Real-time Synchrophasor Applications for Power System Control

Authors: Ken Martin, Neeraj Nayak, Iknoor Singh, Electric Power Group, CA, USA, and Ian Dobson, Iowa State University, USA

Real-Time Contingency Analysis

RTCA background:  Power system operators strive to keep the power system stable and secure at all times. During operation, the system can be observed to assure voltages, frequency and power flows are stable and within acceptable limits. But there is always the question as to what will happen if any element fails. Will it be stable? Or will the problem lead to further problems or even (gasp!) a blackout? The RTCA addresses the what-if problem by removing one or more element at a time and solving the power flow to find out if the system is stable and the flows and voltages are within prescribed limits. Power systems are designed and tested to be N-1 (one element removed) secure, but they may not be with a sudden N-k (k elements removed) condition. Further, sometimes removal of one element will automatically cause removal of others, such as by remedial action or network separation. RTCA applications use a power flow model that shows steady-state violations and does not address dynamic stability.

This RTCA uses a base case of system model covering the utility area that has been updated with the solution provided by synchrophasor data. The base case is a complete set of bus voltages and branch flows that match with each other and the power system model. For this application, it is reduced to the utility of interest and its direct neighbors. It can be updated on a daily basis to keep it current. This case is then updated with the latest PMU measurements and resolved so all the measurements are consistent. This approach of updating a base case model was found to provide a more comprehensive and accurate contingency analysis than only using the PMU data subset by itself. In the next step, the RTCA applies each contingency, such as removing a line from service, to the solved case. The power flow solver updates the model topology for changes caused by the contingency and recomputes all the power flows and bus voltages. Then it tests the new values against limits specified in the model and notes any violations. It will run through the entire contingency set and report all violations. In the automatic mode, the RTCA will take a new case as soon as one is complete and repeat the process. Violations are reported in a user display (Figure 3). This display shows the history of runs (left side), a chart of category 1-3 results (top), and drill down panels where an operator can examine detailed results (center-right). Detailed results include the list of contingencies that cause violations as well list of violations caused by individual contingencies (bottom-right).

RTCA application example: Figure 3 shows an example of contingency violation identified by the RTCA. Loss of a 500-kV line from Bus A-C causes a category 1 limit violation for the power flow on the 500 kV/230 kV transformer A – D. A one-line diagram from the PowerWorld simulator shows this case and the resulting overload of 12% on the transformer A-D.

Voltage Stability
Concept of VSI application:  This Voltage Stability Index (VSI) application assesses the voltage stability of a pre-defined corridor by calculating an index using PMU data. The calculation uses the complex voltage and current measurements from the corridor boundary busses and can be done at the speed of measurement (eg, 60/second) since it does not require iterations. The approach has the effect of reducing a complicated transmission corridor to a single line equivalent. It can be applied to a corridor with multiple lines and several connection points (Figure 4). This approach is particularly useful in quickly assessing the impact of multiple outages which may require emergency action to forestall subsequent cascading events.
The first step in configuring this application is to define the corridor to be monitored. The corridor is chosen so that a typical power flow from generation at one end to load at the other end can stress the system towards a voltage collapse. It works best if there are no significant branches cross-wise through the corridor but will accommodate some input and output taps. A phasor measurement of the voltage and current of each line at the boundary of the corridor is required. The lines in the transmission corridor are reduced to a single line equivalent as follows:

The complex power S for each line at the boundary is computed from the phasor measurements, S=VI*. These are then summed to determine the total power flow at the sending (generation) end, Ss, and the receiving (load) end, Sr. The sending and receiving currents are also summed and used with the complex power sums to find the equivalent voltage across the system Vsr and at the receiving Vr end.

The VSI is simply the voltage across the corridor divided by the load voltage, calculated in %:

It is well known that voltage stability can be strongly affected by generators reaching their maximum reactive power output limits.  Accordingly, the VSI index calculation must monitor the generators providing significant reactive power to the corridor, and, if the limit is reached, change the modeling of the generator in the calculation to a negative load with the constant maximum value of reactive power. If the generator is not directly monitored by a PMU, its reactive power limit status could in some cases be estimated from nearby PMUs or by other signals.
The index is calibrated in an offline model by stressing the transmission corridor by gradually increasing the power flow through the corridor until voltage collapse and then finding the VSI threshold corresponding to the utility-defined emergency margin to voltage collapse. Additional alert thresholds can also be assigned at lower levels of stress, thereby allowing the operator to take precautionary corrective steps.

Application example:  As an example, we consider a transmission corridor through Oregon in the western US. Power flow is predominantly from Pacific North-West to California over a primarily 500 kV transmission corridor. The section from Grizzly substation to Captain Jack and Malin substations was chosen for the study.  Figure 5 shows a schematic layout of the corridor. A high load study case has 4308 MW entering the corridor at Grizzly substation and 3808 MW leaving the corridor at Captain Jack and Malin substations (with the difference leaving the corridor at Ponderosa substations). The power flows and the index are calculated using measurements from Malin, Captain Jack, and Grizzly. 

Loss of two Palo Verde Generating Units: As shown in Figure 6, loss of two Palo Verde Generating Units caused VSI to jump from 12.81% to 16.61% indicating a stressed voltage condition. The stressed voltage condition can also be verified from the Malin voltage subplot, where the voltage decreased from 535.7 kV to 514.8 kV.
Table 1 summarizes the results for a few scenarios. It is evident that VSI increases (worsens) with severity of the voltage issues.
In all cases, the index clearly indicated a stressed condition across the voltage corridor. The next steps are to test enough cases to determine index threshold values that differentiate between critical outages that need emergency action, those that only serve as an alert, and those that do not require special attention.  Emergency actions include adding reactive support at the load end of the corridor or reducing the corridor power transfer. Based upon the study results, we can assign an alert threshold of 19% and an alarm threshold of 23%.

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