By Frederick C. Huff, Emerson
Editor’s Note: The following article is based on a technical paper recently presented at POWER-GEN International 2017 in Orlando, Florida.
A microgrid can be defined as a group of interconnected loads and distributed energy resources within clearly defined electrical boundaries that act as a single controllable entity with respect to the grid and that automatically connects and disconnects from the grid to enable it to operate in both grid connected or “islanded” mode.
Power electronics for each micro-source can provide the control and flexibility for the microgrid to meet its power demands. The Microgrid controls need to ensure that:
- New micro-sources (Solar PV, Fuel Cells, Micro-turbines etc.) can be added to the system without modification of existing equipment.
- The Microgrid can connect to or isolate itself from the grid in a rapid seamless fashion
- Active and Reactive power can be independently controlled
- Voltage sag and system imbalances can be corrected
- Satisfy the Microgrid load dynamics
Each Micro-source has its own controller that interfaces to the micro-source power electronics. Even though the micro-source controllers are designed so communication to each other device is not required having a Distributed Control System (DCS) that monitors all the micro-source controllers and the loads of the entire Microgrid aids operations and provides more robust control. A DCS provides operations with the ability to view the status of the entire Microgrid in a common location. In addition, central logic can quickly detect separation of main distribution grid to switch modes of devices to help ensure frequency is maintained. It can also be a platform for intelligent load shedding to replace standard under-frequency load shed systems and can provide a common interface to an Energy Management System.
“The growth of renewable energy resource installations, emerging utility scale energy storage and demand response is bringing unprecedented opportunities and challenges to the electric distribution system.”  Utility systems are now facing a systems-integration challenge with complex coordination and integration necessary for these distributed resources.
“When distributed energy is integrated into distribution networks at customer sites, issues arise with respect to reverse power flows — from customer (load) to grid. The traditional system is designed for power flow from grid to customer, not the two-way flow of power. Since reverse power flow is not controlled by the distribution utility (let alone the transmission operator), at high penetration levels of Distributed Energy Resources (DER) this becomes a major problem which is further compounded by the intermittency of renewable energy sources due to weather variability, e.g. wind not blowing; sun not shining; clouds.” 
Microgrids offer a solution for utilities and customers to cope with these issues. They control generation and loads at the local level and can disconnect or island from the grid in times of disruption, either from inadequate supply during normal times or outages because of natural disasters. During normal operations, e.g. no shortages of generation due to outages, microgrids offer the additional benefit of optimizing supply and demand via comparative pricing vs the distribution utility, e.g. buying from the utility when market prices are lower than microgrid costs and selling to the market when costs in the microgrid are lower than market prices.
Microgrids provide a solution to customers who experience problems with reliability and outages. They become standby option to maintain power in emergencies. It is also the reason that back-up generation, mostly diesel generators at locations to serve critical load, are now being called “Microgrids”.
In summary, a microgrid can be defined as a group of interconnected loads and distributed energy resources within clearly defined electrical boundaries that act as a single controllable entity with respect to the grid and that automatically connects and disconnects from the grid to enable it to operate in both grid connected or “islanded” mode. A microgrid is capable of operating autonomously from the electrical grid by supplying all its generation.
The microgrid is a grouping of distributed energy resources and interconnected loads. Figure 1 below shows a generic configuration and principal components that most advanced microgrids would typically incorporate.
There is generation that can be dispatched such as diesel generators or microturbines and there is intermittent generation that cannot be controlled such as wind and solar. The microgrid also contains energy storage. This can be batteries or flywheels. It can also be in the form of Hydrogen gas. Often excess solar or wind power can be used to make Hydrogen that can be burnt later in a microturbine or used in automobiles. A microgrid can have critical loads that should always have power such as life support facilities or data centers. There are normally noncritical loads such as heating, air conditioning and lighting.
Normally there is a Point of Common Coupling (PCC) to the main distribution grid unless the microgrid is an island where there is no connection to the main distribution grid.
Key issues that are part of the microgrid structure include the interface, control and protection requirements for each micro-source as well as microgrid frequency control, voltage control, load shedding during islanding, protection, stability and overall operation. The ability of the microgrid to operate connected to the grid as well as smooth transition to and from the island mode is another important function.
