Systems and methods for improved rate of change of frequency ride-through in electric power systems

This application provides methods and systems for rapid load support for grid frequency transient events. Example electric power systems may include a turbine, a generator coupled to the turbine, where the generator is configured to provide power to an electrical grid, and a controller configured to detect a grid event, determine a rate of change of frequency (rate of change of frequency) value, determine a predicted post-grid event governor set point based on the rate of change of frequency value, and initiate a change to at least one turbine operating parameter based on the predicted post-grid event governor set point.

TECHNICAL FIELD

This application and the resultant patent relate generally to electric power systems and more particularly relate to improved rate of change of frequency ride-through in gas turbine power systems.

BACKGROUND OF THE INVENTION

Many known electric power systems include several types of electric power generating units, such as, for example, synchronous generating units and/or non-synchronous generating units. Synchronous generating units are those in which the output voltage waveform generated during operation is synchronized with the rotation of an element (e.g., a prime mover) within the generating unit. Synchronous generating units typically include a rotating mass that rotates within the generating unit to generate output power. Non-synchronous generating units are those in which the output voltage waveform generated during operation is not necessarily synchronized with the rotation of a mass within the generating unit, because, for example, the non-synchronous generating unit may not include such a rotating mass. Examples of non-synchronous generating units include, solar or wind power generating units. At least some conventional electric power systems have adequately tolerated the loss of one or more generating units or loss of loads within the electric power system through the presence of a large number of synchronous generating units distributed within the system.

More particularly, because a synchronous generating unit may include a rotating mass (e.g., the prime mover and generator), it is possible to compensate for the loss of a generating unit or loss of loads within the electric power system of larger grids by distributing the deficit or surplus in electrical power within the system over the remaining number of generating units, which rotate with inertia sufficient to absorb, or “ride-through” the loss (although the rotating mass within each synchronous generating unit may turn more slowly). However, in some instances, in particular for smaller grids, ride-through may not be possible when a large frequency transient event occurs because of an inability to correctly determine an operating state after a transient event is complete. The negative effects of transient events, such as sudden changes to grid frequency, are amplified for smaller grids, such as grids that provide a load capacity of about 500 megawatts (MW). Smaller grids are often less stable than larger grids since a load change of the same magnitude will result in a larger frequency change. Thus, smaller grids tend to experience frequency changes more often than larger grids. A lack of stability may result in blackouts and/or loss of power to the grid. Systems and methods for improved rate of change of frequency ride-through are therefore desired to increase the stability of power to a grid.

SUMMARY OF THE INVENTION

This application and the resultant patent provide improved rate of change of frequency ride-through in gas turbine power systems. The system may include a turbine, a generator coupled to the turbine, where the generator is configured to provide power to an electrical grid, and a controller configured to detect a grid event, determine a rate of change of frequency (rate of change of frequency) value, determine a predicted post-grid event governor set point based on the rate of change of frequency value, and initiate a change to at least one turbine operating parameter based on the predicted post-grid event governor set point.

This application and the resultant patent further provide a method for riding-through grid events for gas turbines. The method may include detecting, by a controller, a grid event, determining a rate of change of frequency value, determining a predicted post-grid event governor set point based on the rate of change of frequency value, and initiating a change to at least one turbine operating parameter for a gas turbine based on the predicted post-grid event governor set point.

This application and the resultant patent further provide a system for riding-through grid events for gas turbines. The system may include a gas turbine, a generator coupled to the gas turbine, where the generator is configured to provide power to an electrical grid, and a controller configured to detect a grid event, determine a rate of change of frequency value, determine an estimated magnitude of the grid event based on the rate of change of frequency value, determine a predicted post-grid event governor set point based on the estimated magnitude of the grid event, determine a destination mode for combustion using the predicted post-grid event governor set point, and initiate a change to an air/fuel ratio based on the destination mode.

