Distributed asset optimization (DAO) system and method

• US 7,089,125 B2
• Filed: 10/27/2004
• Issued: 08/08/2006
• Est. Priority Date: 10/27/2003
• Status: Active Grant

• Current Assignee: IP Co., LLC (Ideahub, Inc.)
• Original Assignee: Itron, Inc.
• Inventors: Sonderegger, Robert C.
• Primary Examiner(s): Nghiem, Michael
• Application Number:
  US10/976,103
• Publication Number:
  US 20050090995A1
• Time in Patent Office: 650 Days
• Field of Search: 702/1, 702/3, 702/57, 702/60, 702/61, 340/870.01, 340/870.02, 703/4, 703/13, 703/21
• US Class Current: 702/57
• CPC Class Codes: G01D 2204/14 Displaying of utility usage with respect to time, e.g. for monitoring evolution of usage or with respect to weather conditions
• CPC Class Codes: H02J 13/00002 characterised by monitoring
• CPC Class Codes: H02J 13/00034 the elements or equipment being or involving an electric power substation
• CPC Class Codes: H02J 3/00 Circuit arrangements for ac mains or ac distribution networks
• CPC Class Codes: H02J 3/003 Load forecast, e.g. methods or systems for forecasting future load demand
• CPC Class Codes: Y02B 90/20 Smart grids as enabling technology in buildings sector smart grids supporting the management or operation of end-user stationary applications in general, or like technologies with no associated climate change mitigation effect Y04S20/00
• CPC Class Codes: Y02E 60/00 Enabling technologies; Technologies with a potential or indirect contribution to GHG emissions mitigation
• CPC Class Codes: Y04S 10/30 State monitoring, e.g. fault, temperature monitoring, insulator monitoring, corona discharge
• 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 20/30 Smart metering, e.g. specially adapted for remote reading

Abstract

A method of determining an energy load on a power distribution component, and a system for storing such method are presented. The method entails collecting meter data (in various formats) and weather data. The meter data and the weather data are correlated to generate tuning equations, each of which is associated with at least one of the meters and indicates a weather sensitivity of that meter. Any meter data that is in the hourly or daily format are normalized to generate normalized hourly loadshapes that are independent of weather conditions and weekly variations. These normalized hourly loadshapes are combined with the tuning equations to generate a set of model coefficients for each of the meters. The set of model coefficients reflects weather conditions and weekly variations for one of the meters, and is useful for determining an energy load on the power distribution component.

Claims

1. A method of determining an energy load on a power distribution component, the method comprising:

collecting meter data for a group of meters, wherein some of the meter data is in an hourly format and some of the meter data is in a monthly format;

collecting weather data;

correlating the meter data with the weather data to generate tuning equations, wherein each of the tuning equations is associated with at least one of the meters and indicates a weather sensitivity of the associated meter;

normalizing the meter data in the hourly format to generate normalized hourly loadshapes that are independent of weather conditions and weekly variations;

combining the tuning equations and the normalized hourly loadshapes to generate a set of model coefficients for each of the meters, wherein the set of model coefficients reflects weather conditions and weekly variations for one of the meters; and

storing the model coefficients so that the model coefficients are retrievable to determine the power load on a power distribution component.

2. The method of claim 1 further comprising selecting the group of meters by:

determining a geographical boundary; and

identifying meters that are located within the geographical boundary.

3. The method of claim 1, wherein the meter data comprises daily power usage data of the meters.

4. The method of claim 1 further comprising validating the collected meter data.

5. The method of claim 4, wherein validating the collected meter data comprises modifying or disregarding values that deviate from a general pattern.

6. The method of claim 4, wherein the validating comprises eliminating duplicate entries.

7. The method of claim 4, wherein the validating comprises checking consistency between data obtained from different sources.

8. The method of claim 1, wherein a first one of the meters has a first profile and generates meter data in an hourly format and a second one of the meters has a second profile and generates meter data in a monthly format, wherein the combining of the tuning equations and the normalized hourly loadshapes comprises matching the first profile and the second profile.

9. The method of claim 8, wherein one of the normalized hourly loadshapes is based on the meter data from the first one of the meters, further comprising assigning the one normalized hourly loadshape to the second one of the meters based on the matching of the first profile and the second profile.

