- Jun 27, 2022 10:42 pm GMT
This item is part of the Special Issue - 2022-06 - DER and Management Systems, click here for more
The power industry is undergoing significant changes with an increasingly growing share of both intermittent renewable generation at the bulk power and distributed energy resources (DERs) at the distribution level. These changes create operational and reliability challenges with the variable nature of the bulk solar PV and wind generation, while planning the retirement of conventional baseload generation and experiencing variability in demand due to the DERs. At the same time, advancements in data communications, connected devices, building automation, and consumer sentiment are among many other drivers causing fundamental changes in the electric power industry.
Maintaining the reliability and affordability of the power supply have been the long standing objective of power system operations. Additional flexible resources and real-time energy balancing are needed to maintain grid reliability and stability in the face of the variability, intermittency, and continued growth rate of wind and solar generation coupled with increasing adoption of DERs at the retail and customer level. Properly managed, demand-side resources can provide such flexibility, and harnessing those can enhance system reliability, resilience, and stability of the power supply, and also make it affordable.
FERC’s landmark Order 2222 mandated all ISO/RTOs to allow DER Aggregations (DERAs) to participate in all ISO/RTO product markets they are technically capable to participate in, and to designate DER Aggregators as a type of Market Participant. This is a far-reaching order since it crosses over into the distribution and retail electric power jurisdiction. Order 2222 formalizes the integration and participation of DERs in all aspects of the bulk and retail power system and market operations. The order requires RTOs to accept DER Aggregations as small as 100kW, with no size limit on individual assets that make up the aggregation.
This landmark FERC Order is, in part, a reflection of the capabilities and the economics that can be gained through the integration of DERAs with system operations and energy markets. DERAs (a.k.a., Virtual Power Plants) are resources on the distribution grid that can effectively act as a generator and/or a load.
Providing visibility and situational awareness to all grid-edge resources, and dispatching or controlling of these resources to provide various grid services, have become requirements for distribution grid operation, and can provide high value to bulk system operations and energy markets.
Figure 1: Smart connected demand-side assets provide flexibility needed to mitigate the intermittency impact of renewable generation
THE EMERGING OPERATIONAL REQUIREMENTS OF THE DISTRIBUTION GRID
Traditionally, the focus on distribution grid operations has been on managing distribution wires and the protection, control, and regulating equipment to reliably deliver power from supply substations to end-use customers. Software tools and systems have been used to monitor the status of the distribution grid facilities in order to reliably deliver power at required voltages, and in the case of an outage, restore the system safely and in a timely fashion. Due to economic and technical considerations, the scope of coverage of a utility’s Distribution SCADA (D-SCADA) and Distribution Management System (DMS), have been limited to the primary (high and medium voltage) distribution equipment, with the assumption that the facilities and equipment under control are owned by the utility. Distribution Outage Management Systems (OMS) are also widely used to support system restoration following an outage.
In many cases, utilities are faced with technology and organizational silos, and the resulting compartmentalization of data. For example, a Customer Service group may maintain customer data in their Customer Information System (CIS) that may not be accessible to operators and systems in the Grid Operations group.
With the expanding penetration of DERs not owned by the utility, there is significant functional expansion and changes in distribution operations and the role of a distribution utility. This is due in part to the impact of DERs on the distribution grid and the capabilities they can provide in support of the grid and wholesale market operations. The distribution operator will need to have visibility to DERs and the parts of the grid where they are located, the ability to forecast the DER capabilities to offer various grid services, the ability to schedule and control them in real time, and operators must be able to assess their impacts on the grid.
Also, customer and third-party owned resources are typically operated under a given tariff or contract, and are subject to compensation for services provided under the terms of the tariff or contract. Thus, distribution utilities need capabilities that bring together commercial aspects of DER operations along with the grid related information, operational requirements, and constraints. A Distributed Energy Resource Management System (DERMS) provides such capabilities.
Figure 2: DERMS brings together commercial operations and grid operations for the modernized grid
ADMS Ensures Real-Time Reliability of Distribution Grid
Figure 3: Major functionality of DERMS in contrast to ADMS
ADVANCED DISTRIBUTION MANAGEMENT SYSTEMS (ADMS)
An Advanced Distribution Management System (ADMS) is a modular system integrating D-SCADA, DMS, and distribution. OMS is offered as a fully integrated solution or provided on an à la carte basis.