DETAILED DESCRIPTION

Referring now to the drawings, in which like numerals refer to like elements throughout the several views.FIG. 1is a schematic diagram of an electric power system100. The electric power system100may include a number of generating units and a number of electrical loads coupled to the generating units. Any number of generating units, loads, and other common electric power system components may be included.

The electric power system100may include one or more electrical system components, such as a first electrical load102a, a second electrical load102b, and/or a third electrical load102c. The electric power system100may also include one or more generating units, such as a first generating unit104a, a second generating unit104b, and/or a third generating unit104c. In the illustrated embodiment, generating units104a-104cmay be synchronously connected gas turbine generating units. However, in other embodiments, generating units104a-104cmay be any generating unit that includes a rotating prime mover, such as steam turbine generating units, reciprocating engine generating units, hydro-turbine generating units, and the like. In some embodiments, electric power system100may include at least one electrical power transmission and distribution system component106, such as, for example, one or more transmission lines, one or more distribution lines, one or more transformers, one or more voltage regulators, and the like. An interconnected electrical power transmission and distribution system component106may thus facilitate the supply of electrical power from generating units104a-104cto one or more electrical loads102a-102c.

The electric power system100may optionally include a non-synchronous power source112, such as a wind and/or a solar electric power system. Non-synchronous power source112may be coupled to electrical power transmission and distribution system component106through a power line, such as an non-synchronous source line113, and may supply electrical energy to one or more electrical loads102a-102cvia electrical power transmission and distribution system component106.

Some or all of the generating units104a-104cmay include at least one controller and/or at least one sensor. For example, generating unit104amay include a controller114aand a sensor116a, generating unit104bmay include a controller114band a sensor116b, and generating unit104cmay include a controller114cand a sensor116c. Each controller114a-114cmay include a processor and a non-transitory computer-readable memory communicatively coupled to the processor.

The electric power system100may include a number of event estimators120a,120b, and120c. In various embodiments, each event estimator120a-120cmay include at least one processor and may be installed within a particular generating unit104a-104c. In some embodiments, each event estimator120a-120cis not a separate hardware component but is embodied as software that executes on a respective controller114a-114cof each generating unit104a-104c. In addition, in some embodiments, each event estimator120a-120cmay be implemented on a standalone computing device that is communicatively coupled to a respective controller114a-114cof the respective generating unit104a-104c.

The electric power system100may include a network estimator118. In various embodiments, network estimator118may include at least one processor152coupled to at least one non-transitory computer-readable memory154. In some embodiments, network estimator118may be implemented on a computing device, such as a workstation computer, a personal computer, a tablet computer, a smart phone, and the like.

The network estimator118may be communicatively coupled (e.g., over a communications network, such as the internet) to one or more data sources150, such as one or more databases and/or database servers. Data sources150may be online and/or offline data sources and may include or store a variety of information associated with electric power system100, such as a variety of status information. Network estimator118may also be communicatively coupled to each event estimator120a-120c.

The status information received by network estimator118via data sources150may include any status information associated with electric power system100, such as, for example, location information, timing information, and/or maintenance activity information, such as scheduled outage information for at least one of generating units104a-104c, electrical loads102a-102c, electrical power transmission and distribution system component106, and/or non-synchronous power source112. Status information may also include information describing rotational inertia associated with each generating unit104a-104c, a total rotational inertia associated with generating units104a-104cwithin electric power system100, and/or a proportion of electrical power being generated at any given time in electric power system100by non-synchronous power source112. This status information may be transmitted over a computer network via at least one grid signal122.

Status information may also be detected by one or more sensors within electric power system100, such as, for example, sensors116a-116c, which may detect an operational status of each generating unit104a-104c, such as a rotational velocity, a temperature, an output voltage, an output current, an output frequency, valve position, a system identifier (e.g., a serial number), and/or a fuel type of generating units104a-104c. Similarly, a sensor (not shown) coupled to electrical power transmission and distribution system component106may detect one or more characteristics thereof, such as, for example, at least one of a type, location, time of occurrence, and severity of a fault, a voltage, a current, a frequency, and a system identifier. Likewise, one or more sensors (not shown) coupled to electrical loads102a-102cmay detect characteristics thereof, such as, for example, an voltage, an current, an frequency, a location, at least one of a type, location, time of occurrence, severity of a fault, and/or a system identifier.

