to allow:
Time of Use (ToU) tariff schemes, whereby consumers are encouraged to shift their consumption from peak to off-peak (and lower price) periods.
However, this non-dynamic approach to demand side load control and the associated large-scale system integration of such actions may merely shift the peak load time to no overall advantage.
Real-Time Pricing (RTP) arrangements where hourly or half hourly price changes are built into the tariff structure to reflect changes in supply and demand. The structures are intended to provide incentives for consumers to limit consumption when the wholesale price of electricity is high and increase consumption during lower rate periods.
Critical Peak Pricing (CPP) is a more realistic alternative to full Real Time Pricing (RTP). The tariff arrangements are intended to augment a time-invariant or Time of Use (ToU) rate structure with a dispatchable high or 'critical' price during periods of system stress. Such a critical price could occur for a limited number of discretionary periods (days) during the year or when system or market demands meet a pre-defined condition.
Participating consumers would receive notification of the dispatchable high price (typically at least a day in advance for large customers) and in some cases would be provided with automated control technologies to support efficient load shedding. Such CPP arrangements are less efficient than full RTP schemes. However, they are considered to be more politically acceptable, as they reduce the potentially large sudden price risks for consumers associated with RTP.
Home Area Networking (HAN) allows multiple devices to work together to create home energy management systems. It is seen as a fundamental building block in AMI.
In addition, another advantage of smart meters is that they are able to report back to the utility control centre in near real-time non-technical losses (e.g. tampering with meters, bypassing meters and illicit tapping into distribution systems).
Major programs of smart meter installation are already underway in Europe. ENEL (Ente Nazionale per l'Energia eLettrica, Italy's largest utility) installed nearly 27 million smart meters in the five years from 2002 to 2007 with an investment of some 2.2 billion Euros. Similarly, EdF (Electricite de France) started an installation of 35 million smart meters in France in July 2008. Further, in the UK, some 47 million gas and electricity meters are being replaced in a d8.6bn program, assisted by Government Capital Grants, such that a smart meter will be installed in every home by 2020.
At the current stage in the development of smart metering the practical aspects of such projects are many and varied. Further information is available in the references at the end of this section.
3.3 Demand Response
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FIG. 3 Demand response (DR) system architecture.
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The Demand Response (DR) allows utilities to have control of loads so as to optimize the power flow across the network and better utilize their generation, transmission and distribution assets. It also allows consumers to make choices with regard to their energy consumption largely driven by responses to vari able tariffs. Demand Response would enable loads to be controlled in response to supply side (generation) availability and associated tariffs. However, such an approach also requires customers to change their normal consumption pat terns in response to the prices of electricity over time. There is hope for this.
For many years, there have been reduced tariffs for household night time energy usage and large power consumers are well aware of the penalties, under existing tariff arrangements, for exceeding pre-set maximum demand.
The essential change brought about by the smart grid is the speed of response.
The benefits of Demand Response include:
_ Improving investment efficiency in power generation, transmission and distribution assets;
_ Reducing price volatility/flattening spot prices;
_ Improving system security and reducing the risk of black-outs;
_ Reducing network congestion;
_ Reducing greenhouse gas emissions; and
_ Improving market efficiency by enhancing consumers' ability to respond to changing prices.
FIG. 3 illustrates the architecture of a Demand Response system where demand response modules are installed on consumer appliances and information exchanges take place through fiber optics, wireless or power line carrier (PLC). It is noted that very serious high frequency (2_30 MHz) interference (EMI compatibility issues) is yet to be resolved using the PLC technology. In addition, deliberate interference (nuisance hacking or even strategic targeted attack) is a risk on radio or internet based communication.
Studies indicate that there is a serious potential in North America for demand to outstrip generating supply. It is considered that a Demand Response of about 5% to 15% of peak demand should result in an efficient balance between building new supply resources and reducing demand. Some of the programs introduced include:
_ Capacity Bidding Program (CBP) -- flexible bidding program where participants are paid monthly incentive payments to reduce the load to a predetermined amount during CBP events with day-of and day-ahead notification.