The basic operation of most microgrid’s today depend on each micro-source controller to:
- Regulate power flow on a feeder as loads on that feeder change their operating points
- Regulate the voltage at the interface of each micro-source as loads on the system change
- Insure that each micro-source rapidly picks up its share of the load when the system islands
Another important feature of each micro-source controller is that it responds in milliseconds and uses locally measured voltages and currents to control the micro-source during all system or grid events. The systems are designed so that communication among micro-sources is not necessary. This arrangement enables micro-sources to “plug and play”. Micro-sources can be added to the microgrid without changes to the control and protection of units that are already part of the system. The basic inputs to the micro-source controller are steady-state set points for power, P, and local bus voltage, V.
The microgrid may contain an Energy Manager that enhances system operation of the microgrid through dispatch of power and voltage set points to each micro-source controller. This function could be as simple as having a technician enter these set points by hand at each controller or to a state-of-the-art communication system with artificial intelligence. The actual values of dispatch of P and V depends on the operational needs of the microgrid. Some possible criteria are:
- Insure that the necessary heat and electrical loads are met by the micro-sources.
- Insure that the microgrid satisfies operational contracts with the bulk power provider.
- Minimize emissions and/or system losses.
- Maximize the operational efficiency of the micro-sources.
The protection coordinator must respond to both system and microgrid faults. For a fault on the grid, the desired response may be to isolate the critical load portion of the microgrid from the grid as rapidly as is necessary to protect these loads. This provides the same function as an uninterruptible power supply at a potentially lower incremental cost. The speed at which the microgrid isolates from the grid will depend on the specific customer loads on the microgrid. In some cases, sag compensation can be used to protect critical loads without separation from the distribution system. If a fault occurs within the island portion of the microgrid, the desired protection is to isolate the smallest possible section of the radial feeder to eliminate the fault.
DCS Enhances Microgrid Control
Even though the micro-source controllers are designed so communication to each other device is not required having a DCS that monitors all the micro-source controllers and the loads of the entire microgrid aids operations and provides more robust control. A DCS provides operations with the ability to view the status of the entire microgrid in a common location. In addition, central logic can quickly detect separation of main distribution grid to switch modes of devices to help ensure frequency is maintained. It can also be a platform for intelligent load shedding to replace standard under-frequency load shed systems and can provide a common interface to an Energy Management System. Figure 2 is an overview of the microgrid at Stone Edge Farms.
The Hydrogen Electrolyzer uses excess solar power to make hydrogen for use in fuel cell and Toyota Mirai. The hydrogen is a form of energy storage. Each of the nodes has its own microsource controller and work independently. The farm has a connection to the main distribution grid but if it were to become an island each micro-source controller would respond to help maintain frequency. In this situation one of the battery inverters is put in master mode. In this mode, the battery inverter is given a frequency setpoint and will automatically charge/discharge the battery in response to changes in frequency. The other battery inverters remain in P,Q mode. This is very similar to placing a generator in Isochronous mode and leaving the remaining generators in droop mode. The DCS is currently being used to provide remote monitoring and supervisory control. It sends setpoints to the micro-source controllers. The DCS will also be used to check for disturbances such as loss of the master battery inverter and automatically send a command to another micro-source controller to switch the inverter from P,Q to Master mode. This may also have to be done if the charge remaining on the battery becomes low. The DCS also helps in re-connecting to the main distribution grid. Currently the grid breaker is manually closed when the synch-check indication shows the microgrid in phase with main grid. This condition often is only true for very short time making it difficult to manually close the breaker. However, this procedure can be automated in a high speed (50msec) control task of the DCS eliminating this timing problem.
Figure 3 shows an overview of the communication network for a DCS when used in an off-grid microgrid such as an island community. The electrical demand of the island must be satisfied from a variety of power producers. This microgrid contains energy manager software that resides in a separate server that receives all required data from the DCS and writes all its calculation results back to the DCS. The DCS is responsible for interfacing to all the actual power producers. The DCS also provides central monitoring and control. It should be noted that the energy manager could be part of the DCS instead of a separate machine as shown.
Energy Manager Functions
The primary Energy Manager functions are described here.
