DETAILED ACTION
Notice of AIA Status
The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA .
Claims 1-20 are pending and are rejected.
Response to Amendment
This Office Action is responsive to the amendment filed on 04/09/2026.
Claims 1-2, 5, 8-9, and 16-20 are amended and are being fully considered by the examiner.
Applicant's amendment necessitated the new ground(s) of rejection presented in this Office action. Accordingly, THIS ACTION IS MADE FINAL.
Response to Arguments
Applicant’s arguments with respect to claim(s) 1 and 19 have been considered but are moot because the new ground of rejection does not rely on any reference applied in the prior rejection of record for any teaching or matter specifically challenged in the argument.
Applicant responds
(a) Response to the Section 102 Rejection
Without acquiescing to the validity of the rejections, and solely in an effort to advance prosecution, Applicant has amended the claims herein to clarify the presently-claimed features. As discussed (and agreed upon) during the aforementioned interview, the claims as amended are patentable over the cited references.
Applicant respectfully submits that independent claims 1 and 19, at least as amended, are patentable over the cited references. Applicant further respectfully submits that dependent claims 2-18, and 20, at least as amended, are allowable for at least the reason that they depend on either claim 1 or 19, as well as by virtue of the patentably distinct subject matter that they recite.
(Page(s): 7)
With respect to (a) above, Examiner appreciates the interpretative description given by Applicant in response.
In response to applicant’s amendments to the claims, a new grounds of rejections in view of KIM has been introduced.
Combination of Paquin and KIM teach all the limitations of claims 1 and 19 as described in the current office action. Thus claims 1 and 19 are rejected under 35 U.S.C. 103 as being unpatentable Paquin and KIM as described in the current office action.
Applicant’s arguments are fully considered, but for the above described reasons, the arguments are moot; therefore, claims 1-20 are rejected under 35 U.S.C. 103 in view of the references as presented in the current office action.
Claim Interpretation
The following is a quotation of 35 U.S.C. 112(f):
(f) Element in Claim for a Combination. – An element in a claim for a combination may be expressed as a means or step for performing a specified function without the recital of structure, material, or acts in support thereof, and such claim shall be construed to cover the corresponding structure, material, or acts described in the specification and equivalents thereof.
The claims in this application are given their broadest reasonable interpretation using the plain meaning of the claim language in light of the specification as it would be understood by one of ordinary skill in the art. The broadest reasonable interpretation of a claim element (also commonly referred to as a claim limitation) is limited by the description in the specification when 35 U.S.C. 112(f), is invoked.
As explained in MPEP § 2181, subsection I, claim limitations that meet the following three-prong test will be interpreted under 35 U.S.C. 112(f):
(A) the claim limitation uses the term “means” or “step” or a term used as a substitute for “means” that is a generic placeholder (also called a nonce term or a non-structural term having no specific structural meaning) for performing the claimed function;
(B) the term “means” or “step” or the generic placeholder is modified by functional language, typically, but not always linked by the transition word “for” (e.g., “means for”) or another linking word or phrase, such as “configured to” or “so that”; and
(C) the term “means” or “step” or the generic placeholder is not modified by sufficient structure, material, or acts for performing the claimed function.
Use of the word “means” (or “step”) in a claim with functional language creates a rebuttable presumption that the claim limitation is to be treated in accordance with 35 U.S.C. 112(f). The presumption that the claim limitation is interpreted under 35 U.S.C. 112(f), is rebutted when the claim limitation recites sufficient structure, material, or acts to entirely perform the recited function.
Absence of the word “means” (or “step”) in a claim creates a rebuttable presumption that the claim limitation is not to be treated in accordance with 35 U.S.C. 112(f). The presumption that the claim limitation is not interpreted under 35 U.S.C. 112(f), is rebutted when the claim limitation recites function without reciting sufficient structure, material or acts to entirely perform the recited function.
Claim limitations in this application that use the word “means” (or “step”) are being interpreted under 35 U.S.C. 112(f), except as otherwise indicated in an Office action. Conversely, claim limitations in this application that do not use the word “means” (or “step”) are not being interpreted under 35 U.S.C. 112(f), except as otherwise indicated in an Office action.
This application includes one or more claim limitations that do not use the word “means,” but are nonetheless being interpreted under 35 U.S.C. 112(f), because the claim limitation(s) uses a generic placeholder that is coupled with functional language without reciting sufficient structure to perform the recited function and the generic placeholder is not preceded by a structural modifier. Such claim limitation(s) (generic placeholders) is/are:
“each module of the array of cascaded modules” in claim 1.
The claim limitations as described above uses generic placeholders for performing the claimed function such that the generic placeholders are modified by functional language as discussed below, in claim 1 -
the generic placeholder “each module of the array of cascaded modules” is modified by the functional language “is configured to output a respective voltage waveform”.
Because this/these claim limitation(s) is/are being interpreted under 35 U.S.C. 112(f), it/they is/are being interpreted to cover the corresponding structure described in the specification as performing the claimed function, and equivalents thereof.
“each module of the array of cascaded modules” being interpreted to cover the corresponding structure converter-source modules that can store energy and output the energy described in the specification ¶44: “IG. 1A is a block diagram depicts an example of a module-based energy system 100. Here, system 100 includes control system 102 communicatively coupled with N converter-source modules 108-1 through 108-N, over communication paths or links 106-1 through 106-N, respectively. Modules 108 are configured to store energy and output the energy as needed to a load 101 (or other modules 108).”
If applicant does not intend to have this/these limitation(s) interpreted under 35 U.S.C. 112(f) applicant may: (1) amend the claim limitation(s) to avoid it/them being interpreted under 35 U.S.C. 112(f) (e.g., by reciting sufficient structure to perform the claimed function); or (2) present a sufficient showing that the claim limitation(s) recite(s) sufficient structure to perform the claimed function so as to avoid it/them being interpreted under 35 U.S.C. 112(f).
Claim Rejections - 35 USC § 103
In the event the determination of the status of the application as subject to AIA 35 U.S.C. 102 and 103 (or as subject to pre-AIA 35 U.S.C. 102 and 103) is incorrect, any correction of the statutory basis (i.e., changing from AIA to pre-AIA ) for the rejection will not be considered a new ground of rejection if the prior art relied upon, and the rationale supporting the rejection, would be the same under either status.
