Methods and apparatus for use with power control systems

Abstract

A system for controlling a power conversion system is provided and comprising a power control system configured to receive an input from a tertiary control, a power control system module, and a measurement subsystem for providing an input to an independent control layer that provides signals for controlling devices having varying response capabilities at corresponding rates.

Description

METHODS AND APPARATUS FOR USE WITH POWER CONTROL SYSTEMSBACKGROUND1. Field of the Disclosure

[0001] Embodiments of the present disclosure generally relate to power control systems and, for example, to methods and apparatus for use with power control systems (PCS).2. Description of the Related Art

[0002] In a relatively new update to electrical codes (e.g., NEC 705.13) and standards (e.g., UL1741 CRD on PCS) oversubscription of conductors, busbars, and grid import / export conductors in building electrical systems is possible as long as components are monitored and participating sources (e.g., solar, batteries, etc.) are electronically controlled, e.g., using PCS. For example, with respect to complex installations (e.g., having multiple conductors and busbars), multiple limits must be coordinated and simultaneously maintained to ensure safe and compliant operation. Additionally, grid-interactive / tertiary control objectives for on-grid systems and voltage / frequency regulation objectives for off-grid systems may conflict / compete with PCS operating limits and must be properly coordinated. To meet the large set of limits and objectives for a complex installation, conventional systems can be controlled in a relatively conservative way, which can lead to less than optimal performance (e.g., overly curtail solar production, charge / discharge the battery more than necessary, etc.).

[0003] For example, conventional methods and apparatus for ensuring safe and compliant operation in complex installations can comprise 1 ) using individual rules for each limit within a complex system, 2) controlling, via multiple distributed controllers, each limit by enforcing individual rules, which requires coordination (e.g., timescale separation) between controllers and is often complex and results in a less performant (e.g., slower) result, 4) control, via a centralized controller with a complex way of prioritizing and switching between rules / limits, which can lead to instability and oscillations, overconservative / suboptimal operation, and 5) using passive or completely autonomous devices, e.g., circuit breakers to enforce limits, which can lead to poor user experience.

[0004] Alternatively, conventional methods and apparatus for ensuring safe and compliant operation in complex installations can comprise using secondary control without PCS. Such methods, however, are more complex systems with multiple PCS functions and / or with the addition of secondary control objectives, which can lead to very few competitors.

[0005] Therefore, described herein are improved methods and apparatus for use with PCS.SUMMARY

[0006] In accordance with some aspects of the present disclosure, there is provided a system for controlling a power conversion system comprising a power control system configured to receive an input from a tertiary control, a power control system module, and a measurement subsystem for providing an input to an independent control layer that provides signals for controlling devices having varying response capabilities at corresponding rates.

[0007] Various advantages, aspects, and novel features of the present disclosure may be appreciated from a review of the following detailed description of the present disclosure, along with the accompanying figures in which like reference numerals refer to like parts throughout.BRIEF DESCRIPTION OF THE DRAWINGS

[0008] So that the manner in which the above recited features of the present disclosure can be understood in detail, a more particular description of the disclosure, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only a typical embodiment of this disclosure and are therefore not to be considered limiting of its scope, for the disclosure may admit to other equally effective embodiments.

[0009] Figure 1 is a block diagram of a system for power conversion, in accordance with at least some embodiments of the present disclosure;

[0010] Figure 2 is a diagram of a control system configured for use the system of Figure 1 , in accordance with at least some embodiments of the present disclosure;

[0011] Figure 3 is a diagram of a system for power conversion, in accordance with at least some embodiments of the present disclosure;

[0012] Figure 4 is a diagram of a system for power conversion, in accordance with at least some embodiments of the present disclosure; and

[0013] Figure 5 is a diagram of PCS functions overlap, in accordance with at least some embodiments of the present disclosure.DETAILED DESCRIPTION

[0014] In accordance with the present disclosure, described herein are improved methods and apparatus for use with PCS. For example, a system for controlling a power conversion system can comprise a power control system configured to receive an input from a tertiary control, a power control system module, and a measurement subsystem for providing an input to an independent control layer that provides signals for controlling devices having varying response capabilities at corresponding rates. The methods and apparatus described herein provide optimization for improved control approaches to field issues (e.g., oscillations) and response time (e.g., switched control and decouple rulesets from controller implementation are no longer required), and are relatively easy to implement, maintain, test, and certify code.

