System and method for operating an electric power system with distributed generation and demand responsive resources based on distribution locational marginal prices
원문보기
IPC분류정보
국가/구분
United States(US) Patent
등록
국제특허분류(IPC7판)
H02J-004/00
H02J-003/14
출원번호
US-0513293
(2014-10-14)
등록번호
US-9960604
(2018-05-01)
발명자
/ 주소
Sun, Hongbo
Zhang, Bowen
출원인 / 주소
MITSUBISHI ELECTRIC RESEARCH LABORATORIES, INC.
대리인 / 주소
Vinokur, Gene
인용정보
피인용 횟수 :
0인용 특허 :
10
초록▼
An iterative framework to optimally integrate various distributed generations (DG) and demand responsive resources (DRR) within a distribution system into transmission market clearing. The concept of distribution aggregated demand and distribution aggregated utility represent a summed distribution l
An iterative framework to optimally integrate various distributed generations (DG) and demand responsive resources (DRR) within a distribution system into transmission market clearing. The concept of distribution aggregated demand and distribution aggregated utility represent a summed distribution level information in consuming electricity that encompasses preferences of the individual DGs and DRRs. This distribution level preference, which is derived based on unbalanced three-phase AC optimal power flow, is bid into the transmission level for optimal market clearing. When the aggregated preferences cannot be obtained, an iterative method enables the transmission and distribution networks to exchange price and demand information. A competitive equilibrium is reached when the method converges to a price-demand coupling point.
대표청구항▼
1. A method for operating an electric power system, wherein the electric power system includes a transmission system operated by a transmission system operator (TSO) and multiple distribution systems, such that each distribution system is operated by a distribution system operator (DSO), comprising
1. A method for operating an electric power system, wherein the electric power system includes a transmission system operated by a transmission system operator (TSO) and multiple distribution systems, such that each distribution system is operated by a distribution system operator (DSO), comprising iterative steps: solving, by the DSO, an unbalanced three-phase alternating current (AC) optimal power flow (OPF) problem based on locational marginal prices (LMP) for power usage for each distribution system, wherein the DSO provides an input on a user input interface to one or more processor in communication with the user input interface and a network, when the DSO cannot obtain an aggregated demand curve at the distribution level, so as to update aggregated demand information for each distribution system in the electric power system, wherein the one or more processor is in communication with other processors of the one or more processor that receive measured electrical values of each distribution system including voltages and phase angles; andsolving, by the TSO, a balanced single-phase direct current (DC) OPF problem to update the LMP for each distribution system, to minimize power generation and distributing cost based on the updated aggregated demand information, iteratively, until a competitive equilibrium reaches a predetermined threshold between aggregated demand and the LMP that results at a market clearing price and demand for energy (MCPDE) for the distribution system. 2. The method of claim 1, further comprising: updating, by the DSO for the TSO, the aggregated demand information according to a linear combination of the aggregated demand information at a last iteration and the aggregated demand based on a last LMP provided by TSO; andupdating, by the TSO for the DSO, the LMP determined according to a linear combination of the LMP at the last iteration, and the LMP based on a last aggregated demand information provided by DSO. 3. The method of claim 2, wherein a diminishing time step size is used by the iterative steps to prevent oscillation or divergence while updating of the LMP and the aggregated demand information. 4. The method of claim 1, wherein the DSO uses an objective function to minimize a cost that is a sum of power from the TSO, power from distributed generators (DG), and comfort losses by demand responsive resources (DRR). 5. The method of claim 4, wherein the DG include solar and wind generators, and the DRR includes price responsive loads. 6. The method of claim 1, wherein the unbalanced three-phase (AC) (OPF) problem is subject to per phase and per bus constraints on active and reactive power flow equations, voltage limits, DRR and DG capacity limits, and per phase and per branch constraints on branch flow limits. 7. The method of claim 6, further comprising: determining a distribution locational marginal price (DLMP) for each phase of each bus of the distribution system as a dual variable of an active power flow equation corresponding to the phase, and the bus in the unbalanced three-phase AC OPF problem. 8. The method of claim 7, further comprising: paying the DG for generating power using the DLMP corresponding to the phase and the bus of the DG;paying the DRR for demand deviation from regular consumption level using the DLMP corresponding to the phase and the bus of the DRR; andcharging consumers with load demands using the DLMP corresponding to the phase and the bus of the loads. 9. The method of claim 1, further comprising: determining the MCPDE by solving the unbalanced three-phase AC OPF problem and the balanced single-phase DC OPF problem for a single operating period, wherein the unbalanced three-phase AC OPF problem is solved by minimizing a cost function over the operating period with constraints of power flow equations, and locational based capacity constraints for DGs and DRRs for the operational period, and wherein the balanced single-phase DC OPF problem minimizes the cost function with constraints for the operational period. 