Advances in Electric Power and Energy. Группа авторов

ERCOT and approved by ROS; the telemetered voltage minus State Estimator voltage shall be within 2% of the telemetered voltage measurement involved for at least 95% of samples measured during a one‐month period.

      5 On all transmission elements greater than 100kV; the difference between State Estimator MW solution and the SCADA measurement will be less than 10 MW or 10% of the associated emergency rating (whichever is greater) on 99.5% of all samples during a one‐month period. All equipment failing this test will be reported to the associated TSP for repair within 10 days of detection.

1.5 APPLICATIONS THAT USE SE SOLUTION

      The state estimator solution is a base case for CA and PF for almost all users. Some users employ the state estimator solution in security‐constrained economic dispatch and LMP and offline power flow applications [25]. In summary, the following applications use the state estimator solution as a base case:

       Contingency analysis

       Online/operator PF

       Locational marginal pricing

       Security‐constrained economic dispatch

       Voltage stability analysis

       Dynamic stability analysis

      A brief discussion of some of these functions is given next.

      1.5.1 Contingency Analysis

      As a real‐time application, CA uses current SE system conditions to determine the effects of specific, simulated outages (lines, generators, or other equipment) on power system security or higher load, flow, or generation levels. In addition, CA considers unexpected failure or outage of a system component (transmission lines, generators, circuit breaker, switch, or any other electrical equipment) and naturally line overloads or voltage violations or higher load, flow, or generation level [26–27].

      Failed or nonfunctional CA application has been identified as a key cause of many significant blackouts. Therefore, it must be highly available and redundant. The information produced by CA allows the operator to implement mitigation actions ahead of a contingency and maintain the reliability of the electric power system.

      1.5.2 Power Flow (Online/Operator)

PF calculates the state of the electric power system in the form of flows, voltages, and angles based on load, generation, net interchange, and facility status data. PF determines system state. PF are available in both online and offline versions. Online load flow programs are a standard part of all energy management system specification [28].

      Online PF is widely used to assess system conditions or perform look‐ahead analysis. It is also used in “n − 1” CA and to identify potential future voltage collapse or reliability problems.

      Real‐time reliability tools can only provide results that accurately represent current and potential reliability problems if these tools have real‐time PF and voltage values and status data for other elements included in their models. The accuracy of the information that real‐time reliability tools provide depends on the accuracy of the data supplied to the tools.

      1.5.3 Locational Marginal Pricing

      The equal incremental cost (system lambda) rule arises in conventional economic dispatch of a system of fossil fuel thermal generating units serving an active power load (demand) neglecting transmission losses. This case uses one active power balance equation (APBE) to model the electric network physical constraints. Accounting for transmission losses in the APBE leads to the well‐known loss penalty factors that are used to penalize the incremental cost of generation for each unit. Loss penalty factors whose values are greater than one correspond to units whose losses increase with the load demand and are further away from the load center. In optimal PF, the electric network is modeled using the PF equations and results in two lambdas (one for the active power equation and the second for the reactive equation) for each node in the system. This is the basis of LMP.

      LMP reflects the wholesale value of electric energy at different pricing nodes (locations) considering the operating characteristics, physical constraints, and losses caused by the physical constraints and limits of the transmission system and patterns of load generation. Pricing nodes include individual points on the transmission system, load zones (i.e. aggregations of pricing nodes), external nodes, and nodes where the independent system operator interconnects with a neighboring region and the Hub. The Hub is a collection of locations that represent an uncongested price for electric energy, facilitate electric energy trading, and enhance transparency and liquidity in the marketplace [29–32].

      Different locations in the system have different LMPs since transmission and reserved constraints prevent the next least expensive megawatt (MW) of electric energy from reaching all locations of the grid. Even during periods when the least expensive megawatt can reach all locations, the marginal cost of physical losses will result in different LMPs at different locations.

      Typically, the LMPs are calculated every five minutes. The LMP at a load zone is used to:

      1 Establish the price for electric energy purchases and sales at specific locations throughout the wholesale electricity market for compensating generators and charging loads.

      2 Collect transmission congestion charges.

      3 Determine compensation for holders of financial transmission rights.

      It is common practice to evaluate the LMP at a load zone as the weighted average of all the nodes within that load zone.

      In practice, an LMP consists of three components:

      1 Energy component of all LMPs that is the price for electric energy at the “reference point,” which is the load‐weighted average of the system node prices.

      2 Congestion component related to the marginal cost of congestion at a given node or external node relative to the load‐weighted average of the system node prices. In a manner like that of the load zone LMP, the congestion component of a zonal price is the weighted average of the congestion components of the nodal prices that comprise the zonal price. Moreover, the congestion component of the Hub price is the average of the congestion components of the nodes belonging to the Hub.

      3 Loss component at a given node or external node reflects the cost of losses at that location relative to the load‐weighted average of the system node prices. The loss component of a zonal price is the weighted average of the loss components of the nodal prices that constitute the zonal price. The loss component of the Hub price is the average of the loss components of the nodes that belong to the Hub.

      1.5.4 Security‐Constrained Economic Dispatch

      Conventional economic dispatch (ED) provides to the load frequency control (LFC) both economic base points and participation factors to control system frequency and net interchange in an economic fashion. The constrained economic dispatch (CED) application aims to meet the following objectives:

       Provide economic base points to LFC

       Promote reliability of service by respecting network transmission limitations

       Provide constrained participation factors

       Contribute no major impact on speed or storage requirements over present EDC

      Security‐constrained economic dispatch determines the level at which each committed resource should be operated while enforcing the “security” aspects of the system [33–34].

      1.5.5 Voltage Stability Assessment

The voltage stability assessment (VSA) application uses a current state estimator model of the real‐time system to determine additional load or transfer the system can sustain in a given direction before