The following is a quotation of 35 U.S.C. 103 which forms the basis for all obviousness rejections set forth in this Office action:
A patent for a claimed invention may not be obtained, notwithstanding that the claimed invention is not identically disclosed as set forth in section 102, if the differences between the claimed invention and the prior art are such that the claimed invention as a whole would have been obvious before the effective filling date of the claimed invention to a person having ordinary skill in the art to which the claimed invention pertains. Patentability shall not be negated by the manner in which the invention was made.
The text of those sections of Title 35, U.S. Code not included in this action can be found in a prior Office action.
The factual inquiries for establishing a background for determining obviousness under 35 U.S.C. 103 are summarized as follows:
Determining the scope and contents of the prior art.
Ascertaining the differences between the prior art and the claims at issue.
Resolving the level of ordinary skill in the pertinent art.
Considering objective evidence present in the application indicating obviousness or nonobviousness.
Claim(s) 1-5, 14-15, and 19-20 is/are rejected under 35 U.S.C. 103 as being unpatentable over Paquin et al. (US20140306533A1) [hereinafter Paquin] and further in view of Kim, JH et al. "An Islanding Detection Method for a Grid-Connected System Based on the Goertzel Algorithm," in IEEE Transactions on Power Electronics, Vol. 26, no. 4, April 2011, pp. 1049-1055 [online] [retrieved on 2026-06-05]. Retrieved from the Internet [hereinafter KIM].
Regarding claim 1 (amended):
Paquin discloses, An energy system configured to connect to a grid, the energy system comprising: [¶71: “the power generation and control system 300” “in FIG. 3,” “individual power generation units are grouped together into a plurality of generation sub-arrays 206 a, 206 b, 206 n (referred to collectively as power generation sub-arrays 206) which collectively provide the generation array 306. The power generation system 300 comprises a coordinated power generation group 302 that can supply power to the electrical grid 204 from the generation array 306 through a connection point 220.”];
an array of cascaded modules, wherein each module of the array of cascaded modules is configured to output a respective voltage waveform, and comprises a respective local control device; and [¶71: “in FIG. 3,” “individual power generation units are grouped together into a plurality of generation sub-arrays 206 a, 206 b, 206 n”… ¶72: “Each generation sub-array 206 a, 206 b, 206 n may be connected to a main AC bus through a local breaker 318 a, 318 b, 318 n.”…
¶62: “The individual inverters 212 of the power generation units may have one or more control parameters that can be adjusted in order to control the output of the inverter. For example, the inverter may adjust a voltage the PV panel operates at in order to adjust the AC output,”
¶73: “Each gateway sub-controller 328 a, 328 b, 328 n communicates with the inverters of an associated generation sub-array 206 a, 206 b. 206 n. For example, gateway sub-controller 328 a communicates with the individual inverters of generation sub-array 206 a, gateway sub-controller 328 b communicates with generation sub-array 328 b, etc.”
Also fig. 3, cascade modules 206 a, 206 b. 206n can output voltage wavefrom to AC bus; and respective local controllers 328 a, 328 b, 328 n];
a master control device communicably coupled to each respective local control device over a communication interface and comprising: [¶72: “The gateway controller 324,” “composed of a number of individual gateway sub-controllers 328 a, 328 b, 328 n and an aggregate controller 330.”];
one or more harmonic controllers configured to periodically cause one or more modules of the array of cascaded modules to output an increased voltage at a specified harmonic frequency by periodically sending control information to the respective local control device of the one or more modules according to a specified island detection time period, [¶73: “Each gateway sub-controller 328 a, 328 b, 328 n communicates with the inverters of an associated generation sub-array 206 a, 206 b. 206 n.”…
¶178: “gateway controller controls the size of individual perturbations from each inverter to produce an array perturbation of size sufficient to detect an island” “all inverters produce a perturbation signal. For example, if the impedance measurement method is used and a perturbation current IPERTURB is required for reliable island detection then gateway controller directs each inverter to inject a current of IPERTURB/N at a harmonic to the grid frequency. All inverters in the array continuously measure VPERTURB, the resultant voltage at the harmonic frequency. If VPERTURB is above a threshold it indicates formation of an island.”…
¶180: “the gateway controller rotates the perturbation operation through all inverters on a time scale sufficient to meet grid code requirements for island detection. For example, if an island must be detected within two seconds of formation then the perturbation operation is controller such that all inverters produce a perturbation at least once every two seconds.”
Examiner notes that, Paquin teaches, harmonic controller periodically controls array of inverters (modules) to inject array perturbation (output an increased voltage at a specified harmonic frequency) during period of islanding detection];
wherein the control information comprises or is representative of an adjusted harmonic voltage; [¶178: “All inverters in the array continuously measure VPERTURB, the resultant voltage at the harmonic frequency. If VPERTURB is above a threshold it indicates formation of an island.”… ¶180: “the gateway controller rotates the perturbation operation through all inverters on a time scale sufficient to meet grid code requirements for island detection. For example, if an island must be detected within two seconds of formation then the perturbation operation is controller such that all inverters produce a perturbation at least once every two seconds.”];
an islanding detector configured to detect, based on an output impedance of the…modules…, when the array of cascaded modules is in an island condition. [¶176: “If an island has formed however, the distributed generator will be able to produce measureable perturbations, indicating that an island has formed.”… ¶177: “Active island detection techniques are well known and include Impedance Measurement (IM),” “the combined inverters of the generation array may be able to perturb the grid enough to detect an island, if the inverters in the array can be coordinated to produce a single synchronized perturbation.” “impedance measurement anti-islanding methods rely on the injection of a small current at a harmonic of the grid frequency to determine the grid impedance.”… ¶178: “gateway controller controls the size of individual perturbations from each inverter to produce an array perturbation of size sufficient to detect an island” “all inverters produce a perturbation signal. For example, if the impedance measurement method is used and a perturbation current IPERTURB is required for reliable island detection then gateway controller directs each inverter to inject a current of IPERTURB/N at a harmonic to the grid frequency. All inverters in the array continuously measure VPERTURB, the resultant voltage at the harmonic frequency. If VPERTURB is above a threshold it indicates formation of an island.”… ¶180: “if an island must be detected within two seconds of formation then the perturbation operation is controller such that all inverters produce a perturbation at least once every two seconds.”
