3.4 DER Capabilities and DER System Architectures

3.4.2 Hierarchical Architecture of Distributed Energy Resources (DER)

Direct control by distribution system operators (DSOs) is not feasible for the thousands if not millions of DER systems “in the field”, so a hierarchical approach is necessary for utilities to exchange information with these widely dispersed DER systems. At the local level, DER systems must manage their own generation and storage activities autonomously, based on local conditions, pre-established settings, and DER owner preferences. However, DER systems are active participants in grid operations and must be coordinated with other DER systems and distribution grid devices. In addition, the DSOs must interact with transmission system operators (TSOs) (also known as regional transmission organizations (RTOs) and/or independent system operators (ISOs)) for reliability and market purposes. In some regions, retail energy providers (REPs), aggregators, or other energy service providers are responsible for managing groups of DER systems either through operational actions or market actions.

DER systems can range in size from 1 kW to more than 10 MW. The impact of aggregated smaller DER systems can be the same as a single larger DER system, so making size distinctions for requirements is becoming less common in standards and regulations. Utilities usually try to identify the net energy or net impacts of DER systems at the Point of Common Coupling (PCC) where a customer’s facility interconnects with utility grid.

As shown in Figure 10, DER systems typically are implemented as a hierarchical architecture .

Figure 10 : Hierarchical architecture of DER systems

1. Level 1: Individual DER Systems (green in the Figure) is the lowest level and includes the actual cyber-physical (cyber-physical means that it is a system that employs software control applications to manage power system hardware. This can have cyber security impacts) DER systems themselves. These DER systems will be interconnected to the utility grid through Electrical Connection Points (ECPs) and will usually be operated autonomously. In other words, these DER systems will be running based on local conditions, such as photovoltaic systems operating when the sun is shining, wind turbines operating when the wind is blowing, electric vehicles charging when plugged in by the owner, and diesel generators operating when started up by the customer. This autonomous operation can be modified by DER owner preferences, pre-set parameter, and commands issued by utilities and aggregators.
2. Level 2: Facilities DER Management (FDEMS) (blue in the Figure) is the next higher level in which a customer DER management system (FDEMS) manages the operation of the Level 1 DER systems. This FDEMS may be managing one or two DER systems in a residential home, but more likely will be managing multiple DER systems in commercial and industrial sites, such as university campuses and shopping malls. Utilities may also use a FDEMS to handle DER systems located at utility sites such as substations or power plant sites. A special type of FDEMS is the microgrid which is a group of DER systems that normally operates connected to a traditional centralized grid, but can be islanded if desired or in response to grid emergencies.

3. Level 3: Utility and REP DER Information and Communications Technologies (ICT) (red in the Figure) extends beyond the local site to provide the wide-area communications networks that support monitoring and control by utilities and retail energy providers (REPs). These communications networks provide the means to request or even command DER systems (typically through a FDEMS) to take specific actions, such as turning on or off, setting or limiting output, providing ancillary services (e.g. volt-var control), and other grid management functions. REP requests would likely be price-based focused on greater power system efficiency, while utility commands would also include safety and reliability purposes. The combination of this Level 3 and Level 2 may have varying scenarios , while still fundamentally providing the same services.
4. Level 4: Distribution Operational Analysis (yellow in the Figure) applies to utility applications that are needed to determine what requests or commands should be issued to which DER systems. Utilities must monitor the power system and assess if efficiency or reliability of the power system can be improved by having DER systems modify their operation. This utility assessment involves many utility control center systems, including Geographical Information Systems, Distribution Automation Systems, Outage Management Systems, Demand Response systems, as well as DER database and management systems. Once the utility has determined that modified requests or commands should be issued, it will send these out as per Level 3.
5. Level 5: Transmission and Market Operations (purple in the Figure) is the highest level, and involves the larger utility environment where regional transmission operators (RTOs) or independent system operators (ISOs) may need information about DER capabilities or operations and/or may provide efficiency or reliability requests to the utility that is managing the DER systems within its domain. This may also involve the bulk power market systems, as well as retail energy providers (REPs).

