MultiSpeak and the NIST Smart Grid

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MultiSpeak and the NIST Smart Grid

Conceptual Reference Model

Figure 1: NIST Conceptual Model: Detailed View

Figure 2 shows the specific logical architecture required to achieve the goals of this conceptual model and sets the stage for how the MultiSpeak specification helps achieve the needs of the smart grid, as identified in NIST's Standards Framework and Roadmap.

Figure 2. Logical Architecture for Enterprise Applications

The National Institute of Standards and Technology (NIST) has developed a Smart Grid Conceptual Reference Model as part of its Smart Grid Standards Framework and Roadmap [1]. Figure 1 shows the detailed conceptual model. NIST has identified 42 standards to support this vision. MultiSpeak was chosen by NIST as a key standard in the Operations area in Figure 1. Figure 2 shows the specific logical architecture required to achieve the goals of this conceptual model and sets the stage for how the MultiSpeak specification helps achieve the needs of the smart grid, as identified in NIST's Standards Framework and Roadmap.

Each box in Figure 2 is an actor. As far as the discussion of logical architecture is concerned, actors are software applications, with the exception of the meter in the Customer domain that acts as the gateway actor between the distribution utility operator and the customer. Software applications that potentially exchange data within an enterprise network are shown as being connected with heavyweight black lines. Such an exchange of data occurs across interfaces. Enterprise networks may be local area networks (LANs) or wide area networks (WANs) or a combination of the two. When software applications are connected together in such a manner that the data flows span NIST conceptual model domains (or sub-domains) then the communications path between the linked gateway actors is shown as a lightweight line. Table 1 describes each enterprise software application shown in Figure 2.