Examiner notes that, Paquin teaches, controller controls inverters to inject perturbation signal and uses impedance measurement to detect islanding condition].
KIM discloses, detect, based on an output impedance of the array of cascaded modules at the specified harmonic frequency, when the array of cascaded modules is in an island condition. [Page 1050, column 2, under Section II: Proposed Islanding Detection Method: “The dc/ac stage controls the dc-link voltage and injects the generated power into the grid… The I∗inv is added using a ninth harmonic component for the proposed AIM. The Goertzel algorithm then monitors the Vgrid(9th)….
The VPCC of the hth harmonic component (VPCC(h)) when the grid is connected condition is
PNG
media_image1.png
77
541
media_image1.png
Greyscale
When an islanding condition occurs, the ZPCC becomes larger than when the grid is connected because the ZPCC equals the Zload.
The VPCC(h) at an islanding condition is VPCC(h) | Islanding=Zload Iinv(h). (2)”
Examiner notes that, KIM teaches detecting island condition array of modules, based on the output impedance Z at a specified harmonic frequency (hth harmonic)].
Therefore, it would have been obvious to one of ordinary skill in the art before the filling date of the claimed invention to have combined the capability of detecting, based on an output impedance of the array of cascaded modules at the specified harmonic frequency, when the array of cascaded modules is in an island condition in order to achieve simple and fast islanding detection with no detrimental effect on the grid power quality due to harmonic injection taught by KIM with the system taught by Paquin as discussed above in order to have reasonable expectation of success such as order to achieve simple and fast islanding detection with no detrimental effect on the grid power quality due to harmonic injection [KIM page 1054, column 2, section V, conclusion: “this method does not have the NDZ (nondetection zone) and detrimental effect on the grid power quality due to harmonic injection… the computation of the AIM is simple and fast ”].
Regarding claim 2 (amended):
Paquin and KIM disclose, The energy system of claim 1, and
Paquin further discloses, further comprising an impedance measurement circuit configured to: measure the output impedance of the array of cascade modules at the specified harmonic frequency;
periodically provide, to the islanding detector and based on the specified island detection time period, data indicating the output impedance of the array of cascade modules. [¶177: “Active island detection techniques are well known and include Impedance Measurement (IM),” “the combined inverters of the generation array may be able to perturb the grid enough to detect an island, if the inverters in the array can be coordinated to produce a single synchronized perturbation.” “impedance measurement anti-islanding methods rely on the injection of a small current at a harmonic of the grid frequency to determine the grid impedance.”… ¶178: “gateway controller controls the size of individual perturbations from each inverter to produce an array perturbation of size sufficient to detect an island” “all inverters produce a perturbation signal. For example, if the impedance measurement method is used and a perturbation current IPERTURB is required for reliable island detection then gateway controller directs each inverter to inject a current of IPERTURB/N at a harmonic to the grid frequency. All inverters in the array continuously measure VPERTURB, the resultant voltage at the harmonic frequency. If VPERTURB is above a threshold it indicates formation of an island.”… ¶180: “if an island must be detected within two seconds of formation then the perturbation operation is controller such that all inverters produce a perturbation at least once every two seconds.”].
Regarding claim 3:
Paquin and KIM disclose, The energy system of claim 1, and
Paquin further discloses, wherein the master control device is configured to:
in response to the islanding detector detecting that the array of cascaded modules is in the island condition: disconnect the array of cascaded modules from the grid; [¶178: “if the impedance measurement method is used and a perturbation current IPERTURB is required for reliable island detection then gateway controller directs each inverter to inject a current of IPERTURB/N at a harmonic to the grid frequency. All inverters in the array continuously measure VPERTURB, the resultant voltage at the harmonic frequency. If VPERTURB is above a threshold it indicates formation of an island.”… ¶182: “The gateway controller then determines whether to disconnect inverters from the grid”… ¶183: “After a distributed generator disconnects from the grid due to detection of an island there is normally a mandatory waiting period between the redetection of the grid by the distributed generator and reconnection of the distributed generator.”… ¶59: “Inverters of such power generation units may monitor one or more characteristics, such as voltage or frequency, of the grid, and if the characteristics fall outside of a threshold, the inverter may simply disconnect from the grid.”];
obtain data indicating a last normal voltage frequency and voltage phase of the grid; and send instructions to a harmonic controller of the one or more harmonic controllers to control the respective voltage waveform output to a load by each module based on the last normal voltage phase and the last normal voltage frequency. [¶96: “The monitoring functionality 1148 may comprise grid monitoring functionality 1150 for monitoring characteristics, such as voltage, frequency and phase of the electrical grid,”… ¶64: “the monitoring functionality 222 may monitor the voltage and/or of the electrical grid frequency. The monitoring functionality 222 may also measure or determine the phase difference between the grid voltage and the injected current.”… ¶145: “FIG. 15 is a flowchart illustrating an grid stability control method using a gateway controller.” “measurement of a parameter “ƒ” of the electrical grid (1502). A determination is made as to whether the parameter exceeds a threshold value ƒTH (1504). If the parameter does exceed the threshold value (Yes at 1504) an adjustment of the array power may be made. The adjustment reduces the output power POUT of panel array by an amount POUT*KΔƒ” “Once the array power output is determined, the inverters can be controlled as described above in order to provide the desired output power.”];
Regarding claim 4:
Paquin and KIM disclose, The energy system of claim 3, and
Paquin further discloses, wherein the master control device is configured to:
receive data indicating that the grid has returned to normal operation and, in response:
obtain data indicating a present voltage phase and present voltage frequency of the grid; reconnect the array of cascaded modules to the grid; [¶183: “All inverters will therefore attempt to reconnect to the grid simultaneously after the end of an islanding event.”… ¶184: “if gateway controller sequentially issues commands to inverters to either reconnect or begin power injection at a substantially constant rate which results in a power output increase which does not exceed the maximum specified by the grid code. For instance, if the grid code specifies a maximum output power increase of PMAX watts/minute and the nominal output power of an individual array inverter is PO watts then the gateway controller would issue commands to reconnect or begin power injection at a maximum rate of PMAX/PO commands per minute.”… ¶147: “The grid parameter ƒ may be continuously monitored and the output power of generation array continually adjusted by the gateway controller. This ensures that only the required power reduction occurs.”… ¶64: “the monitoring functionality 222 may monitor the voltage and/or of the electrical grid frequency. The monitoring functionality 222 may also measure or determine the phase difference between the grid voltage and the injected current.”];
