Distributed hierarchical control architecture for integrating smart grid assets during normal and disrupted operations

• US 9,762,060 B2
• Filed: 12/31/2013
• Issued: 09/12/2017
• Est. Priority Date: 12/31/2012
• Status: Active Grant

• Current Assignee: Battelle Memorial Institute
• Original Assignee: Battelle Memorial Institute
• Inventors: Kalsi, Karan, Fuller, Jason C., Somani, Abhishek, Pratt, Robert G., Chassin, David P., Hammerstrom, Donald J.
• Primary Examiner(s): Masinick, Michael D
• Application Number:
  US14/145,742
• Publication Number:
  US 20140188689A1
• Time in Patent Office: 1,351 Days
• CPC Class Codes: G05F 5/00 Systems for regulating electric variables by detecting deviations in the electric input to the system and thereby controlling a device within the system to obtain a regulated output
• CPC Class Codes: G06Q 40/04 Trading; Exchange, e.g. stocks, commodities, derivatives or currency exchange
• CPC Class Codes: G06Q 50/06 Energy or water supply
• CPC Class Codes: H02J 13/00017 using optical fiber
• CPC Class Codes: H02J 2300/20 The dispersed energy generation being of renewable origin
• CPC Class Codes: H02J 3/00 Circuit arrangements for ac mains or ac distribution networks
• CPC Class Codes: H02J 3/008 involving trading of energy or energy transmission rights
• CPC Class Codes: H02J 3/06 Controlling transfer of power between connected networks; Controlling sharing of load between connected networks
• CPC Class Codes: H02J 3/16 by adjustment of reactive power
• CPC Class Codes: H02J 3/381 Dispersed generators
• CPC Class Codes: H02J 3/46 Controlling of the sharing of output between the generators, converters, or transformers
• CPC Class Codes: Y02E 40/70 Smart grids as climate change mitigation technology in the energy generation sector
• CPC Class Codes: Y02E 60/00 Enabling technologies; Technologies with a potential or indirect contribution to GHG emissions mitigation
• CPC Class Codes: Y04S 10/12 Monitoring or controlling equipment for energy generation units, e.g. distributed energy generation [DER] or load-side generation
• CPC Class Codes: Y04S 10/123 the energy generation units being or involving renewable energy sources
• CPC Class Codes: Y04S 10/50 Systems or methods supporting the power network operation or management, involving a certain degree of interaction with the load-side end user applications
• CPC Class Codes: Y04S 40/124 using wired telecommunication networks or data transmission busses
• CPC Class Codes: Y04S 50/10 Energy trading, including energy flowing from end-user application to grid

Abstract

Disclosed herein are representative embodiments of methods, apparatus, and systems for facilitating operation and control of a resource distribution system (such as a power grid). Among the disclosed embodiments is a distributed hierarchical control architecture (DHCA) that enables smart grid assets to effectively contribute to grid operations in a controllable manner, while helping to ensure system stability and equitably rewarding their contribution. Embodiments of the disclosed architecture can help unify the dispatch of these resources to provide both market-based and balancing services.

Claims

1. A method for operating an area controller configured to coordinate the distribution of electricity to and from multiple feeder networks of an area, the method comprising, by computing hardware:

monitoring a system frequency at the area;

receiving first power reference values set by a system-wide Balancing Authority (BA);

receiving second power reference values set by a real-time area management system;

computing a power flow reference value indicative of an inter-area power flow, based at least in part on measured area real and reactive power, the first power reference values, and the second power reference values;

computing an area control error based at least in part on the system frequency and the power flow reference value; and

controlling one or more electrical generators in the area to adjust their supply and thereby reduce the area control error.

2. The method of claim 1, wherein the method further comprises transmitting the power flow reference value to controllers of the multiple feeder networks.

3. The method of claim 1, wherein the power flow reference value is based on one or more of:

(a) differences between the measured area real and reactive power and the first power reference values;

or (b) differences between the measured area real and reactive power and the second power reference values, which are for a current cleared time interval of a transactive control energy market in which the area controller operates.

4. The method of claim 1, further comprising computing one or more transactive signals representing a bid for using or supplying electricity in an upcoming time interval of a transactive control energy market, the time interval being a periodic time interval that repeats at a fixed interval frequency.

5. One or more non-transitory computer-readable media storing computer-executable instructions for causing an area controller, when programmed thereby, to perform balancing operations to coordinate the distribution of electricity to and from multiple feeder networks of an area of a power system, the balancing operations comprising, with computing hardware of the area controller:

during participation in a transactive control energy market that has time intervals with a first frequency, repeatedly, at a second frequency faster than the first frequency;

monitoring a system frequency at the area;

computing a power flow reference value, indicative of an inter-area power flow;

computing an area control error based at least in part on the system frequency and the power flow reference value; and

controlling one or more electrical generators in the area to adjust their supply and thereby reduce the area control error and improve stability of the power system.

6. The one or more computer-readable media of claim 5, wherein the balancing operations further comprise transmitting the power flow reference value to controllers of the multiple feeder networks.

7. The one or more computer-readable media of claim 5, wherein the power flow reference value is based on one or more of:

(a) differences between measured area real and reactive power and power reference values set by a system-wide Balancing Authority (BA);

or (b) differences between measured area real and reactive power and power reference values for a current cleared time interval of the transactive control energy market.

8. The one or more computer-readable media of claim 5, further comprising computer-executable instructions for causing the area controller, when programmed thereby, to perform bidding operations that comprise computing one or more transactive signals representing a bid for using or supplying electricity in an upcoming time interval of the transactive control energy market.