Description of Enterprise Software Applications

Application	Description
(A1) AMI	Advanced Metering Infrastructure (AMI). This system manages communications with meters, typically at customer locations. The AMI system also often acts to manage customer loads or to connect/disconnect/reconnect customer services.
(A2) Distribution SCADA	Distribution domain Supervisory Control and Data Acquisition (SCADA). Distribution SCADA systems control and obtain data about (typically) distribution substation equipment.
(A3) Meter Data Management	Meter data management (MDM) systems typically act as a centralized data management system to store meter readings and meter-related event data, such as customer outages, meter change-outs, or meter demand resets. MDM systems often are used to validate meter data, including estimating missing data. MDM systems may also include supplemental modules to filter, accumulate, or analyze meter data before it is sent to other systems. In the context of this project, the MDM system may be either (i) a shared system located on the generation and transmission operator network or (ii) a system on the network of a single distribution operator.
(A4) Demand Response	Demand response (DR) systems accept demand targets or market price signals from other systems, such as the Demand Management system (see A15, below), and send control or price signals to other systems, such as the AMI (see A1, above) or the Demand Response Automation Server (see A14, below) so that those systems can pass such control or price signals to other systems or to end devices.
(A5) Engineering Analysis	Engineering analysis (EA) accepts facility data and/or power system models from a geographic information system (see A9, below) and operational data such as metered data from AMI (A1, above) or system operations data from distribution SCADA or distribution automation systems (A2, above or A8, below) and perform off-line analyses of the data. EA systems are often used for system planning purposes. EA systems are sometimes deployed as a module of a distribution management system (DMS).
(A6) Distribution State Estimation	Distribution state estimation (DSE) systems are an emerging variety of engineering analysis system that are designed to perform real-time or near-real time analyses of power system models based on actual metered data and system operations data. DSE systems are often deployed as a module of a distribution management system (DMS).
(A7) Outage Management System	Outage management system (OMS). The OMS accepts detected outage information from customer telephone calls, as well as from automated outage detection systems such as the AMI system (A1, above)or the interactive voice response system (A12, below). The OMS system then analyzes the pattern of detected outages based on a power system model and assists a dispatcher to manage crews to restore the affected facilities.
(A8) Distribution Automation	Distribution automation systems are similar to distribution SCADA systems (see A2, above) except that DA systems typically control or obtain data from devices down line of the distribution substation.
(A9) GIS	Geographic Information System (GIS). The GIS stores and displays information about customers, facilities and work in a geographic context. The GIS is often used as the central repository for the power system model that is subsequently provided to the EA (A5, above), DSE (A6, above), or OMS (A7, above).
(A10) Work Management	Work management (WM). The work management system generates and tracks work-related activities. The work management system is often integrated with (i) the AMI (A1, above) or MDM (A3, above) for managing work related to setting, replacing and retiring meters, (ii) the customer information system (A13, below) for managing service or construction work, and (iii) the OMS (A7, above) for managing outage restoration.
(A11) Automated Vehicle Location	Automatic Vehicle Location (AVL). The AVL system uses global positioning system (GPS) technology to locate utility-owned vehicles and display them in geographic context. AVL system output is often used in the GIS (A9, above), the OMS (A7, above) and the WM (A10, above).
(A12) Interactive Voice Response	Interactive Voice Response (IVR). The IVR system automatically answers customer calls and routes them to the appropriate department or system for further action. In this context, the IVR is integrated with the OMS (A7, above) to manage customer outages.
(A13) Customer Information System	Customer Information System (CIS). The CIS typically consists of several software modules that include a customer database, a bill calculation mechanism, plant inventory, and accounting systems. The CIS must be integrated with many of the systems listed here to provide customer information and to accept meter readings from the AMI (A1, above) or MDM (A3, above).
(A14) Demand Response Automation System (DRAS) Server	Demand Response Automation System (DRAS) Server. The DRAS Server is a system that accepts demand response targets or market price signals from the DR (A4, above) and implements the Open Automated Demand Response (OpenADR) protocol. OpenADR is used to coordinate demand response actions with DRAS Client systems (A22, below) at customer facilities or third-party service aggregators.
(A15) Demand Management	Demand Management (DM). The DM system accepts demand response targets or market price signals from the Load Forecast system (A16, below) and manages appropriate demand response actions with the Demand Response (DR) system (A4, above) at each of the distribution utilities.
(A16) Load Forecast	Load Forecast (LF). The LF system accepts market signals from the Market Services application (A18, below), calculates the relative value of the output of generation assets and demand response resources, and send demand response management targets to the DM system (A15, above).
(A17) G&T EMS	Generation and Transmission (G&T) Energy Management System (EMS). The G&T EMS is a system that collects data from and controls generation and transmission assets, acting in a manner similar to a SCADA system.
(A18) Market Services	Market Services (MS). The MS coordinates market signals with the Energy Market Clearinghouse (A20, below) and sends market information to the Load Forecast application (A16, above).
(A19) RTO/ISO EMS	Regional Transmission Operator (RTO) /Independent System Operator (ISO) Energy Management System (EMS). The RTO/ISO EMS collects information on regional transmission assets and operational conditions and acts to control those transmission assets.
(A20) Energy Market Clearinghouse	Energy Market Clearinghouse. The energy market clearinghouse is the market system that coordinates with market participants to exchange either price signals or bid and offer information. The energy market clearinghouse system in the market domain communicates with the market services application(s) (A18, above) in the generation and transmission system operator domain.
(A21) Distributed Energy Resources EMS	The distributed energy resources (DER) energy management system (EMS). This system acts to collect information about the operation of and to control the assets of a DER facility. In the context of this demonstration project, the DER may be either a distributed generation (DG) or distributed storage (DS) facility. In the context of this demonstration project, it is assumed that the DER EMS will coordinate with the distribution SCADA application (A2, above) in operation at the distribution operator.
(A22) Demand Response Automation (DRAS) Client	Demand Response Automation System (DRAS) Client. The DRAS Client implements the client portion of the Open Automated Demand Response (OpenADR) protocol, which is used to coordinate demand response actions with DRAS Server system (A14, above).

References
[1] National Institute of Standards and Technology, NIST Framework and Roadmap for Smart Grid Interoperability Standards, Release 1.0, NIST Special Publication 1108, January, 2010.