Distributed Energy Resource Technologies

Integrating Distributed Energy Resources into the Distribution System

Handout|Resources Definition of DERs

DERs are supply resources that generate electricity, store electricity, or control electricity usage at the distribution level. Note that resources connected to the bulk electric system are not DERs.

DERs may be connected: 1) Behind the customer meter, or 2) directly to the distribution grid

There are three key categories of DERs. Within each category, there are numerous technologies.

Demand side management Distributed generation (DG) Distributed storage (DS) (DSM) Production of electricity that is Absorption of electricity, coupled Electric loads whose usage can be either consumed internally or that with supplying energy back at a altered, either permanently or is injected into the distribution later time, either for internal temporarily. system. consumption or for injection into the distribution grid. Examples include: Examples include: ▪ Combined heat and power (CHP) ▪ Energy efficiency Examples include: ▪ Demand response by controllable ▪ Rooftop solar PV ▪ Reciprocating engine gensets ▪ Thermal energy storage loads ▪ Gas microturbines ▪ Battery storage ▪ Controllable electric vehicle ▪ Fuel cells ▪ Flywheels charging

DERs provide these benefits to distribution utilities and DER owners. We will discuss them throughout this course.

Voltage support DERs installed with smart inverters have the potential to provide reactive power to the grid, providing a resource that can be used to manage voltage on distribution circuits. Congestion management DERs under control of the distribution operator may be used to reduce loading on circuits that are approaching their design capabilities. Loss reduction Since DERs are located at or near loads, they may reduce the amount of current that a distribution circuit must carry thus reducing circuit losses Lower costs DERs used in a non-wires alternatives program may provide resources that eliminate or defer the need to upgrade distribution facilities Policy goals DERs may be used to achieve renewable energy or storage mandates and/or other regulative or legislative policy goals Resilience / reliability DERs provide a new source of supply that may be available to restore the distribution grid after an outage or when included in a microgrid to maintain service during an outage.

To understand the potential impact of DERs, we must understand how the distribution system is planned and operated to provide reliable service at a reasonable price. Reliability includes delivering electricity to consumers 1) within accepted voltage and frequency standards and 2) with minimal outages. Distribution systems include: • Substations • Primary feeders • Secondary feeders Typical connections voltages: • Utility-scale DERs such as large wind turbines and solar farms typically connect to the distribution system on primary feeders. • Behind-the-meter DERs often connect to secondary feeders.

Copyright Enerdynamics 2019 Components Substation components Substation transformers traditionally are designed for one-way transformation from higher transmission voltage to lower distribution voltage. Transformers Transformers not rated for two-way flow may need replaced and sizing adjusted as DERs impact load profiles. Breakers protect system components by isolating substation equipment during excess current flow. Protection schemes that dictate breaker Circuit breakers operation may need reconfigured to accommodate two-way flow. Breakers may need resizing to match new fault current ratings. Switches control flow from the substation into the distribution feeders. As DERs grow, switches may need resized or reconfigured to match Switches flow conditions. Voltage regulators traditionally are designed for typical transmission system voltages and voltage parameters of connected feeders. Voltage Voltage regulator regulation schemes may need redesigned to account for DER impacts.

Line components Feeder circuit Protect substation from excess fault currents by opening when required. DERs may increase fault currents thus requiring more robust breakers. breakers Line switches direct power flow by connecting or isolating feeders or mains. Automatic switches can be part of a protection scheme. As DERs Line switches grow, switch control systems may need redesigned to account for backflow. Fuses, reclosers, and automatic switches are used to isolate faults. As DERs grow, protection schemes require redesign to account for possible Protective equipment higher fault currents and backflow Voltage regulators including fixed transformers, locally controlled tap changers, fixed capacitors, and switched capacitors, are used to control Voltage regulator voltage levels on the lines. Line voltage may become volatile as DERs grow and DER output is varied. Such volatility may be addressed by adding more voltage regulation devices or through careful DER control. Line transformers reduce voltage as an intermediate step between higher and lower voltage lines or at the customer service. With more DERs, Line transformers transformers may need resizing to account for different amounts of normal and fault current. Conductors are wires that transmit the electricity. They are sized based on maximum current flow. As DERs grow, conductor sizing may change Conductors based on forecast amounts of normal current. In some cases, this can result in savings as DERs reduce the need for flow from the substation.