Load Forecasting — This function provides the capabilities to forecast system load, as well as generation from solar assets. To forecast system load, this function utilizes historical load and weather data and will provide profiles for similar day types. Profiles are maintained for various day-of-week types, seasons, and weather variables. To forecast system load based on forecasted weather, appropriate profiles are selected and adjusted to fit the current system load and weather condition. To forecast solar generation, forecasted solar irradiance and temperature are retrieved from on-line weather services. This, coupled with the physical characteristics of the solar plants such as inclination angles, capability limits, efficiencies, as well as telemetered local conditions are used to generate the solar generation forecast.
Scheduling and Dispatching — This module determines the optimum commitment schedules and Economic Dispatch schedules for the conventional generation facilities, as well as for the battery storage facilities. The primary input to the optimization process is the net load forecast, defined as the difference between the system load forecast and solar generation forecast. This function takes the capabilities of generation units such as maximum and minimum capacities, incremental cost of generation, ramping capabilities, etc., into consideration. It also takes constraints, such as minimum up/down times, outage schedules and other pertinent parameters into consideration.
DCS Data Acquisition Functions
As shown in Figure 3, the DCS is responsible for interfacing directly to all the energy producers. It provides all the required data acquisition functionality. It gathers all the power being consumed in the electrical substations and the power being produced. It also can read the weather and solar irradiance forecasts from a website. This data is then sent to the energy manager over a secure communication link and the results from the energy manager are received over the same link. All the information is made available to operations in a central location on graphic displays. The data acquisition system will automatically gather the status and values from the feeders, and collect them at one central location. This data can be displayed on a monitor (the HMI or human-machine interface).
The DCS contains project-specific graphics like single-line diagrams (SLDs) on which live status of the breakers can be displayed. The operator continuously sees the live status indicating if a breaker is open, closed, bad, tripped, etc. Critical analog values like bus voltages, frequency, power, etc are also displayed. From these DCS graphics the operator can remotely operate breakers and perform tagout operations.
Since data is being continuously acquired by the DCS, it can be stored for later retrieval (the historian) for future analysis. The historian is limited only by its disk space as to how long it can retain data. Disk space may also be augmented by tape drives or DVD writers.
By checking the data, alarms can be reported on the operator workstations or printed out. Alarms may be generated if an analog value goes above or below some limits, e.g. if the bus voltage or frequency falls below an acceptable limit. Alarms may be generated on a change of state of a digital value, e.g., if the grid or generator breaker opens.
With the data, available, the software can automatically generate reports on an hourly, shift, daily, monthly or yearly basis.
Basic DCS Control Functions
Listed below are other control functions that can be implemented in the DCS to enhance the microgrid controls.
Point of Common Coupling Control
A microgrid may have a Point of Common Coupling connection to the distribution utility (the macro-grid) and a rate structure/contract that stipulates the maximum quantity of energy (MWh) that can be consumed in a demand period. If this limit is exceeded, the microgrid manager must pay a penalty or demand charge, and often this ratchets the demand charge up permanently.
Because this consumption demand is measured in energy (MWh) and not power (MW), the control logic can be used to predict the energy consumption at the end of the time. An anticipated error can be estimated by measuring the present rate of power consumption and extrapolating to the end of the demand period. If this predicted value exceeds the maximum demand limit, the control logic can automatically trim load or increase generation from energy storage to limit the energy consumed from the macro-grid, or, an alarm can be generated for the operator to take corrective action.
The way frequency is controlled depends on the types of power producers the microgrid contains. When the microgrid is connected to the main distribution grid the frequency is maintained by the grid. The problems occur when the microgrid is disconnected from the grid.
If the microgrid contains gas and steam turbines the simplest way to maintain frequency is to place the largest gas turbine into isochronous mode and keep the remaining generators in droop. Whenever there is a load change the isochronous machine will move very quickly to keep its speed at 3600 rpm for a 60Hz system. The loads on the machines in droop can be adjusted by centralized logic in the DCS to ensure the isochronous machine always has spare capacity to respond to a load change.
According to  there are two ways of performing frequency control of the microgrid. It can be done locally using a PI controller at each micro-source controller or in a centralized way. Per  inverters are typically controlled to emulate the droop characteristics of synchronous generators. The two primary objectives of this control are to hold the frequency at the desired value when running as an island and to load the power producers in the most economical manner.