send instructions to the one or more harmonic controllers to control the respective voltage waveform provided to the load by the array of cascaded modules. [¶183: “All inverters will therefore attempt to reconnect to the grid simultaneously after the end of an islanding event.”… ¶184: “if gateway controller sequentially issues commands to inverters to either reconnect or begin power injection at a substantially constant rate which results in a power output increase which does not exceed the maximum specified by the grid code. For instance, if the grid code specifies a maximum output power increase of PMAX watts/minute and the nominal output power of an individual array inverter is PO watts then the gateway controller would issue commands to reconnect or begin power injection at a maximum rate of PMAX/PO commands per minute.”… ¶145: “A determination is made as to whether the parameter exceeds a threshold value ƒTH (1504). If the parameter does exceed the threshold value (Yes at 1504) an adjustment of the array power may be made. The adjustment reduces the output power POUT of panel array by an amount” “Once the array power output is determined, the inverters can be controlled as described above in order to provide the desired output power.”… ¶147: “The grid parameter ƒ may be continuously monitored and the output power of generation array continually adjusted by the gateway controller. This ensures that only the required power reduction occurs.”… ¶64: “the monitoring functionality 222 may monitor the voltage and/or of the electrical grid frequency. The monitoring functionality 222 may also measure or determine the phase difference between the grid voltage and the injected current.”].
Regarding claim 5 (amended):
Paquin and KIM disclose, The energy system of claim 1, and
Paquin further discloses, wherein the master control device is configured to send, to each local control device over the communication interface, the control information that instructs the respective local control device to operate switch circuitry to output the respective voltage waveform. [¶68: “The desired output current can be set at the gateway controller 224, which determines the output of individual inverters required to supply the desired output current. The gateway controller 224 may issue commands to one or more of the individual inverters 212 in order to adjust the power output from the inverters, and so lower the combined output power.”… ¶73: “the aggregate controller 330 might instruct each of the gateway sub-controllers 228 a, 228 b, 228 n to reduce output power from the associated generation sub-array by a specific amount. The gateway sub-controllers 228 a, 228 b, 228 n may in turn instruct specific inverters in the associate generation sub-arrays to reduce their power to meet this power reduction request.”].
Regarding claim 14:
Paquin and KIM disclose, The energy system of claim 1, and
Paquin further discloses, wherein each harmonic controller of the one or more harmonic controllers comprises a multi- loop controller comprising an outer voltage control loop and an inner current control loop. [¶68: “The desired output current can be set at the gateway controller 224, which determines the output of individual inverters required to supply the desired output current. The gateway controller 224 may issue commands to one or more of the individual inverters 212 in order to adjust the power output from the inverters, and so lower the combined output power.”… ¶67: “The gateway controller 224 may issue a variety of remote control commands to individual inverters 212 over the communication links. The individual inverters may receive and process the remote control commands to control an output characteristic of the respective inverter. The remote control commands may include, for example, commands to disconnect from local busses 214, reconnect to local busses 214, stop or start injecting power into the local busses 214, vary their output power, vary their output current phase angle.”].
Regarding claim 15:
Paquin and KIM disclose, The energy system of claim 1, and
Paquin further discloses, wherein the islanding detector is configured to obtain one or more baseline impedance measurements of the energy system at the specified harmonic frequency. [¶178: “all inverters produce a perturbation signal. For example, if the impedance measurement method is used and a perturbation current IPERTURB is required for reliable island detection then gateway controller directs each inverter to inject a current of IPERTURB/N at a harmonic to the grid frequency. All inverters in the array continuously measure VPERTURB, the resultant voltage at the harmonic frequency. If VPERTURB is above a threshold it indicates formation of an island.”].
Regarding claim 19:
Paquin discloses, An energy system configured to connect to a power grid, the energy system comprising: [¶71: “the power generation and control system 300” “in FIG. 3,” “individual power generation units are grouped together into a plurality of generation sub-arrays 206 a, 206 b, 206 n (referred to collectively as power generation sub-arrays 206) which collectively provide the generation array 306. The power generation system 300 comprises a coordinated power generation group 302 that can supply power to the electrical grid 204 from the generation array 306 through a connection point 220.”];
one or more modules that each output a respective voltage waveform to a load; [¶71: “the power generation and control system 300” “in FIG. 3,” “individual power generation units are grouped together into a plurality of generation sub-arrays 206 a, 206 b, 206 n”… ¶72: “Each generation sub-array 206 a, 206 b, 206 n may be connected to a main AC bus through a local breaker 318 a, 318 b, 318 n. The gateway controller 324,” “may be composed of a number of individual gateway sub-controllers 328 a, 328 b, 328 n and an aggregate controller 330.”… ¶73: “Each gateway sub-controller 328 a, 328 b, 328 n communicates with the inverters of an associated generation sub-array 206 a, 206 b. 206 n. For example, gateway sub-controller 328 a communicates with the individual inverters of generation sub-array 206 a, gateway sub-controller 328 b communicates with generation sub-array 328 b, etc.”];
a controller configured to periodically cause at least a portion of the one or more modules to output an increased voltage at a specified harmonic frequency by periodically sending control information to the portion of the one or more modules according to a specified island detection time period [¶73: “Each gateway sub-controller 328 a, 328 b, 328 n communicates with the inverters of an associated generation sub-array 206 a, 206 b. 206 n.”…
¶178: “gateway controller controls the size of individual perturbations from each inverter to produce an array perturbation of size sufficient to detect an island” “all inverters produce a perturbation signal. For example, if the impedance measurement method is used and a perturbation current IPERTURB is required for reliable island detection then gateway controller directs each inverter to inject a current of IPERTURB/N at a harmonic to the grid frequency. All inverters in the array continuously measure VPERTURB, the resultant voltage at the harmonic frequency. If VPERTURB is above a threshold it indicates formation of an island.”…
¶180: “the gateway controller rotates the perturbation operation through all inverters on a time scale sufficient to meet grid code requirements for island detection. For example, if an island must be detected within two seconds of formation then the perturbation operation is controller such that all inverters produce a perturbation at least once every two seconds.”