Service components

Depending on the type of DER, a new meter is often required. DR programs often require an interval meter that can verify performance over short time Two-way meter periods. DG and DS installations require a meter that can determine both energy consumed and energy provided to the grid.

Wind, solar PV, high-speed gas turbines, fuel cells, and batteries all require an inverter that converts DC power to AC power used by consumer appliances and Inverter the grid. In the case of batteries, an AC to DC converter is also required when the battery is charging.

An automatic disconnect switch is required to isolate DG and DS from the grid in the event of unexpected outages and during planned outages for Disconnect switch maintenance. The disconnect is necessary for safety since otherwise, the DER could flow energy onto the grid when utility workers expect that the grid is de- energized. Copyright Enerdynamics 2019 Interconnection

Inverters Remote control and monitoring For DC power systems such as wind, solar, and batteries, In many cases, a third-party service provider or a system and for fast-spinning gas turbines, an inverter is required operator must monitor and/or control DERs. In some to convert to AC power. The inverter type is critical to how cases, monitoring and control coupled with backend IT DERs interact with the grid. Smart inverters provide the systems allow multiple DERs to be aggregated into useful technical capability for DERs to become grid resources. blocks of capacity. When multiple assets are owned by Convert DC power to AC power one customer, they can be optimized on a portfolio basis. Smart inverters include: • Power conditioning • Control of real and reactive power output • Remote control capabilities • Bi-directional communications capabilities

Simple interconnection Bi-directional The meter must be able to record flows into the facility and the Distribution grid meter distribution grid. Sometimes a simple energy meter is enough, but other times a smart meter is necessary to record time-of-day interval data, real power (kW), energy (kWh), and reactive power (kVA). A communications Bi-directional line that allows remote meter reading also may be required meter Breaker box The breaker box contains the primary disconnect for the loads as well as disconnects for each circuit. This part of the customer wiring is separate from the DER interconnection. Customer loads Disconnect DG and DS require a disconnect switch to prevent supply from feeding Disconnect Breaker box switch switch into the grid during outages or maintenance. Often a visible air-gap switch provides a verifiable break between the DER and the grid. Either the disconnect switch or the inverter must automatically disconnect the DER from the grid during an outage Inverter Inverter The inverter converts the DC power from the PV panels to AC power. Certain inverters are certified to automatically disconnect during outages. Smart inverters provide equipment status monitoring and remote control including control of real and reactive power output. Smart inverters may PV panel also provide ride-through for short frequency or voltage disruptions

Bi-directional A bi-directional inverter is required since power flows into and out of the inverter batteries. When power is discharged it converts DC power to AC power, More complex interconnection and when the batteries are charged it converts AC to DC. Bi-directional The meter must record flows into the facility and the distribution grid. Bi-directional Bi-directional meter Since the facility will provide grid storage services, a revenue-grade meter inverter Breaker meter Distribution grid is required to measure time-of-day interval data, real power (kW), energy (kWh), and reactive power (kVA). Air-gap switch Inverter System operators rely on inverter controllers to remotely manage battery controller functions.

Air-gap switch A visible air-gap switch is required to provide a visibly verifiable break Battery packs between the DER and the grid. Remote control disconnect is also provided by the protective relay connected to the main breaker. System Protective Protective When specific pre-programmed conditions occur such as over- or under- relay operator relay voltage/frequency, the protective relay signals the breaker to open.