10. The method of claim 1, wherein the model coefficients indicate a meter'"'"'s revenue class, rate class, weather sensitivity, and loadfactor.

11. The method of claim 1 further comprising obtaining a distribution connectivity map that shows power line connectivity among meters, transformers, feeders, and substations.

12. The method of claim 1 further comprising:

determining which subgroup of meters are supplied by the distribution component; and

summing the hourly normalized loadshapes associated with each of the subgroup of meters to determine the energy load on the distribution component.

13. The method of claim 12, wherein the distribution component is a transformer and the energy load on the distribution component is an hourly normalized transformer loadshape, further comprising summing a plurality of hourly normalized transformer loadshapes including the hourly normalized transformer loadshape to determine a feeder circuit loadshape.

14. The method of claim 1, wherein the distribution component is a transformer, the method further comprising:

calculating a first weekly value by summing the hourly normalized meter loadshapes of a subgroup of meters;

calculating a second weekly value by summing hourly meter data obtained from a public database;

determining a difference between the first weekly value and the second weekly value; and

adjusting one or more of the hourly normalized loadshapes if the difference is greater than a first predetermined value.

15. The method of claim 14 further comprising generating an hourly transformer loadshape using the hourly normalized meter loadshapes.

16. The method of claim 15 further comprising determining the energy load on a feeder circuit that supplies power to the transformer, the method further comprising:

determining which subgroup of transformers receive power from the feeder circuit;

calculating a third weekly value by summing hourly normalized transformer loadshapes;

calculating a fourth weekly value by summing hourly transformer data obtained from a public database;

determining a difference between the third weekly value and the fourth weekly value; and

adjusting one or more of the hourly normalized transformer loadshapes if the difference is greater than a second predetermined value.

17. The method of claim 16 further comprising computing an effective loss factor to account for part of the difference between the third weekly value and the fourth weekly value.

18. The method of claim 17 further comprising generating an hourly normalized feeder loadshape based on the hourly transformer loadshapes and the effective loss factor.

19. The method of claim 16, wherein the computing of the effective loss factor comprises dividing the third weekly value by the fourth weekly value.

20. The method of claim 1 further comprising:

receiving a weather condition; and

generating a meter loadshape for a particular meter under the weather condition by using the model coefficients, wherein the meter loadshape is useful for determining a power load on the particular meter under the weather condition.

21. The method of claim 20 further comprising:

generating loadshapes for a plurality of meters under the weather condition, the plurality of meters including the particular meter; and

aggregating the loadshapes for the plurality of meters to generate a transformer loadshape for a transformer that supplies energy to the plurality of meters.

22. The method of claim 21, wherein the transformer loadshape is one of a plurality of transformer loadshapes determined by aggregating meter loadshapes, further comprising aggregating the transformer loadshapes to generate a feeder circuit loadshape for a feeder circuit that supplies power to the plurality of transformers whose loadshapes are aggregated.

23. The method of claim 20 further comprising receiving a date in the past and using the date to receive the weather condition.

24. The method of claim 20 further comprising generating a report in response to a request by using the meter loadshapes.

25. The method of claim 1 further comprising storing the normalized hourly loadshapes and the set of model coefficients.

26. A computer-readable memory system to instruct a computer to function in a specified manner, the memory comprising:

instructions to collect meter data and weather data for a group of meters;

instructions to correlate the meter data with the weather data to generate tuning equations, wherein each of the tuning equations is associated with at least one meter and indicates a weather sensitivity of the meter;

instructions to normalize the meter data to generate normalized hourly loadshapes that are independent of weather conditions and weekly variations; and

instructions to combine the tuning equations and the normalized hourly loadshapes to generate a set of model coefficients for the meter, wherein the set of model coefficients reflects weather conditions and weekly variations for the meter; and

instructions to store the model coefficients so that the model coefficients are retrievable to determine the power load on a power distribution component.

27. The memory system of claim 26 further comprising instructions to generate a report by using the model coefficients in response to a client request.

28. The memory system of claim 26 further comprising instructions to store the normalized hourly loadshapes, wherein the instructions to store the model coefficients comprises instructions to store the model coefficients in a separate database than the normalized hourly loadshapes.

29. The memory system of claim 26 further comprising instructions to select the group of meters by determining a geographical boundary and identifying meters that are located within the geographical boundary.