9. An area controller comprising computing hardware, wherein the area controller is configured to perform balancing operations to coordinate the distribution of electricity to and from multiple feeder networks of an area in parallel with a transactive control energy market in which the area controller operates, the balancing operations comprising:

monitoring a system frequency at the area;

receiving first power reference values for balancing a power system that includes the area;

receiving second power reference values for a current cleared time interval of the transactive control energy market;

computing a power flow reference value indicative of an inter-area power flow, based at least in part on measured area real and reactive power, the first power reference values, and the second power reference values;

computing an area control error based at least in part on the system frequency and the power flow reference value; and

controlling one or more electrical generators in the area to adjust their supply and thereby reduce the area control error.

10. The area controller of claim 9, wherein the balancing operations further comprise transmitting the power flow reference value to controllers of the multiple feeder networks.

11. The area controller of claim 9, wherein the power flow reference value is based on one or more of:

(a) differences between the measured area real and reactive power and the first power reference values, which are set by a system-wide Balancing Authority (BA);

or (b) differences between the measured area real and reactive power and the second power reference values.

12. The area controller of claim 9, wherein the area controller is further configured to compute one or more transactive signals representing a bid for using or supplying electricity in an upcoming time interval of the transactive control energy market.

13. A method for operating an area controller configured to coordinate the distribution of electricity to and from multiple feeder networks of an area, comprising:

by computing hardware;

monitoring a system frequency at the area;

computing a power flow reference value, indicative of an inter-area power flow, based on a weighted sum of;

(a) differences between measured area real and reactive power and power reference values set by a system-wide Balancing Authority (BA); and

(b) differences between the measured area real and reactive power and power reference values for a current cleared time interval of a transactive control energy market in which the area controller operates, wherein (a) is weighted more heavily during contingencies and (b) is weighted more heavily during normal operation;

computing an area control error based at least in part on the system frequency and the power flow reference value; and

controlling one or more electrical generators in the area to adjust their supply and thereby reduce the area control error.

14. A method for operating a feeder controller configured to coordinate the distribution of electricity to and from multiple electrical devices coupled to a feeder controlled by the feeder controller, comprising, by computing hardware:

monitoring a system frequency at the feeder;

computing a feeder power reference value based on a weighted sum of;

(a) differences between measured feeder real and reactive power and power reference values set by an area controller; and

(b) differences between the measured feeder real and reactive power and power reference values for the feeder for a current cleared time interval of a transactive control energy market in which the feeder controller operates, wherein (a) is weighted more heavily during contingencies and (b) is weighted more heavily during normal operation;

computing a feeder control error based at least in part on the system frequency and the feeder power reference value;

computing one or more setpoints for one or more electrical devices coupled to the feeder, the setpoints being configured to adjust performance of the one or more electrical devices and thereby reduce the feeder control error; and

transmitting the one or more setpoints to controllers for the one or more electrical devices.

15. One or more non-transitory computer-readable media storing computer-executable instructions for causing an area controller, when programmed thereby, to perform operations to coordinate the distribution of electricity to and from multiple feeder networks of an area, the operations comprising, with computing hardware of the area controller:

monitoring a system frequency at the area;

computing a power flow reference value, indicative of an inter-area power flow, based on a weighted sum of;

(a) differences between measured area real and reactive power and power reference values set by a system-wide Balancing Authority (BA); and

(b) differences between the measured area real and reactive power and power reference values for a current cleared time interval of a transactive control energy market in which the area controller operates, wherein (a) is weighted more heavily during contingencies and (b) is weighted more heavily during normal operation;

computing an area control error based at least in part on the system frequency and the power flow reference value; and

controlling one or more electrical generators in the area to adjust their supply and thereby reduce the area control error.

16. An area controller comprising computing hardware, wherein the area controller is configured to perform operations to coordinate the distribution of electricity to and from multiple feeder networks of an area, the operations comprising:

monitoring a system frequency at the area;

computing a power flow reference value, indicative of an inter-area power flow, based on a weighted sum of;

(a) differences between measured area real and reactive power and power reference values set by a system-wide Balancing Authority (BA); and

(b) differences between the measured area real and reactive power and power reference values for a current cleared time interval of a transactive control energy market in which the area controller operates, wherein (a) is weighted more heavily during contingencies and (b) is weighted more heavily during normal operation;

computing an area control error based at least in part on the system frequency and the power flow reference value; and

controlling one or more electrical generators in the area to adjust their supply and thereby reduce the area control error.

17. One or more non-transitory computer-readable media storing computer-executable instructions for causing a feeder controller, when programmed thereby, to perform operations to coordinate the distribution of electricity to and from multiple electrical devices coupled to a feeder controlled by the feeder controller, the operations comprising, with computing hardware of the feeder controller:

monitoring a system frequency at the feeder;

computing a feeder power reference value based on a weighted sum of;

(a) differences between measured feeder real and reactive power and power reference values set by an area controller; and

(b) differences between the measured feeder real and reactive power and power reference values for the feeder for a current cleared time interval of a transactive control energy market in which the feeder controller operates, wherein (a) is weighted more heavily during contingencies and (b) is weighted more heavily during normal operation;

computing a feeder control error based at least in part on the system frequency and the feeder power reference value;

computing one or more setpoints for one or more electrical devices coupled to the feeder, the setpoints being configured to adjust performance of the one or more electrical devices and thereby reduce the feeder control error; and

transmitting the one or more setpoints to controllers for the one or more electrical devices.