Communicati To use the facility for grid services, a dedicated communications link that ons line allows for remote control and monitoring is required. A high-speed fiber link may be necessary depending on the nature of the services. Copyright Enerdynamics 2019 Interconnection rules

Interconnection rules specify the necessary equipment required for IEEE 1547 Standard a DER to connect to the grid. To help states establish workable interconnection standards, the • Most interconnection rules are set by state regulators. engineering organization IEEE has developed model standards. IEEE 1547-2018 is a technology-neutral model standard that fosters a • But in cases where the DER will participate directly in ISO stable and reliable distribution grid, addresses potential impacts of markets, the ISO may also specify additional interconnection DERs on the Bulk Electric System (BES), and allows DERs to be utilized requirements. as grid assets. • Interconnection rules are set at the state level and vary from Key provisions include: state to state and even from utility to utility. • Performance requirements • Operational requirements • Testing specifications • Safety • Maintenance • Response to abnormal conditions • Power quality • Islanding EEE 1547 continues to evolve with growing penetrations of DERs. The 2018 update added provisions to ensure DERs can act as grid support and, where desired, can participate in wholesale markets. Key provisions added in 2018: • Communications capability • Information availability • Abnormal voltage and frequency ride through • Active voltage control capability (control of real/reactive power output) • Frequency regulation capability • May provide frequency inertial response

Copyright Enerdynamics 2019 Grid modernization Grid modernization refers to making investments in the distribution system to improve current functions and bring new capabilities. Goals include improved operations, better customer service, enhanced DER integration, and facilitation of new services. Many of these investments are necessary to enable effective DER integration and utilize its benefits.

Installation of sensors and other smart devices capable of providing Monitoring and communications information and a communications system capable of delivering data Implementation of key systems to provide monitoring, control, and data IT systems management associated with smart infrastructure and DERs Integration of power management devices and switches that can operate Distribution automation autonomously or through remote control Interconnection to a diverse and distributed mix of resources including Flexible resources DSM, DG, and storage

Substation Condition of equipment is monitored remotely, system conditions reported to distribution operations in real time, remote control of settings on switches and voltage regulators, remote security alarming Fault locator Reports faults immediately and communicates directly with automated switches to isolate the fault and automatically restore service where possible Switch Automated switch can be monitored and controlled remotely either by human system operator or by automated outage management system Voltage regulator Local intelligence at a capacitor bank or transformer with taps monitors the voltage and automatically switches capacity banks or taps to control voltage Power line monitor Monitors that provide situational awareness along the distribution grid to assess real-time power line and power quality conditions, and detect anomalies such as overloading or line sagging. Recloser Recloser with local intelligence monitors weather conditions and changes operations to avoid re-energizing lines on high fire days

Transformer Condition of transformer such as oil temperature and composition is reported remotely to operations software to identify when maintenance is required Meter Smart meter stores data at intervals such as five or fifteen minutes, records advanced data, reports data back to central data management system at intervals set by the utility, and notifies the utility if an outage is detected. Inverters Smart inverter provides voltage/frequency ride-through during system disturbances, allows remote control of real/reactive power output for voltage control, automatically supports system frequency, and allows remote curtailment of DERs Controllable load Distribution operator or third-party aggregator can remotely curtail loads, either directly through control on the device, or via a building control system Copyright Enerdynamics 2019 Communications infrastructure

High-speed communications infrastructure that transports data and controls signals is key to grid modernization. Electric distribution utilities will be expected to provide such networks and will do so by managing a combination of utility-owned facilities, leased third-party facilities, and customer-owned internal networks.