[0015] For illustrative purposes, the methods and apparatus are described herein for use with one or more components of an energy management system.

[0016] For example, Figure 1 is a block diagram of an energy management system (e.g., power conversion system, system 100) in accordance with one or more embodiments of the present disclosure. The diagram of Figure 1 only portrays one variation of the myriad of possible system configurations. The present disclosure can function in a variety of environments and systems.

[0017] The system 100 comprises a structure 102 (e.g., a user’s structure), such as a residential home, commercial building, or separate mounting structure, having an associated DER 118 (distributed energy resource). The DER 118 is situated external to the structure 102. For example, the DER 1 18 may be located on the roof of the structure 102 or can be part of a solar farm. Alternatively, the DER 1 18 can be situated internal to the structure 102. For example, when the DER 118 is a permanent residential battery energy storage system, the DER 118 may be installed in a garage(or other suitable location inside the structure 102). The structure 102 comprises one or more loads (e.g., essential and / or non-essential loads) and / or energy storage devices 114 (e.g., portable energy systems (PES), appliances, electric hot water heaters, thermostats / detectors, boilers, electric vehicle supply equipment (EVSE), EVs, water pumps, and the like), which can be located within or outside the structure 102, and a DER controller 116, each coupled to a load center 112 (a main panel). Although the energy storage devices 114, the DER controller 116, and the load center 112 are depicted as being located within the structure 102, one or more of these may be located external to the structure 102.

[0018] The load center 112 is coupled to the DER 118 by an AC bus 104 and is further coupled, via a meter 152 and optionally a MID 150 (microgrid interconnect device), to a grid 124 (e.g., a commercial / utility power grid). The structure 102, the energy storage devices 1 14, DER controller 116, DER 118, load center 1 12, generation meter 154, the meter 152, and the MID 150 are part of a microgrid 180. It should be noted that one or more additional devices not shown in Figure 1 may be part of the microgrid 180. For example, a power meter or similar device may be coupled to the load center 112.

[0019] The DER 118 comprises at least one renewable energy source (RES) coupled to power conditioners 122 (e.g., microinverter, power converter, power conversion units (PCUs), etc.). For example, the DER 118 may comprise a plurality of RESs 120 coupled to a plurality of power conditioners 122 in a one-to-one correspondence (or two-to-one). In embodiments described herein, each RES of the plurality of RESs 120 is a photovoltaic module (PV module), although in other embodiments the plurality of RESs 120 may be any type of system for generating DC power from a renewable form of energy, such as wind, hydro, and the like. The DER 1 18 may further comprise one or more batteries (or other types of energy storage / delivery devices) coupled to the power conditioners 122 in a one-to-one correspondence, where each pair of power conditioner 122 and a DC battery 141 may be referred to as an AC battery 130.

[0020] The power conditioners 122 invert the generated DC power from the plurality of RESs 120 and / or the DC battery 141 to AC power that is grid-compliant and couple the generated AC power to the grid 124 via the load center 112. The generated AC power may be additionally or alternatively coupled via the load center 112 to the oneor more loads (e.g., EV, EVSE) and / or the energy storage devices 114. In addition, the power conditioners 122 that are coupled to the AC batteries convert AC power from the AC bus 104 to DC power for charging the AC batteries. A generation meter 154 is coupled at the output of the power conditioners 122 that are coupled to the plurality of RESs 120 in order to measure generated power.

[0021] In at least some embodiments, the power conditioners 122 may be AC-AC converters that receive AC input and convert one type of AC power to another type of AC power. Alternatively, the power conditioners 122 may be DC-DC converters that convert one type of DC power to another type of DC power. The DC-DC converters may be coupled to a main DC-AC inverter for inverting the generated DC output to an AC output.