Examiner notes that, Paquin teaches, harmonic controller periodically controls array of inverters (modules) to inject array perturbation (output an increased voltage at a specified harmonic frequency) during period of islanding detection];
wherein the control information comprises or is representative of an adjusted harmonic voltage; [¶178: “All inverters in the array continuously measure VPERTURB, the resultant voltage at the harmonic frequency. If VPERTURB is above a threshold it indicates formation of an island.”… ¶180: “the gateway controller rotates the perturbation operation through all inverters on a time scale sufficient to meet grid code requirements for island detection. For example, if an island must be detected within two seconds of formation then the perturbation operation is controller such that all inverters produce a perturbation at least once every two seconds.”];
an islanding detector configured to detect, based on an impedance of the one or more modules…, when the one or more modules are in an island condition. [¶176: “If an island has formed however, the distributed generator will be able to produce measureable perturbations, indicating that an island has formed.”… ¶177: “Active island detection techniques are well known and include Impedance Measurement (IM),” “the combined inverters of the generation array may be able to perturb the grid enough to detect an island, if the inverters in the array can be coordinated to produce a single synchronized perturbation.” “impedance measurement anti-islanding methods rely on the injection of a small current at a harmonic of the grid frequency to determine the grid impedance.”… ¶178: “gateway controller controls the size of individual perturbations from each inverter to produce an array perturbation of size sufficient to detect an island” “all inverters produce a perturbation signal. For example, if the impedance measurement method is used and a perturbation current IPERTURB is required for reliable island detection then gateway controller directs each inverter to inject a current of IPERTURB/N at a harmonic to the grid frequency. All inverters in the array continuously measure VPERTURB, the resultant voltage at the harmonic frequency. If VPERTURB is above a threshold it indicates formation of an island.”… ¶180: “if an island must be detected within two seconds of formation then the perturbation operation is controller such that all inverters produce a perturbation at least once every two seconds.”
Examiner notes that, Paquin teaches, controller controls inverters to inject perturbation signal and uses impedance measurement to detect islanding condition].
KIM discloses, an islanding detector configured to detect, based on an impedance of the one or more modules at the specified harmonic frequency, when the one or more modules are in an island condition. [Page 1050, column 2, under Section II: Proposed Islanding Detection Method: “The dc/ac stage controls the dc-link voltage and injects the generated power into the grid… The I∗inv is added using a ninth harmonic component for the proposed AIM. The Goertzel algorithm then monitors the Vgrid(9th)….
The VPCC of the hth harmonic component (VPCC(h)) when the grid is connected condition is
PNG
media_image1.png
77
541
media_image1.png
Greyscale
When an islanding condition occurs, the ZPCC becomes larger than when the grid is connected because the ZPCC equals the Zload.
The VPCC(h) at an islanding condition is VPCC(h) | Islanding=Zload Iinv(h). (2)”
Examiner notes that, KIM teaches detecting island condition array of modules, based on the output impedance Z at a specified harmonic frequency (hth harmonic)].
Therefore, it would have been obvious to one of ordinary skill in the art before the filling date of the claimed invention to have combined the capability of detecting, based on an output impedance of the array of cascaded modules at the specified harmonic frequency, when the array of cascaded modules is in an island condition in order to achieve simple and fast islanding detection with no detrimental effect on the grid power quality due to harmonic injection taught by KIM with the system taught by Paquin as discussed above in order to have reasonable expectation of success such as order to achieve simple and fast islanding detection with no detrimental effect on the grid power quality due to harmonic injection [KIM page 1054, column 2, section V, conclusion: “this method does not have the NDZ (nondetection zone) and detrimental effect on the grid power quality due to harmonic injection… the computation of the AIM is simple and fast ”].
Regarding claim 20 (amended):
Paquin and KIM disclose, The energy system of claim 19, and
Paquin further discloses, further comprising a master control device that includes the controller and the islanding detector, [¶72: “The gateway controller 324,” “composed of a number of individual gateway sub-controllers 328 a, 328 b, 328 n and an aggregate controller 330.”… ¶178: “gateway controller controls the size of individual perturbations from each inverter to produce an array perturbation of size sufficient to detect an island” “all inverters produce a perturbation signal. For example, if the impedance measurement method is used and a perturbation current IPERTURB is required for reliable island detection then gateway controller directs each inverter to inject a current of IPERTURB/N at a harmonic to the grid frequency. All inverters in the array continuously measure VPERTURB, the resultant voltage at the harmonic frequency. If VPERTURB is above a threshold it indicates formation of an island.”];
wherein each module of the one or more modules comprises a respective local control device configured to operate switch circuitry based on the control information received from the master control device. [¶72: “The gateway controller 324,” “composed of a number of individual gateway sub-controllers 328 a, 328 b, 328 n and an aggregate controller 330.”… ¶73: “the aggregate controller 330 might instruct each of the gateway sub-controllers 228 a, 228 b, 228 n to reduce output power from the associated generation sub-array by a specific amount. The gateway sub-controllers 228 a, 228 b, 228 n may in turn instruct specific inverters in the associate generation sub-arrays to reduce their power to meet this power reduction request. The individual generation sub-arrays 206 a, 206 b, 206 n may be connected to the connection point 220, which may include monitoring 222 functionality as depicted, through respective breakers 318 a, 318 b, 318 n.”].