10. The method of claim 1, further comprising: determining a set of the MCPDE by solving the unbalanced three-phase AC OPF problem and the DC OPF problem for multiple periods, wherein the unbalanced three-phase AC OPF problem is solved by the DSO to minimize a cost function over the multiple periods with constraints on power flow equations, and locational based capacity constraints for DGs and DRRs for each period, and inter-temporal constraints for the DG and the DRR between different periods, and wherein the balanced single-phase DC OPF problem minimizes a cost function with the inter-temporal constraints for the multiple periods. 11. The method of claim 1, further comprising: updating, by the DSO for the TSO, the aggregated demand information based on the LMP provided by the TSO; anddetermining, by the TSO, the LMP based on the updated aggregated demand information to minimize a cost of generating power. 12. The method of claim 1, further comprising: updating, by the DSO for the TSO during each iteration, the aggregated demand information and a distribution aggregated utility function for the distribution system based on the LMP and a feasible range of the LMP provided by the TSO; anddetermining, by the TSO, the LMP based on the aggregated demand information and a utility function provided by DSO and minimize a sum of production cost of power generations in the transmission level and a negative sum of the distributed aggregated utility function of the distribution system. 13. The method of claim 12, further comprising: determining the distribution aggregated utility function by integration a distribution aggregated demand curve and the feasible range of aggregated demand of the distribution system. 14. The method of claim 1, wherein the aggregated demand information includes an amount of the aggregated demand for power and a distribution aggregation utility function. 15. The method of claim 1, wherein the electric power system includes fixed and variable generators and fixed and variable loads. 16. The method of claim 1, wherein the steps are implemented by processors at the DSO and the TSO. 17. The method of claim 1, wherein the power distribution system is modeled by a system admittance matrix, and a set of branch admittance matrices for each branch in the power distribution system. 18. A method for operating a power system, wherein the power system includes a transmission system operated by a transmission system operator (TSO) and multiple distribution systems, such that each a distribution system is operated by a distribution system operator (DSO), comprising iterative steps: solving, by the DSO, an balanced single-phase alternating current (AC) optimal power flow (OPF) problem based on locational marginal prices (LMP) for power usage for each distribution system, wherein the DSO provides an input on a user input interface to one or more processor in communication with the user input interface and a network, when the DSO cannot obtain an aggregated demand curve at the distribution level, so as to update aggregated demand information for each distribution system in the power system, wherein the one or more processor is in communication with other processors of the one or more processor that receive measured electrical values of each distribution system including voltages and phase angles; andsolving, by the TSO, a balanced single-phase direct current (DC) OPF problem to update the LMP for each distribution system, to minimize power generation and distributing cost based on the updated aggregated demand information, iteratively, until a competitive equilibrium reaches a predetermined threshold between aggregated demand and the LMP that results at a market clearing price and demand for energy (MCPDE) for the distribution system. 19. The method of claim 1, wherein the predetermined threshold is based on when |PSi(t)−PSi(t+1)|<ϵ, and |LMPi(t)−LMPi(t+1)|<ϵ, such that|PSi(t)−PSi(t+1)| is an aggregated demand difference between two consecutive iterations, where PSi is an aggregated demand of the distribution system, and (t) is the current iteration, and (t+1) is the next iteration, and e is a number approximate to zero, and|LMPi(t)−LMPi(t+1)| is a locational marginal price difference between two consecutive iterations, where LMPi is a locational marginal price of the distribution system, and (t) is the current iteration, and (t+1) is the next iteration. 20. A system for operating an electric power system, wherein the electric power system includes a transmission system operated by a transmission system operator (TSO) and multiple distribution systems, such that each distribution system is operated by a distribution system operator (DSO), comprising: one or more processor in communication with input interfaces and a network used by the DSO is configured to solve an unbalanced three-phase alternating current (AC) optimal power flow (OPF) problem based on locational marginal prices (LMP) for power usage for each distribution system, wherein the DSO provides an input on a user input interface to the one or more processor in communication with the user input interface and a network, when the DSO cannot obtain an aggregated demand curve at the distribution level, so as to update aggregated demand information for each distribution system in the electric power system, wherein the one or more processor is in communication with other processors of the one or more processor that receive measured electrical values of each distribution system including voltages and phase angles; andusing another processor of the one or more processor in communication with an input interface of the input interfaces and the network by the TSO, the TSO is configured to solve a balanced single-phase direct current (DC) OPF problem to update the LMP for each distribution system, to minimize power generation and distributing cost based on the updated aggregated demand information, iteratively, until a competitive equilibrium reaches a predetermined threshold between aggregated demand and the LMP that results at a market clearing price and demand for energy (MCPDE) for the distribution system.
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