The status information detected by one or more sensors with electric power system100, such as by sensors116a-116c, may also be used by controllers114a-114cto detect the occurrence of a rate of change of frequency event and/or a grid event within electric power system100. For example, where a sensor116a-116cdetects a large increase or decrease in the frequency or speed of a corresponding generating unit104a-104c, a respective controller114a-114cmay determine that a rate of change of frequency event has occurred.

Accordingly, the network estimator118receives status information via grid signal122and determines or obtains at least one network characteristic representative of an operational status of electric power system100, such as for, example, at least one frequency characteristic of electric power system100. More particularly, network estimator118uses status information to generate at least one model of electric power system100. For example, network estimator118may analyze the status information to generate a model of the electric power system100, such as a look-up table that correlates a plurality of rate of change of frequency values with one or more electric power system characteristics, such as one or more frequency characteristics. The model may thus include and/or describe one or more characteristics of the electric power system100and may represent one or more interrelationships between elements coupled to the electric power system100, such as between generating units104a-104cand electrical loads102a-102c. In addition, network estimator118may transmit all or a part of the model, such as a model look-up table, of the electric power system100to each event estimator120a-120c.

The model of the electric power system100may identify one or more characteristics of the electric power system100and/or generating units104a-104c, such as a settling frequency, a settling power, a frequency peak, and/or a frequency nadir. These characteristics may be based upon an analysis of the status information associated with electric power system100. To this end, the model provided to each event estimator120a-120cmay include a look-up table that cross-references a plurality of rate of change of frequency values with a plurality of characteristics, such as a plurality of settling frequencies, a plurality of settling powers, a plurality of frequency peaks, and/or a plurality of frequency nadirs. In general, a settling frequency and a settling power are the speed or frequency and the output power, respectively, into which a generating unit104a-104c“settles” or stabilizes after the occurrence of a grid event and/or after a primary response to a rate of change of frequency event and/or grid event has been deployed within electric power system100. Similarly, a frequency nadir is the lowest output power frequency occurring as a result of a grid event, and a frequency peak is the highest output power frequency occurring as a result of a grid event. In the exemplary embodiment, the model may be transmitted via a network signal124to each event estimator120a-120c, and each event estimator120a-120cmay store the model (including associated characteristics) in a memory, such as, for example, in a non-transitory computer-readable memory.

The network estimator118may receive and/or collect status information on a periodic basis (e.g., once every fifteen minutes, etc.) to update the model of the electric power system100. The updated model may include updated characteristics associated with electric power system100and may be transmitted to one or more event estimators120a-120cfor storage. In various embodiments, network estimator118may receive feedback from one or more event estimators120a-120c, such as feedback about an estimated characteristic in comparison to an actual or measured characteristic. For instance, a particular event estimator120a-120cmay use a look-up table to estimate a particular frequency nadir based upon a measured or sensed rate of change of frequency value. The particular event estimator120a-120cmay receive from a sensor116a-116c, an actual frequency nadir occurring as a result of the rate of change of frequency event, and an error or difference between the estimated frequency nadir and the actual frequency nadir may be returned as an error value to network estimator118. Similarly, the actual frequency nadir (rather than, or in addition to, the error value) may be returned to network estimator118.

As used herein, the phrase “grid event” refers to an abrupt change in total electrical power consumed within and/or generated by an electric power system. For example, a grid event may be associated with a sudden reduction of total generation or load within an electric power system due, for example, to loss (or tripping) of one or more generating units, one or more non-synchronous power sources, and/or one or more loads. In addition, as used herein, a “source rejection grid event” is an abrupt change in total electrical power generated by an electric power system, such as, for example, as a result of a loss of one or more generating units. Similarly, as used herein, a “load rejection event” is an abrupt change in total electrical power consumed by an electric power system, such as, for example, as a result of a loss of one or more loads.