_ Demand Bidding Program (DBP) -- which is a voluntary internet based bidding program that offers bill credits with no penalties for reducing power consumption when a DBP event is called with day-of and day-ahead notification.
_ Real-Time Pricing (RTP) -- in which participants are billed for the electricity that they consume based upon hourly prices driven by temperature.
Participants may choose to make adjustments in their HVAC electricity usage based upon hourly prices within different temperature ranges.
_ Agricultural and Pumping Interruptible (API) -- which is an interruptible rate that offers monthly credit to customers who allow the utility (Southern California Edison) to temporarily interrupt electrical services from their pumping equipment.
_ Time-of-Use Base Interruptible Program (TOU-BIP) -- which is a program for customers who can reduce their consumption by a predetermined amount (also called the Firm Service Level) within 15 or 30 min of notification. In return customers receive monthly capacity credits.
_ Emergency Demand Response Program (EDRP) and Special Case Resources (SCR) Program _ designed to reduce power usage through voluntary shutting down of large businesses and power consumers who are paid for such reductions when asked to do so.
Similar schemes have been introduced in Europe, typically as indicated below:
_ In France by ERDF (a subsidiary of EdF). The Tempo pricing scheme is an optional tariff for domestic customers with over 9 kW peak demand.
Customers receive color codings associated with different tariff rates for day and night usage one day in advance so that they may change their consumption accordingly.
_ In Italy, by ENEL an RTP scheme is available to customers with peak capacity over 12 kW.
_ In the United Kingdom, demand response is provided by National Grid (Transmission) under contracts with service providers (Generators and Distribution Companies) for frequency regulation and Short-Term Operating Reserve (STOR). Short-Term Operating Reserve is a replacement for Standing Reserve through the provision of standby generation and/or demand reduction. Participants are paid an availability payment (d/MW/h) and utilization payment (d/MWh). However, demand response is not yet fully available to domestic customers.
It is important to recognize that the cost of installing a smart metering sys tem depends greatly upon the commercial environment as well as the technical nature of the networks involved. For example, a mandatory system-wide approach operated in Sweden by the distributor has been found to be 56% cheaper on a cost per meter basis than a discretionary system operated by the energy supplier in Germany. On the other hand, in the UK, studies have indicated that there is no business case for a 100% roll-out of smart meters and a figure of 30% of households represents an economic installation level(but this hurdle may be overcome by government grants).
3.4 Active Thermal Rating Monitoring
Active network monitoring, especially at transmission voltage levels, is already available. However, at present applications at distribution voltage levels are currently not so commonly used. Active Thermal Rating Monitoring (ATRM) is a solution that involves the installation of sensors to measure and communicate the loading level of branches in power networks. Manufacturers claim that ATRM could increase distribution line loadings of 5-15% through such closer monitoring and control. However, such systems require massive investment to install monitoring and control devices and use the dynamic data collected in the network operations. As such ATRM systems are not yet widely integrated into distribution power systems operations. Similarly, at the distribution level, the monitoring of received power quality (e.g. network voltage levels) gives the opportunity for improved customer service and better reinforcement planning information.
3.5 Outage Management and Self-Healing
The security of power system operations and quality of supply can be assessed through various criteria such as number of interruptions, duration of an outage and volume of energy not supplied due to an outage. More detailed description and discussion are presented in Section 23.
Transmission networks already have extensive fault monitoring and control arrangements so as to help maintain uninterrupted power transfer. However, this investment is less common at distribution network voltage levels (below 36 kV), where up to 35 MVA may be supplied from a single 33 kV feeder and up to 2,500 or 200 consumers may be supplied from a single feeder at 11 kV or 400 V respectively.