ADMS utilizes the real-time data acquisition capabilities of SCADA along with DMS and OMS applications to support real-time distribution grid operations. The key objective here is to improve system reliability indices, including System and Customer Average Interruption Duration Indices (SAIDI/CAIDI) and the System Average Interruption Frequency Index (SAIFI).
A quick use case will help illustrate the purpose and efficiency of an ADMS system. If a pole is knocked over by a car, a DMS application like FLISR (Fault Location, Isolation and Service Restoration), with the help of real-time D-SCADA information and fault detectors located in the field, would identify and isolate the fault location. The OMS will locate the nearest truck to dispatch to the location. The ADMS then creates switching orders for the field personnel to perform restorations. The OMS function uses the last-gasp information of Advanced Meter Infrastructure (AMI) to detect customer outages.
DERMS manages DER and DER Aggregation lifecycles from registration to supply of grid services and settlements, and provides for integration from IoT devices to markets and across utility enterprise systems.
Figure 4: DERMS brings together operational and commercial data from diverse sources and provides information to key systems and processes
DISTRIBUTED ENERGY RESOURCE MANAGEMENT SYSTEM (DERMS)
A properly designed and implemented DERMS addresses both grid reliability operations as well as commercial aspects of dealing with DERs, such as the associated transactions with customers and other third party DER asset owners. A DERMS provides the monitoring and control of DERs directly or through aggregators and third party head-ends, and manages DER metering and telemetry data. It interfaces and exchanges data and controls with other enterprise and legacy systems, including DMS/ADMS, breaking the silos of data across the distribution utility organizations to serve as the system of record for all data related to DERs and their operations. DERMS provides the capability to model the distribution grid topological connectivity and power flow and voltages, and extends the distribution grid operator’s visibility to parts of the grid not visible to the ADMS. It also provides the capabilities to forecast, schedule, and analyze DER impacts on the grid, and monitor DER operations as well as transactions with customers, aggregators, grid operators, the ISO and other stakeholders. A DERMS addresses both grid reliability operations and the commercial aspects associated with managing customers, their assets, and their contractual issues.
Some vendors with experience in demand management position DERMS myopically, as simply an extension of a Demand Response Management System (DRMS). This view lacks power system expertise to model and assess the impacts and benefits that controlling demand side assets, both DR and DER, may have on operations of both the distribution grid and the bulk power system. These may include providing frequency response to mitigate the impact of reduced system inertia, managing reverse power flows, and addressing the distribution grid operating constraints, such as voltage limits, phase imbalances and their impact on distribution grid losses, or fluctuations resulting from the intermittency of DER operations, among others. These capabilities are covered by a full function DERMS.
In a nutshell, DERMS helps turn DERs from being a grid reliability challenge into cost-effective grid services, which in turn improve grid reliability, stability, and resilience, while also improving supply economics.
A well-designed DERMS allows a utility to minimize renewable energy curtailment, and instead to leverage DERs to provide grid services, including capacity, various forms of reserves, frequency response, and voltage support, to mention a few. More generally, DERMS helps optimize the use of DERs so they are best utilized across multiple systems, by considering technical, operational and economic factors, while also meeting local customer, tariffs, contracts, and Power Purchase Agreement (PPA) requirements. A well designed DERMS, such as OATI’s webSmartEnergy® DERMS Solution, provides among others:
- Versatility: Handling a wide range of DER assets and DER Aggregates with homogeneous or heterogeneous DER types
- Enhanced Visibility: Leveraging field interfaces and sources of data
- Scalability and Adaptability: Supporting large volumes of data representing customers, DERs, and their operations. Provide scaling to support a growing organization’s needs.
- Performance: Providing required performance for monitoring, dispatch and control and management of large numbers of DERs
- Field and Enterprise Integration: Supporting industry interoperability standards integrating with DERs, 3rd party head-ends and enterprise systems — AMI, OMS, DMS, MDMS, CIS, EMS, GIS, and others systems
- Cyber Security: Adhering stringently to industry and federal cyber security standards.
Based on our field experience, when properly managed by a DERMS, DER assets can yield annual revenue streams in the range of $50 to $500 per kW DER capacity across the different products and services they offer. This does not include the additional “resiliency” benefits to the grid and consumers. To assess and monetize the value of resilience, subjective metrics are typically used, which could far exceed the quantifiable benefits quoted above.