30. The memory system of claim 26 further comprising instructions to validate the meter data.

31. The memory system of claim 30, wherein the instructions to validate the meter data comprises instructions to modify or disregard values that deviate from a general pattern.

32. The memory system of claim 30, wherein the instructions to validate the meter data comprises instructions to eliminate duplicate entries.

33. The memory system of claim 30, wherein the instructions to validate the meter data comprises instructions to check consistency between data from different sources.

34. The memory system of claim 26, wherein the instructions to combine the tuning equations and the normalized hourly loadshapes comprise instructions to match a first set of profile values that is associated with the tuning equations with a second set of profile values that is associated with hourly meter data from which the normalized hourly loadshapes are derived.

35. The memory system of claim 26, wherein the instructions to combine the tuning equations and the normalized hourly loadshapes comprise instructions to assign one of the normalized hourly loadshapes to each one of the meters by matching profile values that are associated with the normalized hourly loadshapes with profile values of each of the meters.

36. The memory system of claim 26, wherein the model coefficients indicate a meter'"'"'s revenue class, rate class, weather sensitivity, and loadfactor.

37. The memory system of claim 26 further comprising instructions to obtain a distribution connectivity map that shows power line connectivity among meters, transformers, feeders, and substations.

38. The memory system of claim 26 further comprising:

instructions to determine which subgroup of meters are supplied energy by the distribution component; and

instructions to sum the hourly normalized loadshapes associated with each of the subgroup of meters to determine the energy load on the distribution component.

39. The memory system of claim 38, wherein the distribution component is a transformer and the energy load on the distribution component is an hourly normalized transformer loadshape, further comprising instructions to sum a plurality of hourly normalized transformer loadshapes including the hourly normalized transformer loadshape to determine a feeder circuit loadshape.

40. The memory system of claim 26, wherein the distribution component is a transformer, the memory further comprising:

instructions to calculate a first weekly value by summing the hourly normalized meter loadshapes of a subgroup of meters;

instructions to calculate a second weekly value by summing hourly meter data obtained from a public database;

instructions to determine a difference between the first weekly value and the second weekly value; and

instructions to adjust one or more of the hourly normalized loadshapes if the difference is greater than a first predetermined value.

41. The memory system of claim 40 further comprising generating an hourly transformer loadshape using the hourly normalized meter loadshapes.

42. The memory system of claim 41 further comprising:

instructions to determine the energy load on a feeder circuit that supplies power to the transformer;

instructions to determine which subgroup of transformers receive power from the feeder circuit;

instructions to calculate a third weekly value by summing hourly normalized transformer loadshapes;

instructions to calculate a fourth weekly value by summing hourly transformer data obtained from a public database;

instructions to determine a difference between the third weekly value and the fourth weekly value; and

instructions to adjust one or more of the hourly normalized transformer loadshapes if the difference is greater than a second predetermined value.

43. The memory system of claim 42 further comprising instructions to compute an effective loss factor to account for part of the difference between the third weekly value and the fourth weekly value.

44. The method system of claim 43 further comprising instructions to generate an hourly normalized feeder loadshape based on the hourly transformer loadshapes and the effective loss factor.

45. The memory system of claim 42, wherein the computing of the effective loss factor comprises dividing the third weekly value by the fourth weekly value.

46. The memory system of claim 26 further comprising:

instructions to receive a weather condition; and

instructions to generate a meter loadshape for a particular meter under the weather condition by using the model coefficients, wherein the meter loadshape is useful for determining a power load on the particular meter under the weather condition.

47. The memory system of claim 46 further comprising:

generating loadshapes for a plurality of meters under the weather condition, the plurality of meters including the particular meter; and

aggregating the loadshapes for the plurality of meters to generate a transformer loadshape for a transformer that supplies energy to the plurality of meters.

48. The memory system of claim 47, wherein the transformer loadshape is one of a plurality of transformer loadshapes determined by aggregating meter loadshapes, further comprising instructions to aggregate the transformer loadshapes to generate a feeder circuit loadshape for a feeder circuit that supplies power to the plurality of transformers whose loadshapes are aggregated.

49. The memory system of claim 46 further comprising:

instructions to receive a date in the past; and

instructions to use the date to receive the weather condition.

50. The memory system of claim 26 further comprising instructions to store the normalized hourly loadshapes and the set of model coefficients.