Smart sensors with Geographic Information System (GIS) capability are available which can immediately detect and transmit the nature and location of a distribution feeder problem to a central control. More fundamentally, the loss of contact with a group of routers of itself gives an immediate indication of a network problem in a defined area and represents a considerable advance on consumer notification, which is the fall-back information system for outages in many distribution systems. Outage management and self-healing are able to reroute and restore the supply after disturbances or when the fault has been cleared.
The electric and natural gas company, PECO, has commenced installing such an automated outage management integration system and also installing smart meter technology to more than 1.6 million customers in Pennsylvania, USA. The targets from this investment are set by the company as:
1. US$ 400,000 annual Operations and Maintenance (O&M) cost savings (through avoided costs associated with reduced overtime and outside maintenance contractor requirements through better outage event management).
2. Reduction in Customer Average Interruption Duration Index, CAIDI by 2_4 min (through improved event analysis, including nested outage recognition).
3.6 Active Fault Level Management
Equipment fault level ratings are traditionally based on the maximum fault level that can be withstood by the equipment under worst case network con figurations. In many instances such high fault levels represent seldom encountered situations (e.g. when all feeders on a switchboard are connected and bus section circuit breakers are closed). Active fault level management monitors the connected generation and switching configurations in real time to assess the system fault levels at points in the network. The active fault level management control system may then alter the network configuration if fault levels approach maximum (e.g. by opening busbar interconnections and increasing the equivalent fault impedance to the equipment under threat).
3.7 Active Synchophasor Monitoring (Phasor Measurement Unit)
Monitoring of the steady state condition of the grid is normally based upon nonsimultaneous average measurement values taken over periods of many seconds. The installation of more immediate, real time monitoring of line voltage or current phase angles (phasors) can assist with rapidly understanding the changing and transient phenomena associated with emerging instability or system collapse.
A phasor measurement unit (PMU) can measure the electrical waves on a power system to determine the grid health condition. A PMU can be a dedicated device or its function could be built in a protection system. The measurement consists of both magnitude and phase angle of the sine waves in electricity. PMUs can be installed in dispersed locations in the power system and synchronized from the common time source of a global positioning sys tem (GPS) radio clock. The measurement can be sent to a control centre to help the network operators to understand the system status in real-time.
Furthermore, the data could also be used in equipment dynamic rating to improve network transfer capability and economics.
4 POWER EQUIPMENT SOLUTIONS
4.1 FACTS Devices
Flexible Alternating Current Transmission System (FACTS) devices may be used to maximize the capacity of new and existing Transmission and Distribution networks. The advantages from FACTS device installation include:
_ steady-state and dynamic reactive power compensation and voltage regulation;
_ steady-state and dynamic stability enhancement;
_ increasing power transfer capability of existing assets;
_ reduced fault current;
_ reduced transmission losses;
_ improving power quality.
FACTS devices are not new, but huge advances have been made over the last 20 years in the associated power semiconductor technologies. Some examples of FACTS power devices to meet these demands are described in Sections 24-26. The challenge is to lower the costs of such equipment and to cost effectively widen their application to distribution voltage levels.
4.2 Fault Current Limiter
Unlike the use of reactors or high impedance transformers, FCL devices are intended to limit fault currents without adding impedance into the circuit under normal operation. The alternative traditional fault limiter (the "Is Limiter") is not considered fail safe and requires servicing after each operation. Superconducting Fault Current Limiters (SCFCLs), which use high temperature superconductors, increase the source impedance and limit fault currents only during fault current conditions. Such devices are currently undergoing trail tests (e.g. ABB 8 kV, 6.4 MVA units) and offer a potential solution for controlling fault-current levels on utility distribution networks.
4.3 Voltage Control and VAr Support Devices
AC voltage support equipment such as the Thyristor Controlled Reactor (TCR) and the Thyristor Switched Capacitor (TSC) have a proven reliability track record in the supply of reactive power with fast response time and low maintenance.
FIG. 4 SVC and STATCOM layouts.