System that connects and aggregates many energy grid operational functions to provide visibility of system conditions plus outage management and restoration capabilities. An ADMS combines Advanced Distribution numerous systems that previously may have been separate including outage management, Management System (ADMS distribution management, voltage management, demand response program management, and data analytics to enable a highly visible and controllable distribution grid. System that manages response to outages, and may include or interact with the utility GIS system, the Outage Management System (OMS) customer information system, an automated call handling system, and the FSLIR system to prioritize and direct service restoration crews in the field and to provide information to customers. Fault Location Isolation Service System of automated switches and reclosers, line monitors, communications networks, and data Restoration (FLISR) analytics that identifies faults and mitigates their effects including automated power restoration. Control and data acquisition system that is the primary system for distribution operators to interact SCADA with key distribution assets. System and infrastructure for collecting and analyzing meter data including smart meters, automated Advanced metering infrastructure meter reading (AMR) software, and meter data and management system (MDMS). Interacts with the (AMI) billing system, the OMS, customer portals, and demand response management systems. Distributed Energy Resources System that aggregates and controls DERs using monitoring, data analytics, and control function to Management System (DERMS) provide DER visibility and allow DERs to be operated as grid assets. System that allows consumers and third-party service providers to interact and provide data so that service providers can develop and deliver customer-focused energy services and so that consumers Distribution Services Platform (DSP) can easily buy services and can easily participate as a seller in distribution-level or wholesale energy markets. Systems that collate data from various sources, analyze the data, and provide usable information to the other IT systems and/or to human grid operators and managers. May include artificial intelligence Data management and analytics components to optimize actions taken based on data. Often interacts with other systems such as ADMS, OMS, DERMS, and DSP.

The grid must evolve as DER penetrations increase and consumers use DERs in new ways.

Step Traditional planning Planning with DERs

1. Forecasting Key tasks: List of locations where capacity can’t • Evaluate existing peak loads by feeder and substation handle DER output • Forecast system load growth • Forecast peak load growth by feeder and substation Outcome: List of locations where capacity can’t meet peak load 2. Reliability Key tasks: A hosting capacity analysis that and power • Identify existing reliability, voltage, or other power quality issues determines maximum capacity of DERs quality • Identify potential solutions on each feeder analysis Outcome: List of locations where components need replaced or upgraded to enhance service quality 3. Special Key tasks: Projects required to integrate forecasted projects • Identify proposed special projects (i.e. smart meter roll-out, distribution DERs automation initiative, etc.) Outcome: New infrastructure plans 4. Risk / Key tasks: Analysis of the locational value of DERs benefit • Analyze risks associated with normal and “one-point of failure” operations and identification of non-wires analysis • Analyze component conditions alternatives • Perform benefit-cost analysis Outcome: Proposed capital and expense plan that includes system enhancements 5. Regulatory Key tasks: Regulators may hold separate oversight • File plan with regulator proceedings to analyze DER issues • Participate in regulatory proceeding resulting in an approved DER integration Outcome: An approved capital and expense plan including specific project plan approval 6. Final plan Key tasks: System is upgraded to integrate • Implement final distribution plan forecasted DERs Outcome: System is upgraded to address forecasted reliability issues

As DER penetrations grow, the factors that must be evaluated during planning evolve.

Load history, new customer connections, and forecast load growth have historically been used to determine necessary capacity for each distribution feeder. As a small amount of DERs are added to feeders, they can simply be modeled as negative load. But as DERs grow above five to ten percent of peak load models must be enhanced to more closely replicate DER behavior.

Since many DERs are variable or are impacted by hourly consumer decisions, forecasting must move from a focus on peak loads to forecasting hourly loads on each feeder.

Copyright Enerdynamics 2019 Power flow analysis The hourly forecast for DERs allows a distribution power flow analysis to determine how power will flow on each feeder throughout the day. This often requires a more detailed feeder segment model than was required in the past.

A Hosting Capacity Analysis (HCA} allows the utility to transparently state what level of DERs can be connected to each feeder without spending on upgrades. It also provides the utility planners with specific information on which components require an upgrade if higher penetrations occur.

The combination of power flow and hosting capacity analyses allows the distribution utility to determine where on the system DERs have the highest value. Factors considered include the value of wholesale energy at the distribution substation, reduced losses on the distribution feeder, deferral of load-based upgrades and reliability improvements, and the required investment to integrate the DER.

Non-wires alternatives are projects using DERs that allow system upgrades to be deferred or made permanently unnecessary.

Distribution resource plans often include a framework for new investments in communication infrastructure and software that will transform the grid into a platform enabling innovative services associated with DERs.