These grid events may affect the power output by one or more generating units, such as, for example, one or more rotating gas turbine generating units, coupled to the electric power system. For example, during a source rejection grid event, one or more generating units still coupled to the electric power system may initially experience a reduction in rotational speed as each generating unit attempts to compensate for the loss of generation power within the electric power system. Similarly, during a load rejection event, the power output by the prime movers of the generating units coupled to the electric power system may exceed the power required for the total electrical load on the electric power system, which may result in an increase in the rotational speed associated with one or more of the generating units. As the rotational speed of the generating units within the electric power system increases and decreases, the frequency of the alternating electrical current and/or the voltage developed by the generating units within the electric power system may fluctuate rapidly. For convenience, these frequency fluctuations may be referred to herein as rate-of-change-of-frequency events (or “rate of change of frequency”) events. Some machines may also trip during the process of responding to frequency changes. Rate of change of frequency events therefore occur as a result of one or more grid events and may lead, as described herein, to the loss of one or more other generating units on the electric power system, which may contribute, in turn, to overall electric power system instability. In addition, as described herein, rate of change of frequency events are associated with rate of change of frequency values, such as values ranging from zero to two Hertz/second. In some embodiments, a rate of change of frequency value may indicate a severity of an associated rate of change of frequency event.

Embodiments of the disclosure may be configured to enhance dry low NOx modes in gas turbines, when a large frequency transient happens in a small grid. Some embodiments may calculate an approximate nadir/peak change in the amplitude of frequency in the first 200-300 milliseconds after the transient. For example, a network estimator or other computer system associated with the electric power system may be configured to measure or otherwise determine the rate of change of frequency immediately after the start of the grid event. Instead of an acceleration based dry low NOx mode switch/fuel management, the gas turbine control can modulate air-fuel ratios, dry low NOx modes, different fuel splits across combustion nozzles, and/or other response actions that can avoid transient instability of the gas turbine. In some embodiments, early electrical detection can be used to identify the initiation of a grid event, which can then trigger a calculation of the delta change in average frequency (e.g., using a weighted average technique of units inertia, operating point on units capability, and/or megawatt margin available) and operating machines. This calculation can be provided as a feed forward control parameter to a turbine controller to readjust the air/fuel splits and avoid unnecessary changes in operating parameters. Accordingly, embodiments may enhance the flame stability and overall gas turbine transient stability.

The systems and methods described herein facilitate ride-through, by one or more generating units coupled to the electric power system, in response to the occurrence of high rate of change of frequency events within the electric power system. More particularly, the systems and methods described herein provide a substantially real-time generating unit control scheme and enable prompt and effective corrective action for generating units to ride-through high rate of change of frequency events in electric power systems.

FIG. 2is an example process flow200for improved rate of change of frequency ride-through as may be described herein. Other embodiments may have additional, fewer, and/or different operations than those discussed with respect to the example illustrated inFIG. 2.

The process flow200may be performed, for example, by one or more controllers associated with an electric power system. For example, the process flow200may be performed by a network estimator by executing computer-executable instructions using one or more computer processors.

At block210, a grid event may be detected by a controller. For example, a controller associated with the electric power system may be configured to detect a grid event, which may be a frequency transient event. Detection may occur using an early electrical detection program or other suitable method. In some embodiments, prior to detecting the grid event, the controller may determine an estimated system inertia. In some embodiments, the controller may be configured to detect frequency drops in an electrical grid as a potential disturbance. For example, the controller may be configured to monitor one or more features or electrical properties of an electrical grid, such as a frequency, voltage, current, power, or power factor associated with the electrical grid. Based on changes in electrical grid features or electrical properties, the controller may determine whether a transient event is present on the electrical grid. For example, if one or more of frequency, voltage, current, power, or power factor associated with the electrical grid increases or decreases more than a threshold, the controller may determine that a transient event is occurring or otherwise about to occur. In one example, the controller may sense a rate of change of electrical frequency at terminals of a generator and may determine a rate of change of shaft line acceleration (where the rate of change is one of the electrical properties monitored by the controller) in order to determine whether a transient event is occurring. When a transient event is detected, the controller may send a notification of the transient event to a turbine controller. Because the controller may be coupled to the generator and the exciter, the controller may detect grid events faster and more reliably than speed measurement techniques.