[0022] The power conditioners 122 may communicate with one another and with the DER controller 116 using power line communication (PLC), although additionally and / or alternatively other types of wired and / or wireless communication may be used. The DER controller 116 may provide operative control of the DER 118 and / or receive data or information from the DER 118. For example, the DER controller 116 may be a Gateway / Combiner that receives data (e.g., alarms, messages, operating data, performance data, and the like) from the power conditioners 122 and communicates the data and / or other information via the communications network 126 to a cloudbased computing platform 128, which can be configured to execute one or more application software, e.g., a grid connectivity control application, to a remote device or system such as a master controller (not shown), and the like. The DER controller 116 may also send control signals to the power conditioners 122, such as control signals generated by the DER controller 116 or received from a remote device or the cloud-based computing platform 128. The DER controller 116 may be communicably coupled to the communications network 126 via wired and / or wireless techniques. For example, the DER controller 116 may be wirelessly coupled to the communications network 126 via a commercially available router. In one or more embodiments, the DER controller 116 comprises an application-specific integrated circuit (ASIC) or microprocessor along with suitable software (e.g., a grid connectivity control application) for performing one or more of the functions described herein (e.g., the methods described herein).

[0023] The generation meter 154 (which may also be referred to as a production meter) may be any suitable energy meter that measures the energy generated by the DER 118 (e.g., by the power conditioners 122 coupled to the plurality of RESs 120). The generation meter 154 measures real power flow (kWh) and, in some embodiments, reactive power flow (kVAR). The generation meter 154 may communicate the measured values to the DER controller 116, for example using PLC, othertypes of wired communications, orwireless communication. Additionally, battery charge / discharge values are received through other networking protocols from the AC battery 130 itself.

[0024] The meter 152 may be any suitable energy meter that measures the energy consumed by the microgrid 180, such as a net-metering meter, a bi-directional meter that measures energy imported from the grid 124 and well as energy exported to the grid 124, a dual meter comprising two separate meters for measuring energy ingress and egress, and the like. In some embodiments, the meter 152 comprises the MID 150 or a portion thereof. The meter 152 measures one or more of real power flow (kWh), reactive power flow (kVAR), grid frequency, and grid voltage. The meter 152 measures powerflows independently of MID state, i.e., when MID is closed and DER’s are connected to the grid and when MID is open and DER’s are isolated from the grid.

[0025] The MID 150, which may also be referred to as an island interconnect device (IID), connects / disconnects the microgrid 180 to / from the grid 124. The MID 150 comprises a disconnect component (e.g., a, relay, a contactor, or the like) for physically connecting / disconnecting the microgrid 180 to / from the grid 124. For example, the DER controller 116 receives information regarding the present state of the system from the power conditioners 122, and also receives the energy consumption values of the microgrid 180 from the meter 152 (for example via one or more of PLC, other types of wired communication, and wireless communication), and based on the received information (inputs), the DER controller 116 determines when to go on-grid or off-grid and instructs the MID 150 accordingly. In some alternative embodiments, the MID 150 comprises an ASIC or CPU, along with suitable software (e.g., an islanding module) for determining when to disconnect from / connect to the grid 124. For example, the MID 150 may monitor the grid 124 and detect a grid fluctuation, disturbance or outage and, as a result, disconnect the microgrid 180 fromthe grid 124. Once disconnected from the grid 124, the microgrid 180 can continue to generate power as an intentional island without imposing safety risks, for example on any line workers that may be working on the grid 124.

[0026] In some alternative embodiments, the MID 150 or a portion of the MID 150 is part of the DER controller 116. For example, the DER controller 116 may comprise a CPU and an islanding module for monitoring the grid 124, detecting grid failures and disturbances, determining when to disconnect from / connect to the grid 124, and driving a disconnect component accordingly, where the disconnect component may be part of the DER controller 116 or, alternatively, separate from the DER controller 116. In some embodiments, the MID 150 may communicate with the DER controller 116 (e.g., using wired techniques such as power line communications, or using wireless communication) for coordinating connection / disconnection to the grid 124.

[0027] A user 140 can use one or more computing devices, such as a mobile device 142 (e.g., a smart phone, tablet, or the like) communicably coupled by wireless means to the communications network 126. The mobile device 142 has a CPU, support circuits, and memory, and has one or more applications (e.g., a grid connectivity control application (an application 146)) installed thereon for controlling the connectivity with the grid 124 as described herein. The mobile device 142 may run on commercially available operating systems, such as IOS, ANDROID, and the like.

[0028] In order to control connectivity with the grid 124, the user 140 interacts with an icon displayed on the mobile device 142, for example a grid on-off toggle control or slide, which is referred to herein as a toggle button. The toggle button may be presented on one or more status screens pertaining to the microgrid 180, such as a live status screen (not shown), for various validations, checks and alerts. The first time the user 140 interacts with the toggle button, the user 140 is taken to a consent page, such as a grid connectivity consent page, under setting and will be allowed to interact with toggle button only after he / she gives consent.