A rapidly responding Static VAr Compensator (SVC) can continuously provide the reactive power necessary to control dynamic voltage swings and thereby improve the transmission and distribution performance. Installing an SVC at one or more locations in the network will increase power transfer capability through enhanced voltage stability while maintaining a smooth voltage profile under different system conditions (see Section 28, Section 28.8.5).
The total reactive power that a static VAr compensator produces will depend upon the voltage level at the SVC's terminals. Hence, the rating of an SVC is the maximum reactive power that it can provide at nominal voltage.
In contrast the Static Synchronous Compensator (STATCOM) is not affected by the magnitude of the voltage at the STATCOM's terminals. It operates according to voltage source principles which when combined with the Pulse Width Modulation (PWM) power switching characteristics of modern Insulated Gate Bipolar Transistors (IGBTs), offer unequalled performance in terms of rating and speed of response. FIG. 4 shows layouts of SVC and STATCOM.
SVCs and STATCOMs are expensive capital plant items and at present their application is limited to reactive power management on transmission networks. Several new technologies such as the Distribution Static VAr Compensator (D-SVC) and the Distribution Static Synchronous Compensator (D-STATCOM) which can connect directly to distribution networks without the need for step up transformers are under investigation.
4.4 Unified Power Flow Controller
In some circumstances it may be possible to increase the grid's capacity through better control of the active and reactive power flow in the transmission network independently of busbar voltage. The Unified Power Flow Controller (UPFC) provides reactive shunt compensation, active and reactive series compensation and phase shifting. It is therefore capable of regulating the magnitude and phase angle of sending and receiving end voltages, thus controlling power flow in the transmission line and selectively changing trans mission line impedance. American Electric Power (AEP), working in conjunction with Westinghouse Electric Corporation and the Electric Power Research Institute (EPRI), has recently installed two 6160 MVA voltage sourced GTO thyristor based inverters to achieve this and, at the same time, help to avoid the need for existing transmission line reinforcement (FIG. 5).
FIG. 5 UPFC layout.
5 ENERGY STORAGE
The large scale introduction of electric vehicles could mean that in the future there will be substantial energy storage capacity in the vehicle batteries at the distribution level. The electricity demand on the distribution network will increase while vehicle battery charging takes place. However, intelligent control of electric vehicle (EV) battery charging and discharging should be able to use EVs as energy storage to achieve:
_ Peak load shaving.
_ Black start islanding.
_ Better ancillary services provision (including load following, operational reserve, frequency regulation, and 15 minute fast response times).
_ Renewables integration (ramp rate control, solar cloud ride through etc.).
_ Better management of daily cycles (compensating for shifts in large energy capacity wind and solar peak generation availability); and
_ Relief of network congestion and constraints (short duration power application and stability and long duration energy application and to relieve thermal loading).
Utilization of such energy storage is currently on a trial basis.
Examples include:
_ The trial installation at a Scottish and Southern Energy Distribution company substation in UK of flow batteries. The flow battery (where the active materials in a two electrolyte system are external to the battery and where these reactants are circulated, by demand, through the flow stack as required -- see FIG. 6) is capable of supplying 150 kWh with a maxi mum output of 100 kW. This installation is being assessed for supply to local emergency loads under loss of AC power conditions.
_ Installation of some 2 MW battery storage at Donegal in Ireland to compensate for wind power output deficit from the 6 MW Sorne wind farm.
The batteries are designed to have a high (80%) efficiency level and 20 years estimated life. (Obviously this puts into perspective the problems of harnessing intermittent renewable energy resources).
_ Connection points for electric vehicles are being provided at some car parks across the City of London in UK. However, the current charging stations are not yet capable of utilizing the car battery energy storage through bidirectional power transfer.
Other forms of energy storage are flywheel and compressed air. For instance, installation of 20 MW flywheel energy storage facilities are undergoing trials in the transmission network of New York State to provide peaking generation capacity.
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FIG. 6 Flow battery arrangement.
Generator Pump; Pump DC/AC Load Negative electrolyte tank Positive electrolyte tank; V3+ V4+ V3+ V2+