In the case of the microgrid at Stone Edge Farms where there are no generators one of the battery inverters is put into master mode and the others remain in P,Q mode. In this master/slave configuration the master inverter is given a frequency set point and it automatically adjusts the charging and discharging of the battery to maintain the desired frequency. The other battery inverters in P,Q mode match the frequency of the master. However, the P,Q inverters can be adjusted by centralized logic in the DCS to make sure the master has spare capacity. This frequency control configuration is analogous to having one generator in isochronous mode and the remaining ones in droop.
Figure 4 shows a high-level overview of frequency logic that could be applied to the microgrid shown in Figure 3 above where all generators are in droop and inverters are in P,Q mode. The amount of power that must be produced is the current generation plus any correction due to frequency deviation from the set point value of 60Hz. This total required MW amount is then distributed to the power producers. The way the power is distributed is determined from the economic dispatch function from the energy manager. The energy manager software is running say once per minute while the logic in the DCS is running every one second or faster. The advantage of having this base frequency control in the DCS is that while the energy manager is not running the DCS is constantly ensuring the frequency is maintained. The logic in the DCS can automatically detect if a power producer tripped and automatically re-allocate its power to the remaining power producers. Similarly, it instantly detects if an operator has placed a device in manual mode and constrains the power that device is making and re-distributes the remaining load. The same holds true if a power producer reaches a high or low limit. In between runs of the energy manager software the frequency control in the DCS loads the available power producers based on the desired values from the last run of the energy manager to ensure the power is being produced in the most economical way.
Breaker Control and Interfacing to IEDs
Remote breaker control logic allows an operator to issue OPEN and CLOSE commands from the single line diagram graphics displayed on an operator workstation. Before a command is executed, the control logic checks to ensure that the breaker is in the proper state for the operation. This means to check for proper status (e.g. breaker open), open faceplate, activate faceplate, arm, and allow only the corresponding command (breaker close command). If a command is issued and the status indicator does not reflect the new state (the breaker does not indicate that the operation was successful) within a certain amount of time, an alarm is generated.
The DCS can typically communicate with intelligent electronic devices (IEDs) using various protocols such as:
- Modbus over RS485 serial link
- Modbus over TCP/IP
- IEC 61850
- IEC 60870-5-104
Load shedding is critical in controlling a microgrid. Contingency analysis and load shedding software automatically responds to electrical disturbances such as loss of grid or loss of power producer so that stable conditions can be restored.
If a power source (grid, generator, or an inter-connect breaker on a generation bus) is lost, then the power that was originally available from that power source must be shed in a fraction of a second so that the remaining power producers are not over-loaded, and so that the disturbance to the process is minimized. A large chunk of downstream feeders may have to be shed immediately to prevent a blackout.
Often there is only an under-frequency relay system. This is the simplest method of carrying out load shedding. For this scheme, the circuit breaker interdependencies are arranged to operate based on hardwired trip signals from an intertie circuit breaker or a generator trip. Even though, the execution of this scheme is fast, breaker interlock load shedding possesses several inherent drawbacks:
- Load shedding based on worst-case scenario
- Only one stage of load shedding
- Almost always, more load is shed than required
- Modifications to the system are costly
A priority based load shed system can be implemented in the DCS that only sheds the amount of load required. The load shed logic selects the feeders to be shed from a list of available feeders, and selects the feeders in order from the least important feeder to the more important ones. The logic also checks that the load-shed breaker is available for automatic tripping (e.g. closed and has a MW flow) and desirable (i.e. connected to the importing bus and not to the exporting bus). This list of breakers for each possible load-shed case is continuously updated and made available at the controllers.
The moment a power source is lost, the selected breakers are shed automatically by the system. Graphic displays are provided to the operator so he can see which loads will shed if a contingency were to occur so he can prevent a critical load to plant operation from tripping. At any time, he can adjust the priority or temporarily remove it from the load shed system and then restore it later. The columns of the matrix are the contingency cases and the rows are the breakers. If a cell is highlighted with a MW amount for the breaker this indicates that load will shed if the contingency should occur.
Loads are shed on detecting opening of a power-source breaker.
When the microgrid is disconnected from the grid it is then its own electrical island. The frequency of the island must be maintained from its own power producers. If the microgrid load exceeds its generation, then the frequency of the island will fall below the nominal value of 50 Hz (60 Hz in the USA). If the frequency goes below a minimum threshold value, the system will shed enough low-priority loads to bring the frequency back to the nominal value.