[0029] Once consent is received, the scenarios below, listed in order of priority, will be managed differently. Based on the desired action as entered by the user 140, the corresponding instructions are communicated to the DER controller 116 via the communications network 126 using any suitable protocol, such as HTTP(S), MQTT(S), WebSockets, and the like. The DER controller 116, which may store thereceived instructions as needed, instructs the MID 150 to connect to or disconnect from the grid 124 as appropriate.

[0030] Figure 2 is a diagram of a control system 200 configured for use the system of Figure 1 , in accordance with at least some embodiments of the present disclosure. The PCS control can be performed using various approaches. For example, the PCS can be performed using a hierarchal approach (needs time scale separation), a distributed approach (local optima), and / or a centralized approach. In at least some embodiments, the PCS described herein uses the centralized approach, which provides global optima, has no time scale separation, and uses a convex problem that has a fast solution, is well within response time requirements, and leaves a buffer for measurement delay. For example, the control system 200 uses PCS and a secondary control in a single optimal solution. Unlike conventional / traditional rule-based approaches, the control system 200 uses a relatively easy approach (e.g., using less lines of code) to maintain implementation, e.g., to electronically control devices to ensure conductors, busbars, and export / import conductor limits are met.

[0031] The PCS and the secondary control can use a three-tiered hierarchical control architecture. A first tier, called the primary control (e.g., the DER controller 1 16), is an autonomous tier that uses local voltage and frequency (V / F) to balance instantaneous generation and load via a governing action, so the first tier does not rely on communications to function and is thus very fast and reliable. A second tier, called secondary control (e.g., the power conditioners 122), is managed within each area with a local area controller. When there is a load or generation change in an area, the change is picked up by the primary regulation in all areas, which causes changes to voltage, frequency, and scheduled intertie currents across the entire system (e.g., the system 100). The secondary control is responsible for correcting the change by increasing generation on the area that the load change occurred. The third tier, called tertiary control (e.g., the cloud-based computing platform 128), is also managed within each area with an area controller (e.g., a controller of a PCU of a battery, microinverter, etc.). The third tier changes the distribution of offsets between different groups of resources (e.g., devices) to minimize a cost function (for economic optimization).

[0032] The control system 200 (e.g., a single centralized optimization control system, e.g., the DER controller 116) is operable in both off-grid and on-grid modes and considers all constraints and objectives simultaneously and provides a mathematically optimal result via convex optimization (e.g., a convex problem). For example, an optimization problem solver can be used to provide optimal solutions (e.g., <= 100 ms at about 0.3-10Hz update rate) fast enough to act upon and satisfy PCS and typical secondary control timescales (e.g., typically about 1-3 s). For example, the control system 200 is configured to receive information from a tertiary control 202 (e.g., the cloud-based computing platform 128). In at least some embodiments, the tertiary control 202 provides inputs comprising prioritization / sharing between a battery and generator, force battery and generator operating region, and power export limiting (e.g., PCS-export limiting function (ELF)). In at least some embodiments, for power imports (e.g., from the grid and to facility wiring in a direction from the grid direction towards storage and loads), a PCS-import limiting function (ILF) can be used. For example, PCS-ILF provides a cost effective transition to electrification (e.g., can be especially useful with electric vehicle (EV) charging). For example, as grids, typically, cannot handle widespread uncontrolled charging of EVs, utility companies are now having to upgrade grids, which has an estimated cost of about $370 (billion) by 2050. Sites with PCS-ILF, however, can significantly reduce the need for such expenditure. PCS-import limiting function (ILF) can be used for other components of the system 100. For example, PCS-import limiting function (ILF) can be used with one or more loads of the system 100. In at least some embodiments, the PCS-import limiting function (ILF) can be used in conjunction with one or more loads or appliances, e.g., PVs, hot water heaters, HVAC, etc., which can sometimes cause one or more problems (abnormal condition) on the grid. In such embodiments, the PCS-import limiting function (ILF) can be fully automated e.g., receive inputs (data) from the one or more loads or appliances. Alternatively or additionally, the PCS-import limiting function (ILF) can be configured to receive one or more manual inputs to limit the inputs received from the one or more loads or appliances.