Claim(s) 6-13 and 16 is/are rejected under 35 U.S.C. 103 as being unpatentable over Paquin and KIM and further in view of Yu et al. (US20220006298A1) [hereinafter YU].
Regarding claim 6 (amended):
Paquin and KIM disclose, The mover system of claim 1, but they do not explicitly disclose, and
YU discloses, wherein the control information sent to each local control device comprises a normalized reference signal for each module of the array of cascaded modules and, for at least one module, a modulation index used by the at least one module to scale the normalized reference signal. [¶16: “determining, based on a voltage of the alternating current electricity output by the alternating current port, a harmonic voltage amplitude of the alternating current electricity output by the alternating current port; and determining, based on the harmonic voltage amplitude, the harmonic voltage amplitude growth rate of the alternating current electricity output by the alternating current port.”… ¶59: “The harmonic amplitude growth rate is a ratio of a harmonic amplitude growth in a period of time to a harmonic amplitude at a start time point of the period of time. The harmonic amplitude growth rate of the alternating current electricity output by the alternating current port of the grid-tied inverter may be a harmonic voltage amplitude growth rate, a harmonic impedance amplitude growth rate, or the like. A harmonic voltage amplitude is a maximum absolute value that appears in a harmonic voltage in one cycle.” “A harmonic in the alternating current electricity output by the alternating current port may be a kth harmonic, and k is a harmonic order of the harmonic, namely, a ratio of a harmonic frequency to a fundamental frequency. For example, k may be preset, and may be greater than 1 and less than 40. Certainly, k may alternatively be another value greater than 1. This embodiment of this application sets no limitation thereto.”… ¶61: “the harmonic output by the alternating current port of the grid-tied inverter flows into the power grid.”].
Therefore, it would have been obvious to one of ordinary skill in the art before the filling date of the claimed invention to have combined the control information sent to each local control device comprises a normalized reference signal for each module of the array of cascaded modules and, for at least one module, a modulation index used by the at least one module to scale the normalized reference signal in order to quickly and accurately detect islanding, with additional benefit of avoiding false detection of caused by a fluctuation of the power grid taught by YU with the system taught by Paquin and KIM as discussed above in order to have reasonable expectation of success such as to quickly and accurately detect islanding, with additional benefit of avoiding false detection of caused by a fluctuation of the power grid [YU ¶35: “In this way, whether islanding occurs can be accurately detected.” “false detection caused by a fluctuation of the power grid can be avoided. When islanding occurs, it can be quickly detected, and a detection time is relatively short.”].
Regarding claim 7:
Paquin, KIM and YU disclose, The energy system of claim 6, and
YU further discloses, wherein the normalized reference signal represents (i) a fundamental frequency and (ii) a voltage at a specified harmonic frequency. [¶59: “A harmonic voltage amplitude is a maximum absolute value that appears in a harmonic voltage in one cycle.” “A harmonic in the alternating current electricity output by the alternating current port may be a kth harmonic, and k is a harmonic order of the harmonic, namely, a ratio of a harmonic frequency to a fundamental frequency. For example, k may be preset, and may be greater than 1 and less than 40. Certainly, k may alternatively be another value greater than 1. This embodiment of this application sets no limitation thereto.”… ¶61: “the harmonic output by the alternating current port of the grid-tied inverter flows into the power grid.”].
Regarding claim 8 (amended):
Paquin, KIM and YU disclose, The energy system of claim 7, and
YU further discloses, wherein (i) the fundamental frequency and (ii) the voltage at the specified harmonic frequency are measured concurrently. [¶107: “FIG. 6, a frequency ƒ of a voltage U of the alternating current electricity output by the alternating current port of the grid-tied inverter may be detected, and a frequency growth rate Δƒ of the alternating current electricity output by the alternating current port is determined based on the detected frequency ƒ. In addition, the voltage U and a current I of the alternating current electricity output by the alternating current port may be detected in real time; a harmonic impedance amplitude Zg,k of the alternating current electricity output by the alternating current port is determined based on the detected voltage U and current I; accordingly, a harmonic impedance amplitude growth rate ΔZg,k of the alternating current electricity output by the alternating current port is determined;”].
Regarding claim 9 (amended):
Paquin, KIM and YU disclose, The energy system of claim 8, and
Paquin further discloses, the master control device is configured to periodically send the control information to each local control device such that the control information is sent to each local control device multiple times during each specified island detection time period, ¶180: “the gateway controller rotates the perturbation operation through all inverters on a time scale sufficient to meet grid code requirements for island detection. For example, if an island must be detected within two seconds of formation then the perturbation operation is controller such that all inverters produce a perturbation at least once every two seconds.”], and
wherein
for a first sub-period of each recurring time period, the control information comprises a normalized reference signal with a harmonic voltage at a first magnitude; and [¶178: “All inverters in the array continuously measure VPERTURB, the resultant voltage at the harmonic frequency. If VPERTURB is above a threshold it indicates formation of an island.”… ¶180: “the gateway controller rotates the perturbation operation through all inverters on a time scale sufficient to meet grid code requirements for island detection. For example, if an island must be detected within two seconds of formation then the perturbation operation is controller such that all inverters produce a perturbation at least once every two seconds.”];
for a second sub-period of each recurring time period, the control information comprises the normalized reference signal with the harmonic voltage adjusted at a second magnitude. [¶99: “the output characteristic that is adjusted may be the combined output power provided to the electrical grid from the plurality of individual inverters. The gateway controller may determine the power output required to be provided by each individual inverter in order to supply the desired output power to the electrical grid, and then set the control parameters of the individual inverters in order to provide the desired combined output power.”… ¶121: “the output power of inverters with powers lower than the common value are increased.”];
Regarding claim 10:
Paquin, and KIM disclose, The energy system of claim 1, and
YU further discloses, the one or more harmonic controllers comprise a fundamental frequency reference signal generator configured to generate a voltage reference signal at a fundamental frequency. [¶16: “determining, based on a voltage of the alternating current electricity output by the alternating current port, a harmonic voltage amplitude of the alternating current electricity output by the alternating current port;”… ¶59: “A harmonic voltage amplitude is a maximum absolute value that appears in a harmonic voltage in one cycle.”].