At block220, a rate of change of frequency value may be determined. For example, to determine the rate of change of frequency value, the controller may perform a calculation using the following formula:

In instances where the estimated system inertia is determined prior to detecting the grid event, to determine the rate of change of frequency value, the controller may determine a weighted average of the estimated system inertia, operating point of the turbine, and available megawatt margin of the electric power system. The size of the disturbance may be a function of system inertia (H) or kinetic energy (M) and the rate of change of frequency at t=0.

In embodiments where the grid event is a frequency transient event, and the controller may be configured to determine the rate of change of frequency value within about 200 or about 300 milliseconds after the grid event is detected.

In some embodiments, the controller may be configured to determine an estimated nadir, an estimated high nadir value, and an estimated low nadir value using the rate of change of frequency value. The controller may optionally determine an updated nadir estimation after a threshold length of time has elapsed. In addition, in some embodiments, the controller may be configured to determine a feed forward controller parameter based on the rate of change of frequency value. The feed forward controller parameter may be used by other controllers to adjust operating parameters of electric system components, such as gas turbine combustor fuel flow.

At block230, a predicted post-grid event governor set point may be determined based on the rate of change of frequency value. For example, to determine the predicted post-grid event governor set point, the controller may perform a calculation using the following formula:

In some embodiments, the controller may determine an estimated magnitude of the grid event based on the rate of change of frequency value. In such instances, the predicted post-grid event governor set point may therefore be a function of droop and the estimated magnitude of the grid event.

At block240, a change to at least one turbine operating parameter based on the predicted post-grid event governor set point may be initiated. For example, the controller may be configured to initiate a change to one or more turbine operating parameter based on the predicted post-grid event governor set point. Examples of changes to turbine operating parameters may include a change to at least one of an air/fuel ratio, a dry low NOx mode, or a fuel split across combustion nozzles.

At optional block250, the controller may be configured to determine that a combustor is at a destination mode that is selected based on the change to the at least one turbine operating parameter. For example, in some embodiments, the controller may be configured to determine a destination mode for combustion using the predicted post-grid event governor set point. The destination mode may be an expected end state or settling point of a gas turbine after completion of a grid event, as discussed with respect toFIG. 5. In some embodiments, the change to the at least one turbine operating parameter may cause the turbine to switch to a transition mode at a first time and the destination mode at a second time. The destination mode may be selected from a set of available destination modes having different combustion configurations. The turbine may transition from a default mode to a transition mode, from the transition mode to a transition recovery mode, and from the transition recovery mode to the destination mode within about two seconds of the grid event. The electric power system, and more specifically the gas turbines of the electric power system, may therefore be configured to ride-through rate of change of frequency values of up to 2 Hz per second.

FIGS. 3-4are schematic diagrams illustrating various graphs related to determination of factors that are used to improve rate of change of frequency ride-through as may be described herein.

InFIG. 3, a first graph300illustrates measured frequency over time, where a rate of change310is determined at or near (e.g., just before or just after) the beginning of a grid event. The first graph300may depict a qualitative plot of frequency response without secondary control. The initial rate of change of frequency is determined by system inertia and the amount of load/generation change. Within about 5-10 seconds, the nadir or low point of the measured frequency may be detected, and the frequency may settle after about 20-30 seconds. The amount of disturbance power may be determined from the rate of change of frequency and the kinetic energy stored in the rotating masses of the synchronous area, which may be calculated using a formulas such as:

A second graph320inFIG. 3illustrates power over time, where a peak power330occurs at substantially the same time as the low frequency point, and where settling power340occurs shortly thereafter. The second graph320may depict a qualitative plot of primary control power without secondary control. The governor set point may therefore be set to match the predicted settling power340in advance of the completion of the grid event. The contribution of the i-th generator to the total settling primary control power from the disturbance power, composite droop of all generators, and the droop of the i-th generator may be determined using a formula such as:

Embodiments may therefore predict the post-disturbance governor set point to increase the rate of change of frequency capability of the system to about 2 Hertz/second. The rate of change of frequency value may be determined within 200-300 milliseconds, and the size of the power disturbance may be estimated. The settling power of the gas turbine may be estimated based on the estimated size of the power disturbance, and turbine parameters and/or a destination mode can be selected based on the estimated settling power.

FIG. 4illustrates a third graph400depicting sample system frequency during transients. An initial rate of change of frequency410may be determined at a first point in time by system inertia and the amount of load/generation change. A nadir420may be detected at a second point in time. Settling power430may be determined at a third point in time. Primary frequency control may occur between the initial rate of change of frequency410and the settling power430. The nadir420may be estimated within 300 milliseconds or less after the grid event. The estimated settling power may be determine within about 2 seconds after the grid event.

A fourth graph440inFIG. 4depicts mechanical frequency measured over time, where a rate of change of frequency changes from 0 to 300 to 500, and then stabilizes at a stable frequency442before secondary control initializes. A fifth graph450inFIG. 4depicts algorithm input data over time, where 6 samples (or another suitable amount) of mechanical frequency, power, and voltage are collected and used to measure and/or determine nadir and settling power. A sixth graph460inFIG. 4depicts algorithm output data over time, where a best guess nadir and highest/lowest nadir values are output at a first point in time462(e.g., 250 milliseconds, etc.), an updated nadir estimation is output at a second point in time464(e.g., 325 milliseconds, etc.) after the samples are collected in the fifth graph450, an expected settling power is output at a third point in time466(e.g., 500 milliseconds, etc.), and updated equivalent inertia, composite droop of all generators, and load damping constant are output at a fourth point in time468.

FIG. 5is a schematic illustration of destination strategy500determination after detection of grid frequency transient events as may be described herein. Other embodiments may have additional, fewer, and/or different components or configurations than those discussed with respect to the example illustrated inFIG. 5.

InFIG. 5, a first mode510may be an initiation mode, or a combustor mode during which a grid event occurs. Certain circuits may be fueled while others may be unfueled.

A second mode520may be a transition initiation mode, during which inner recovery may be emphasized by fueling certain circuits. For example, fuel may be biased toward a certain circuit to avoid lean blowout. Embodiments may be configured to avoid or reduce the number of times the turbine goes to a transition mode, such as the second mode520. The time to shift modes between the first mode510and the second mode520may be less than about 0.3 seconds after the grid event. To determine that the mode is to be shifted, the estimated nadir value may be used.

A third set of modes530,550,570may be various transition recovery modes with different fuel flows and configurations. The respective fuel flows may include different splits and may be determined using look-up tables.

A fourth set of modes540,560,580may be various destination modes with various fuel flows and configurations that may correspond to different settling powers. The destination mode that is selected by the controller may be locked in until the speed transient subsides. The rate of change of frequency may not be equal across the system. The shift from the transition initiation mode to the destination mode may occur within about 2 seconds after the event, thereby minimizing time at both the second mode520and any one of the third set of modes530,550,570. The estimated settling power may be used to select the appropriate destination mode.

In some embodiments, a controller associated with an electric power system may determine a destination mode for combustion using the predicted post-grid event governor set point, where the destination mode is selected from a set of available destination modes having different combustion configurations, such as the fourth set of modes540,560,580.

The above-described systems and methods thus facilitate ride-through, by one or more generating units coupled to the electric power system, in response to the occurrence of rate of change of frequency events within the electric power system. More particularly, the systems and methods described herein provide a substantially real-time generating unit control scheme and enable prompt and effective corrective action for generating units to ride-through rate of change of frequency events in electric power systems.