[0033] Additionally, a PCS limits module 204 and a measurement subsystem 206 (e.g., existing in the meter 152) provide one or more inputs to the control system 200. In at least some embodiments, the PCS limits module 204 receives systemconfiguration / temperature limits and system temperature limits (e.g., aggregators, branch circuits, resources per circuit, etc.), which is provided to the control system 200. Similarly, the measurement subsystem 206 provides all system metering information to the control system 200.

[0034] An independent control layer 208 is configured to allow control of devices (e.g., PV PCU biases, battery PCU biases, generator set point, etc.) with varying response capabilities at ideal rates of the devices (e.g., slower solar PCU control and faster battery PCU control due to different communication speeds). In at least some embodiments, the independent control layer 208 comprises a local fallback control (e.g., auxiliary / fallback problem solving) that is configured to maintain (guarantee safe) operation on occurrence of an event (e.g., failure). Examples of events can include, but are not limited to, loss of communications to PV PCUs via PLC or to battery PCUs via CAN, loss of communications to a generator, loss of communications with the generator relay, or loss of communication to the Gateway or compute platform running the centralized control algorithm.

[0035] Thus, in at least some embodiments, in parallel to the PCS convex problem computed by the control system 200, an auxiliary / fallback backup problem 210 is solved periodically by the independent control layer 208 to determine setpoints and limits that will govern system behavior upon loss of comms or device function. For example, the auxiliary / fallback backup problem 210 provides setpoints and / or limits for every location in a system (e.g., the system 100). The setpoints guarantee no safety or regulatory limits are exceeded, and the setpoints can be continuously updated on a slower timescale to account for the latest system operating configuration. Additionally, the setpoints and / or limits depend on the system configuration and dynamic inputs, such as battery SoCs, load variation, and time-of- day, etc. Moreover, in at least some embodiments, local devices (e.g., relays, GIB, PCUs, etc.) with intelligence are empowered to act upon loss of communications or device function.

[0036] For example, with respect to loss of communication to PV PCUs or battery PCUs, the PCS is configured such that each PCU will expect a set-point at least every 10s. If no setpoint is provided, each PCU will migrate to a safe set-point, and the safe set-points can be updated based on time-of-use (TOU)Zpower export limit (PEL)Zotherconstraints. In such cases, the PCS is configured to calculate (e.g., using simple scaling) the safe set-points for a predetermined time (e.g., minute or slower) and send the safe set-points to the PCUs if the safe set-points change. Additionally, with respect to loss of communication to PV PCUs or battery PCUs, in at least some embodiments, the PCS is configured such that if no communications are received for a period longer than the predetermined time, the system is moved to a safe state, which may include reconfiguring the system by opening relays on some electrical branches.

[0037] With respect to loss of communication to the generator, the PCS is configured to automatically open the generator relay. Similarly, with respect to loss of communication to the generator relay, the PCS is configured to automatically shut down the generator. With respect to loss of the centralized compute platform, the PCS is configured similarly to loss of communications, e.g., each PCU will migrate to safe set-points while a fail-over compute platform comes online.

[0038] Figure 3 is a diagram of a system 300 for power conversion (e.g., the system 100), in accordance with at least some embodiments of the present disclosure. The system 300 is a grid tied system and comprises a battery stack (e.g., the AC battery 130) connected to a combiner (e.g., the DER controller 116). In the embodiment illustrated in Figure 3, a maximum allowable current for PV can be 48A (greater or less) and for the battery can be 16A (greater or less). One or more current transformers CT can be provided for measuring the current of another circuit (e.g., to monitor high-voltage lines across the grid). The inventors have found that by using the PCS described herein with the system 100 multiple advantages, such as battery over-subscription, PV over-subscription, etc. can be provided. For example, as a Gateway / Combiner (e.g., the DER controller 116) can monitor currents at every main component of the system 300, PCS can be implemented at the Gateway level so that all the components can be protected and can be used to a maximum potential without the addition of extra hardware. In at least some embodiments, the PCS can be modeled in a tertiary control engine (TCE), e.g., the tertiary control 202 at the cloudbased computing platform 128 to generate a TCE schedule (e.g., for a home energy management system (HEMS)) that balances economic optimization with system current limits achieved by PCS. In at least some embodiments, the PCS can beconfigured to work in conjunction with the HEMS to provide import limiting to the HEMS. For example, when the HEMS comprises one or more PVs and energy storage systems, the PCS and the HEMS can be combined into one holistic system that can be configured to provide robust import limiting. In such embodiments, the PCS and the HEMS can be configured to calculate import limiting on the fly when abnormal values are detected.