Regarding claim 11:
Paquin, KIM and YU disclose, The energy system of claim 10, and
YU further discloses, wherein the one or more harmonic controllers comprise one or more harmonic frequency reference signal generators each configured to generate a harmonic frequency voltage reference signal at a respective harmonic frequency relative to the fundamental frequency. [¶16: “determining, based on a voltage of the alternating current electricity output by the alternating current port, a harmonic voltage amplitude of the alternating current electricity output by the alternating current port; and determining, based on the harmonic voltage amplitude, the harmonic voltage amplitude growth rate of the alternating current electricity output by the alternating current port.”… ¶59: “A harmonic voltage amplitude is a maximum absolute value that appears in a harmonic voltage in one cycle.” “A harmonic in the alternating current electricity output by the alternating current port may be a kth harmonic, and k is a harmonic order of the harmonic, namely, a ratio of a harmonic frequency to a fundamental frequency. For example, k may be preset, and may be greater than 1 and less than 40. Certainly, k may alternatively be another value greater than 1. This embodiment of this application sets no limitation thereto.”].
Regarding claim 12:
Paquin, KIM and YU disclose, The energy system of claim 11, and
YU further discloses, wherein the master controller comprises a signal combiner that generates the control information by combining the fundamental frequency voltage reference signal with the harmonic frequency voltage reference signal of at least one of the one or more harmonic frequency reference signal generators. [¶16: “a harmonic voltage amplitude of the alternating current electricity output by the alternating current port; and determining, based on the harmonic voltage amplitude, the harmonic voltage amplitude growth rate of the alternating current electricity output by the alternating current port.”… ¶21: “a harmonic voltage amplitude of the alternating current electricity output by the alternating current port; and determining, based on the harmonic voltage amplitude, the harmonic voltage amplitude growth rate of the alternating current electricity output by the alternating current port.”… ¶59: “A harmonic voltage amplitude is a maximum absolute value that appears in a harmonic voltage in one cycle.” “A harmonic in the alternating current electricity output by the alternating current port may be a kth harmonic, and k is a harmonic order of the harmonic, namely, a ratio of a harmonic frequency to a fundamental frequency. For example, k may be preset, and may be greater than 1 and less than 40. Certainly, k may alternatively be another value greater than 1. This embodiment of this application sets no limitation thereto.”].
Regarding claim 13:
Paquin, KIM and YU disclose, The energy system of claim 12, and
Paquin further discloses, wherein the one or more harmonic frequency reference signal generators comprise a plurality of harmonic frequency reference signal generators,
the master controller further comprising a primary controller configured to select between the plurality of harmonic frequency reference signal generators for generating the harmonic frequency voltage reference signal [¶178: “gateway controller is in communication with inverters and is aware of the number of inverters (N) in array and their perturbation method.” “if the impedance measurement method is used and a perturbation current IPERTURB is required for reliable island detection then gateway controller directs each inverter to inject a current of IPERTURB/N at a harmonic to the grid frequency. All inverters in the array continuously measure VPERTURB, the resultant voltage at the harmonic frequency. If VPERTURB is above a threshold it indicates formation of an island.”], but doesn’t explicitly disclose, and
YU further discloses, generating the harmonic frequency voltage reference signal that is combined with the fundamental frequency voltage reference signal. [¶16: “a harmonic voltage amplitude of the alternating current electricity output by the alternating current port; and determining, based on the harmonic voltage amplitude, the harmonic voltage amplitude growth rate of the alternating current electricity output by the alternating current port.”… ¶21: “a harmonic voltage amplitude of the alternating current electricity output by the alternating current port; and determining, based on the harmonic voltage amplitude, the harmonic voltage amplitude growth rate of the alternating current electricity output by the alternating current port.”… ¶59: “A harmonic voltage amplitude is a maximum absolute value that appears in a harmonic voltage in one cycle.” “A harmonic in the alternating current electricity output by the alternating current port may be a kth harmonic, and k is a harmonic order of the harmonic, namely, a ratio of a harmonic frequency to a fundamental frequency. For example, k may be preset, and may be greater than 1 and less than 40. Certainly, k may alternatively be another value greater than 1. This embodiment of this application sets no limitation thereto.”].
Regarding claim 16 (amended):
Paquin, KIM and YU disclose, The energy system of claim 15, and
Paquin further discloses, wherein the islanding detector is configured to detect when the array of cascaded modules is in the island condition [¶178: “gateway controller is in communication with inverters and is aware of the number of inverters (N) in array and their perturbation method.” “if the impedance measurement method is used and a perturbation current IPERTURB is required for reliable island detection then gateway controller directs each inverter to inject a current of IPERTURB/N at a harmonic to the grid frequency. All inverters in the array continuously measure VPERTURB, the resultant voltage at the harmonic frequency. If VPERTURB is above a threshold it indicates formation of an island.”], but doesn’t explicitly disclose, and
YU further discloses, island condition based on the output impedance of the array of cascaded modules, the one or more baseline impedance measurements, and an impedance threshold [¶17: “dividing the harmonic voltage amplitude by the harmonic current amplitude to obtain a harmonic impedance amplitude of the alternating current electricity output by the alternating current port; and determining, based on the harmonic impedance amplitude, the harmonic impedance amplitude growth rate of the alternating current electricity output by the alternating current port.”… ¶70: “Step 302: Determine an islanding disturbance coefficient corresponding to the harmonic amplitude growth rate of the alternating current electricity output by the alternating current port.”].
Claim(s) 17-18 is/are rejected under 35 U.S.C. 103 as being unpatentable over Paquin and KIM and further in view of Lucas et al. (US20250038542A1) [hereinafter Lucas].