At any time, operations, can change the load shed priority scheme. There may be times when a load is critical and should not be shed and at other times it can be. A graphic display provides the user with the ability to change a breaker priority or to temporarily remove it from the load shed system and restore it later.
When microgrid loads are turned on and off there is a varying active (MW) power demand. If some of the loads are large inductive loads (i.e. motors) this will also cause a varying reactive (MVAr) power demand that can cause fluctuations in bus voltages. Each micro-source controller can respond to changes in voltage but centralized voltage control in the DCS can enhance this control by satisfying the reactive demand within the constraints of:
- Keeping the power factor of tie-line power close to unity or at the operator-entered power-factor set-point. This eliminates power-factor penalties. If the microgrid is running as an island, then all the reactive power must be generated internally.
- Ensuring that generators always run within their reactive capability.
- Keeping bus voltages within allowable limits.
- Keep all generators and inverters on same bus with equal power factors
Reactive power can be controlled by:
- Turning capacitor banks on and off.
- Adjusting the excitation on generators and synchronous motors.
- Adjusting tap positions on transformers.
- Adjusting the VAR’s on inverters that may be for solar, wind or batteries
Capacitor Bank Control
Switching capacitor banks ON when reactive power demand is high helps satisfy the reactive demand and gives more MW capacity to the generators. This can lead to a monetary savings. When it is cheaper to generate power rather than buy power, it is desirable to have more in-plant generation capacity. If the generator can run at a higher power factor it can make more MW for the same amount of fuel and reduce the amount of purchased power.
Thus, switching on a capacitor bank reduces the MVAr load demand on that bus, and therefore reduces the MVAr imported from the grid which in turn may reduce the MVAr from the generators.
Capacitor banks help reduce losses in the electrical network by satisfying the reactive demand locally.
Generator MVAr Control
If the microgrid contains generators the amount of reactive power produced by a generator can be controlled by adjusting the Automatic Voltage Regulator (AVR) set-point on the machine. The generators AVR are programmed with a voltage setpoint equal to the nominal voltage of the bus that they are connected. When there is a change in reactive demand the AVR will automatically respond with enough reactive power to maintain the bus voltage. When this occurs often time’s one generator will end up with a low power factor and others with a very high-power factor. The centralized voltage control logic will redistribute the VAr’s so all machines have equal power factors.
This logic also ensures that each generator stay within its reactive capability.
Since changing generator MVAr will automatically change the voltage of the bus downstream of the generator, control logic will also ensure that the operator cannot move the bus voltage outside its allowable operating range. If the bus voltage goes outside this range while in MVAr Auto mode, the control logic will automatically adjust the generator’s MVAr to bring the bus voltage within limits.
If the microgrid does not contain generators the Var’s on the inverter can be adjusted to hold voltage. If the microgrid is running as an island the master inverter is given a voltage setpoint. The DCS can send Var setpoints to the slave inverters in P,Q mode to redistribute the VArs in such a way so that all inverters have the same power factor.
Transformer OLTC control
If the microgrid transformers have on-load tap-changing (OLTC) control, then the DCS control logic can calculate the desired tap position of the transformer so that the voltage of the bus immediately downstream of the transformer is kept within limits, normally within ±5% of the nominal value.
The OLTC control logic can be placed in OLTC Auto or Manual mode from the operator workstations. When in OLTC Auto mode, the optimum tap positions calculated by the control logic are used so that the transformers’ downstream buses are within their voltage limits. When in Manual mode, operator-entered tap positions are used. The operator may also manually raise or lower the taps by clicking on buttons.
OLTC control may be implemented as an Auto-mode control (recommended tap position is calculated automatically), or as Manual-mode raise/lower control, or simply as a tap-position advice to the operator (no automatic control) as desired by the customer.
A DCS is well suited to be a microgrid central controller. It can monitor all the micro-source controllers and the loads of the entire microgrid that allows operations to view the entire microgrid from a common location.
In addition, central logic can quickly detect separation of main distribution grid to switch modes of devices to help ensure frequency is maintained. It can also be a platform for intelligent load shedding to replace standard under-frequency load shed systems and can provide a common interface to an Energy Management System. It can also be used to provide secondary load frequency and voltage control.