[0039] For example, inclusion of power control system limits for conductors (e.g., conductor function), bus bar (e.g., bus bar function) of a main panel and combiner as input to the TCE produces economic based schedules that can be transmitted to the secondary controller (e.g., a controller of a PCU of a battery, microinverter, etc.). Additionally, in at least some embodiments, overall system objectives (e.g., cost savings or energy independence) can also be inputted to TCE and used to produce economic based schedules that can be transmitted to the secondary controller. For example, in at least some embodiments, the TCE can be used for battery setpoints vs. battery modes. In at least some embodiments, the TCE can be used for providing a user with options for lowest energy costs and / or highest energy costs, which can be controlled by AC battery discharge / charge, PV / AC battery curtailment, etc.

[0040] Table 1 shows a comparison of results without PCS to results with PCS. For example, a home-owner (e.g., having a system with the topology as shown in Figure 3) would get an energy bill of $6.17 for a week if max battery current allowed is 39.6A (TCE without PCS included). Conversely, the same homeowner would get a bill for a week as $7.94 as schedules get significantly modified by secondary controller due to the PCS topology's current limitations (mainly battery) as shown in Figure 3.. However, with the PCS included in TCE, the bill gets reduced to $6.24 as TCE generated schedules are feasible to implement by the secondary controller.

[0041] Table 1

[0042] In at least some embodiments, one or more algorithms can be used by one or more of the primary control, secondary control, and / or tertiary control and be configured to predict when PCS limits are going to be reached and by how much, which can be used in determining optimal system control. For example, the primary control, secondary control, and / or tertiary control can comprise one or more control algorithms that are configured to allow a user to decide whether to defer charging a battery, to export solar to a grid and / or to only charge a battery when the PCS limits are reached. Such embodiments can decrease waste of solar electrons, can be optimized for cost, and provide minimal impact on transformers, etc. Additionally, forecasting production and consumption allows the system 100 to forecast PCS triggers. In at least some embodiments, PCS maps can be formed and can comprise an index of public PCS zones and / or conditions. In at least some embodiments, PCS forecasting can be performed based on mass-data forecasting and consumption forecasting.

[0043] Figure 4 is a diagram of a system 400 for power conversion (e.g., the system 100), and Figure 5 is a diagram showing how multiple PCS functions overlap 500, in accordance with at least some embodiments of the present disclosure. The overlapping functions shown in Figure 5 demonstrate why a coordinated approach for implementing PCS and device control, as described herein, is required -without a coordinated approach, multiple controllers could try to implement their own PCS function, but would end up fighting for device control with other controllers. Forexample, as noted above, the methods and apparatus described herein use PCS function approach, as opposed to conventional PCS zone approaches.

[0044] For example, with respect to a conductor function 502 (CF), the PCS controls current on one or more conductors on the local electric power system (EPS) (e.g., facility wiring), requires one (1 ) measurement for each conductor, and may use the one (1 ) measurement for both 240 V lines, e.g., when there are no 120V loads or generation on A conductor. In at least some embodiments, the PCS can be configured to shut down all production of the system 100 (self-aware) if a current meets or exceeds a current on the facility wiring (e.g., abnormal condition). Alternatively, in at least some embodiments, such as when the system 100 is self-aware, and an abnormal condition (e.g., loss of communications) is detected in the system 100, the PCS can be configured to use limp-home values to limit or reduce production (to normal values) of the system 100. In at least some embodiments, such as when abnormal values of the microinverters are detected, the PCS can use the limp-home values to limit or reduce production of the microinverters (e.g., the microinverters can be configured to self-adjust).

[0045] With respect to a busbar function 504 (BF), the PCS controls total current flowing in a busbar and requires measurement of all sources of supply to the busbar (e.g., grid, ESS, PV, etc.). In at least some embodiments, the grid measures L1 and L2 since the grid currents may be unbalanced, and PV and energy storage system (ESS) may be one leg only if generation is balanced, e.g., two (2) wire 240.