The management of DER systems involves multiple levels of information exchanges (see circled numbers in Figure 3):

• Interaction 12 - Autonomous DER behaviour in which the controller responds to sensors that sense local conditions within Level 1. Controllers are focused on direct and rapid monitoring and control of the DER hardware. Common types of autonomous DER controls include managing one or more inverters, such as a small PV system, a battery storage system, or an electric vehicle service element (EVSE). In addition to basic control, this autonomous behaviour can perform advanced “smart inverter” functions using one or more of the pre-set modes and/or schedules that respond to locally sensed conditions, such as voltage, frequency, and/or temperature. Responses could include anti-islanding ride-through protective actions, volt-var control, frequency-watt control, ramping from one setting to another per a schedule, soft-restart, and other functions that may be pre-set. Interaction latency requirements are typically milliseconds to seconds.
• Interaction 10 - DER management system interactions within Level 2 with multiple DER systems managed or coordinated by a DER facility energy management system (FDEMS). Peer to peer interactions can also occur between DER controllers, such as between a PV controller and a battery storage controller. The FDEMS has a more global vision of all the DER systems under its control, and can allocate tasks to different DER systems, depending upon the facility operator’s requests, load conditions within the facility, and possibly demand response pricing signals. It understands the overall capabilities of the DER systems under its management but may not have (or need) detailed data. FDEMS can issue direct commands but will primarily update the autonomous settings for each DER system. Interaction frequency may be seconds to minutes, hours, or even weeks.
• Interaction 1 – Direct DSO interactions with DER systems within Level 3, between Level 4 and Level 1. These direct DSO interactions usually imply that the DER system is under contract to be managed by the DSO, such as providing energy storage for smoothing fluctuations or counteracting spikes and sags. The DSO generally uses its SCADA system for these interactions. Interaction latency requirements are typically a few seconds.
• Interaction 2 – DSO interactions with FDEMS within Level 3, between Level 4 and Level 2. These interactions may be for the purpose of the DSO monitoring the aggregated generation and load, usually at the PCC, with the ability of the DSO to request ancillary services, such as reactive power support, frequency support, or limiting real power output at the PCC. The DSO could also request data on generation capabilities, load forecasts, and other longer term information. The DSO could also provide updated settings and schedules for specific advanced functions, such as volt-var control or frequency-watt control. It could also include pricing signals. These DSO-FDEMS interactions would probably not use the real-time SCADA system (due to concerns about the volumes of data and cyber security) and could be every few minutes, or hourly, weekly, or seasonally
• Interaction 3 – DSO interactions with aggregators within Level 3, between Level 4 and Level 5. These interactions would be primarily for the DSO to monitor aggregated groups of DER systems that are under the aggregator’s management. These groups of DER systems would be established by the DSO, such as all DER systems on a particular feeder or feeder segment, or all DER system capable of performing the volt-var function. The DSO could then issue commands (or requests, depending upon the contractual relationships) to specific groups of DER systems via the aggregator.
• Interactions 4 and 5 – Aggregator interactions with DER systems or FDEMS within Level 3 between Level 5 and Levels 3 and 4 (respectively). These interactions consist of monitoring and control (or requests) so that the aggregator has visibility of all DER or FDEMS under its management.
• Interaction 11 – Internal DSO interactions among applications and systems involved with DER systems within Level 4. These interactions between applications provide the capability of the DSO to make decisions on operating the distribution system with DER systems.
• Interaction 6 – DSO interactions with the TSO or ISO/RTO within Level 3, between Level 4 and Level 5. These interactions provide the TSO with the ability to request ancillary services from DER systems, FDEMS, and/or aggregators, by going through the DSO. The TSO can also request forecasts, information on emergency situations, and other DER-related data.
• Interactions 7, 8, and 9 - Market interactions by the TSO, aggregators, FDEMS, and DSO (respectively), within Level 5. These interactions would be for sending and receiving market offers, bids, and/or pricing signals.