Regarding claim 17 (amended):
Paquin and KIM disclose, The energy system of claim 1, but doesn’t explicitly disclose, and
Lucas further discloses wherein the islanding detector comprises a filter configured to remove signals from the output impedance of the array of cascaded modules that do not correspond to the modules. [¶133: “the Park Transforms 38102, 38202, and 38302 may output the d and q components of the 3rd, 5th, and 7th harmonic currents Ia3rd, Iq3rd, Iq5th, Iq5th, Id7th, and Iq7th into low pass filters 38106, 38104, 38206, 38204, 38306, and 38304 respectively to filter out high frequency components in the waveforms. In some embodiments, the low pass filters 38106, 38104, 38206, 38204, 38306, and 38304 may output the filtered current waveforms to PI controllers 38110, 38108, 38210, 38208, 38310,”… ¶304: “detect islanding in any number of ways known to one skilled in the art. In some embodiments, a power system may detect islanding by intentionally creating a fundamentally invalid condition within the island and then detecting that condition.”].
Therefore, it would have been obvious to one of ordinary skill in the art before the filling date of the claimed invention to have combined the islanding detector comprises a filter configured to remove signals from the output impedance of the modules that do not correspond to the modules in order to preventing/mitigating/reducing damage to the power system as a result of unanticipated amounts of current being applied to one or more component of the power system by using the filter to filter unwanted signal taught by Lucas with the system taught by Paquin and KIM as discussed above in order to have reasonable expectation of success such as to preventing/mitigating/reducing damage to the power system as a result of unanticipated amounts of current being applied to one or more component of the power system by using the filter to filter unwanted signal [Lucas ¶293: “preventing/mitigating/reducing damage to the power system as a result of unanticipated amounts of current being applied to one or more component of the power system”].
Regarding claim 18 (amended):
Paquin, KIM and Lucas disclose, The energy system of claim 17, and
Lucas further discloses wherein the islanding detector comprises a state machine decoder configured to determined filter coefficients, of the filter, for allowed frequencies in the output impedance of the array of cascaded modules. [¶133: “the Park Transforms 38102, 38202, and 38302 may output the d and q components of the 3rd, 5th, and 7th harmonic currents Ia3rd, Iq3rd, Iq5th, Iq5th, Id7th, and Iq7th into low pass filters 38106, 38104, 38206, 38204, 38306, and 38304 respectively to filter out high frequency components in the waveforms. In some embodiments, the low pass filters 38106, 38104, 38206, 38204, 38306, and 38304 may output the filtered current waveforms to PI controllers 38110, 38108, 38210, 38208, 38310,”].
Conclusion
The prior art made of record and not relied upon is considered pertinent to applicant's disclosure is listed in the PTO-892 Notice of Reference Cited document mailed on 01/14/2026.
Krein (US20110164440A1) - Voltage-sensed system and method for anti-islanding protection of grid-connected inverters:
¶11: preventing islanding of a power source connected to an electric AC grid via an interface. The method senses an output voltage waveform of the interface, controls an output current waveform of the interface to track a reference current waveform having a mathematical relationship with the sensed output voltage waveform. The method then discontinues the output current waveform when the output voltage waveform is sensed to be outside a predetermined waveform range.
Ohm (US20080122293A1) - System and Method for Anti-Islanding, Such as Anti-Islanding for a Grid-Connected Photovoltaic Inverter:
¶19: system and method for detecting islanding of an inverter using a positive feedback mechanism is described. In some examples, the system detects islanding without requiring a detectable change in frequency of the islanded location of the utility grid. For example, the system may detect an islanding condition even though a measured frequency error of the utility grid is zero or may detect the islanding condition based on the measured frequency error being positive or negative. That is, the system may detect islanding by measuring the natural frequency drift within a utility grid or may detect islanding by measuring an error in frequency due to an injected minimum frequency disturbance.
Yu’634 et al. (US20100157634A1) - Power inverter control for grid-tie transition:
¶9: determine an output power of the power inverter based on the output line voltages and output line currents, and determine an amplitude of oscillation in the output power caused by the disturbance frequency. The controller may also be configured to detect an islanding condition, if the amplitude of oscillation is below a threshold. The control system may further include an interface circuit coupled to the controller and configured to disconnect the grid from the power inverter if the islanding condition is detected.
Applicant's amendment necessitated the new ground(s) of rejection presented in this Office action. Accordingly, THIS ACTION IS MADE FINAL. See MPEP § 706.07(a). Applicant is reminded of the extension of time policy as set forth in 37 CFR 1.136(a).
A shortened statutory period for reply to this final action is set to expire THREE MONTHS from the mailing date of this action. In the event a first reply is filed within TWO MONTHS of the mailing date of this final action and the advisory action is not mailed until after the end of the THREE-MONTH shortened statutory period, then the shortened statutory period will expire on the date the advisory action is mailed, and any nonprovisional extension fee (37 CFR 1.17(a)) pursuant to 37 CFR 1.136(a) will be calculated from the mailing date of the advisory action. In no event, however, will the statutory period for reply expire later than SIX MONTHS from the mailing date of this final action.
Any inquiry concerning this communication or earlier communications from the examiner should be directed to MOHAMMED SHAFAYET whose telephone number is (571)272-8239. The examiner can normally be reached M-F 8:30 AM-5:00 PM.
Examiner interviews are available via telephone, in-person, and video conferencing using a USPTO supplied web-based collaboration tool. To schedule an interview, applicant is encouraged to use the USPTO Automated Interview Request (AIR) at http://www.uspto.gov/interviewpractice.
If attempts to reach the examiner by telephone are unsuccessful, the examiner’s supervisor, Kenneth Lo can be reached at (571) 272-9774. The fax phone number for the organization where this application or proceeding is assigned is 571-273-8300.
Information regarding the status of published or unpublished applications may be obtained from Patent Center. Unpublished application information in Patent Center is available to registered users. To file and manage patent submissions in Patent Center, visit: https://patentcenter.uspto.gov. Visit https://www.uspto.gov/patents/apply/patent-center for more information about Patent Center and https://www.uspto.gov/patents/docx for information about filing in DOCX format. For additional questions, contact the Electronic Business Center (EBC) at 866-217-9197 (toll-free). If you would like assistance from a USPTO Customer Service Representative, call 800-786-9199 (IN USA OR CANADA) or 571-272-1000.
/M.S./
Patent Examiner,
Art Unit 2116
/KENNETH M LO/Supervisory Patent Examiner, Art Unit 2116
Prosecution Insights