[0046] With respect to export limiting function 506 (ELF), the PCS controls current on the conductors from the area EPS point of common coupling (PCC). Additionally, the export limiting function is essentially the same as conductor function 504 but adds measurements of response time. In at least some embodiments, an optional scheduling function can be added to the export limiting function (e.g, maximum 288 values for the export limit with values based on time of day, day type (e.g., weekdays, Saturday, Sunday), and month of year.)

[0047] In at least some embodiments, the PCS map can be used to maintain safety if communication or measurement is lost.

[0048] In at least some embodiments, as each conductor or busbar has a maximum current rating, a PCS maps a maximum current on a path from a microinverter on acable through one or more combiners / aggregators to the main panel and to the PCC. The microinverter can then be added to the PCS map and a maximum possible current for each conductor and busbar can be calculated. A special safety mode PMax% variable can be calculated for each microinverter at its given location in the PCS map based on a ratio of the maximum allowable current / maximum possible current. The safety mode PMax% variable can be stored in non-volatile memory in the individual microinverters. When communications or a current measurement on a conductor is lost for more than a predetermined amount of time (e.g., seconds, minutes, hours) then the microinverters revert to the safety PMax% power limit until communications / current measurement can be restored.

[0049] In at least some embodiments, a map can be created and based on size of wires / circuit breakers / DERs available / used in the system 100. For example, one or more software applications can be configured to map PCS values / settings (e.g., normal and abnormal) and propagate the PCS values / settings to the system 100. For example, an installer can manually enter the size of wires / breakers. For example, the installer can open / close (off / on) the breaker for a predetermined time (e.g., to create a fault), the PCS (cloud / tertiary) detects the faults, records the faults, and transmits the recorded faults to the one or more software applications which can then create a map. The steps for creating the map can be validated using automated and manual processes. Once the map is created, the PCS can be configured so that if a breaker malfunctions and is not capable of tripping, the PCS can be configured to trip the breaker to avoid overloading circuit.

[0050] In at least some embodiments, such as when the main panel malfunctions, which can cause a possible circuit overload, and if communications are lost, the PCS can automatically move into limp-home. Again, the limp-home values can be propagated to each microinverter to ensure that the limp-home values are propagated down to DER level.

[0051] In at least some embodiments, an installer can enter the specifications of the system 100 (e.g., normal / abnormal / limp-home values of wires, circuit breakers, conductors, busbars, combiners, etc.) into the software application during installation and the PCS values can be calculated on the fly and propagated down to the DERs of the system 100. The normal / abnormal / limp-home values can be stored in thetertiary control (e.g., cloud-based server) and used during installation (commissioning) of the system 100. In some instances, the normal / abnormal / limp-home values can change over time, e.g., if the grid changes. For example, negative information (e.g., external / telemetry data) coming from the grid can be provided from the cloud-based server to the software application during installation (or after installation) and used to provide iteratively updated / upgraded normal / abnormal / limp-home values forthe PCS.

[0052] In at least some embodiments, the PCS can be configured to control the system 100 based on one or more external inputs, e.g., temperature, irradiance, etc. For example, one or more temperature sensors and / or irradiance sensors can be provided in the combiner box and / or main panel and can be configured to provide temperature / irradiance information (e.g., via tertiary control and / or directly from the combiner box and / or main panel) to the PCS, which, in turn, can use the temperature / irradiance information as a proxy for overloading busbars, i.e. , instead of amperage rating, which can be indicative of temperature.

[0053] In at least some embodiments, the PCS can be configured to receive grouping commands from the combiner box / main panel and send the grouping commands to microinverters, e.g., if current drops / changes, so that the microinverters can selfvalidate and possibly correct installation issues (can be a combination of manual / self- automated processes).

[0054] In at least some embodiments, the PCS can be used for community management (e.g., transformer PCS).

[0055] In at least some embodiments, secondary parameters / tertiary parameters of the system can be used when determining PCS. For example, as noted above, everything connected to a node can be evaluated for cost. The tertiary control can pass along the cost information to secondary control (see table above -cost optimization, e.g., cost of copper can be used in determining cost of wire). The PCS can also be used for customer upgrade based on customer upgrade path, e.g., customer wants to reduce CO2 emission, customer wants to add an EV / EVSE, etc.