LESSONS LEARNED AND PATH FORWARD
The great change of distribution grid operations we are observing today is reminiscent of a similar paradigm shift that we witnessed in North America more than twenty-five years ago
In 1996, FERC Orders 888 and 889 mandated “Transmission Open Access” to enhance competition in the generation and supply of electric power. This accelerated the de-regulation of the electric power industry and ushered in the break up and separation of bulk generation from transmission, opening transmission to all sources of generation. These led to the creation of Independent System Operators (ISO) to administer and manage energy and ancillary services markets. At that time, system vendors and newly forming ISOs quickly realized that a simple application of power system applications, originally developed as part of utility control centers and Energy Management Systems, could only address a small fraction of the requirements for managing the open transmission grid and administering market transactions with multitudes of new generation resources and a variety of stakeholders. New technologies and methods were developed at great expense to support the infrastructure required to interface with market participants, manage transactions, and also manage the grid.
OATI was born along with this Open Access and owes its success to pioneering cost effective solutions that addressed the operational issues that bulk power system operators were facing from those FERC Orders.
In the new FERC Order 2222 arena, conventional power system applications and solutions dealing primarily with reliability and operations of the grid have limitations, such as the performance and scalability needed to address numbers of data points and also control orders of magnitude larger than what they were designed for. More important, they lack the functionalities required to address the commercial and transactive side of problems, such as enrolling retail customers, validating and registering their assets, forecasting asset capabilities, baselining of every single metering point, modeling local operational requirements and power purchase agreements (PPAs), and monitoring and controlling ubiquitous DERs using inexpensive sensors that utilize newly formed communications and message payload protocols and standards, among others. Once again, OATI is leveraging its pioneering webSmartEnergy® DERMS solution built upon its field-proven platform and experience compiled during the last 25+ years to address these emerging industry needs.
The OATI DERMS design and development support each element in the complete life cycle of managing DERs:
Registration and Enrollment of Customers, Entities and their Resources: Managing various tariffs, creating standard and customized programs and services, and enrolling customers, aggregators and service providers and their DER assets and capabilities into these programs and services.
Resource Aggregation: Aggregating assets and their capabilities based into dispatchable resources, a.k.a Virtual Power Plants, based on various criteria, e.g., DER, customer, tariff/contract calcifications, Grid Service capabilities, grid and market pricing locations, etc.
Grid Topology Mapping: Modeling and tracking distribution grid topological connectivity from service delivery points to supply substations, the interface to transmission system. It provides for tracing function to update the topology based on as operated switching configurations. Aggregations and other DERMS functions leverage this capability.
Forecasting: System and Operations Planning: Forecasting load, DER and DER Aggregation capability forecasts, including solar PV, battery storage usage, and EV charging load, as well as Grid Service capability forecasts.
Scheduling and Schedule Coordination: Scheduling operation, dispatch and control of DERs, DER Aggregations and associated Grid Services. This may include various notifications, stakeholder and operational coordination, approvals and adjustments.
Optimization: Economic and operational optimization of resource and grid Service schedules while considering resource and commercial constraints, system conditions and market opportunities.
Telemetry and Monitoring: Cost-effective IoT level telemetry for monitoring the status of DER assets through industry standard protocols, interfaces to 3rd party head-ends, and use of OATI IoTSCADA capabilities. Graphical visualization techniques including geospatial maps provide overview and drilldown monitoring and alarming capability.
Dispatch and Control: Dispatching, disaggregating and/or controlling of DERs and DER Aggregations. Dispatch and control actions are monitored and exceptional conditions are alarmed.
Metering, Verification and Settlements: Handling metering and sub-metering data, baseline computations, dispatch performance assessments, and settlements with stakeholders and participating DERs for retail and bulk power services provided.
Logging and Record Keeping: Maintaining DER operational data in support of various management and regulatory reporting, business intelligence, and after-the-fact and post mortem analysis, and dispute resolution.
In contrast to the above elements, ADMS technology is architected to support real-time assessment of distribution grid conditions and provide system restorations following an outage. This architecture is highly influenced by the need for real-time processing of grid telemetry data, alarms and controls. As such, it is built around a database representing the status of only the primary distribution circuits, transformers, and regulators.
Furthermore, the ADMS operating model is typically built around utility owned assets with operators having full control of the assets, and behind-the-meter resources are not represented. In general, an ADMS does not deal with commercial aspects like tariffs or contracts, third-party supplied services, measurement, verification, or settlements, essential elements of a DERMS solution and necessary for business operations in the SmartGrid.
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