[0056] In at least some embodiments, for PV oversubscription, the PCS can be configured to determine / recommend the size of oversubscription. For example, when a user (homeowner) decides to add the PV oversubscription with the intention of having more production even when there are shading / weather / facing direction relatedrestrictions, the PCS can be configured to predict (e.g., artificial intelligence (Al)Zmachine learning (ML) model based on one or more of the above conditions) the extra microinverters that are required and recommend the extra microinverters to the user. Likewise, in at least some embodiments, the tertiary control engine is configured to store information about PCS restrictions and, based on the stored PCS restrictions, the tertiary control controls the system 100. Similarly, for battery oversubscription, the PCS can be configured to determine / recommend the size of oversubscription. For example, as the user decides to add the battery oversubscription with the intention of having longer backup hours during off-grid, the PCS can be configured to predict the extra batteries required (e.g., artificial intelligence (Al)Zmachine learning (ML) model based on prediction of off-grid and storm guard events, etc.) and can recommend the extra batteries required to the user. With respect to both PV oversubscription and battery oversubscription, the PCS can also be configured to provide (show as described above) the extra energy cost savingsZimprovement in self-consumption percentage (%) as a result of the extra invertersZbatteries, which can also provide the user with the capability of ensuring that the user is receiving optimal oversizing from the system and not spending unnecessarily.

[0057] While the foregoing is directed to embodiments of the present disclosure, other and further embodiments of the disclosure may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.

Claims

IN THE CLAIMS1 . A system for controlling a power conversion system, comprising: a power control system configured to receive an input from a tertiary control, a power control system module, and a measurement subsystem for providing an input to an independent control layer that provides signals for controlling devices having varying response capabilities at corresponding rates.

2. The system of claim 1 , wherein the tertiary control is a cloud-based computing platform.

3. The system of claim 1 , wherein the tertiary control is configured to change a distribution of offsets between different devices to minimize a cost function for economic optimization.

4. The system of claim 1 , wherein the tertiary control is configured to provide inputs comprising at least one of prioritization / sharing between a battery and generator, force battery and generator operating region, power export limiting, or power import limiting.

5. The system of claim 1 , wherein the tertiary control is configured to generate a tertiary control engine schedule for a home energy management system.

6. The system of claim 1 , wherein the tertiary control comprises one or more control algorithms that are configured to allow a user to decide whether to defer charging a battery, to export solar to a grid and / or to only charge the battery when power control system limits are reached.

7. The system of claim 1 , wherein the varying response capabilities are at least one of PV PCU biases, battery PCU biases, or a generator set point.

8. The system of claim 1 , wherein the independent control layer comprises local fallback control that is configured to maintain operation on an occurrence of an event.

9. The system as in any of claims 1 to 8, wherein the event comprises at least one of loss of communications to PV PCUs via PLC or to battery PCUs via CAN, loss of communications to a generator, loss of communications with the generator relay, or loss of communication to a gateway, or failure of a compute platform running a one or more control algorithms.

10. The system of claim 8, wherein the local fallback control is further configured to determine set-points and limits that govern system behavior upon loss of communications or device function of local devices.

11. The system of claim 10, wherein the setpoints are continuously updated to account for the latest system operating configuration.

12. The system of claim 11 , wherein the setpoints depend on at least one of system configuration or dynamic inputs.

13. The system as in any of claims 1 to 8 or 10 to 12, wherein the at least one of system configuration or dynamic inputs comprises at least one of battery SoCs, load variation, or time-of-day.

14. The system of claim 10, wherein the local devices comprises at least one of relays, GIB, or PCUs.

15. The system of claim 14, wherein when the loss of communication is to the PCUs, the local fallback control is further configured to provide a set-point for a predetermined amount of time.

16. The system of claim 15, wherein when no set-point is provided to the PCUs, the PCUs migrate to a safe set-point, and the safe set-point is updated based on at least one of time-of-use (TOU) or power export limit (PEL).

17. The system of claim 16, wherein the local fallback control is further configured to calculate the safe set-point for a predetermined time and send the safe set-point to the PCUs if the safe set-point changes.

18. The system of claim 17, wherein when no communications are received for a period longer than the predetermined time, the local fallback control is further configured to move the system to a safe state.

19. The system as in any of claims 1 to 8, 10 to 12, or 14 to 18, wherein the safe state comprises reconfiguring the system by opening relays on electrical branches.

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