Patent Application
20210334910
The present invention generally relates to the field of managing a power grid, and more particularly to outage planning and coordinate in a distributed electrical power grid.
Power distribution grids typically include electricity generation plants, such as natural gas powered plant, a nuclear powered plant, solar electric farms, wind farms, that connect with electric power transmission infrastructure. Electric power transmission infrastructure includes high voltage transmission lines, electricity distribution stations, and interconnecting switches. Electric utility companies may manage the power grid, including managing faults, maintenance, and upgrades related to the power grid. However, the management of the power grid is often inefficient and costly relying on telephone calls from consumers when an outage occurs or on field workers analyzing the local distribution network.
Scheduled maintenance and repairs involve switch plans and repair actions. The switch plans involve isolating the problem and then restoring the problem after repair. This total time of restoration directly affects reliability metrics, so utilities wish to minimize outage durations, minimize the boundaries of the total area affected by outages, and minimize the sections of de-energized grid that are isolated because of outages. Repair estimates are currently calculated by individuals or by simply referring to pre-filled tables.
The outage and work planning for a distributed electrical power grid, which involves planned de-energization of electrical equipment, in contrast with an unplanned power outage, is currently a manually intensive effort. Today there is no automated systemic offering to provide core conflict resolution and outage planning. The business processes today also do not provide for an automated methodology for notifying requesters of work of upcoming pending work orders. Furthermore, there is no current mechanism to make requestors to confirm, to decline, or to edit on the fly their pending work order(s).
The present invention provides an automated outage and work-flow planning system for a distributed electrical power grid. The system is used with planned de-energization of electrical equipment as opposed to responding to an unplanned power outage. The present invention provides an automated system that provides core conflict resolution and outage planning. The present invention automatically notifies requestors of upcoming work orders. in addition, the present invention reduces scheduling in efficiencies by requiring requestors to confirm, to decline, or to edit on the fly their pending work order(s).
More specifically disclosed is a system, a method, and a computer program product for managing outage and maintenance planning in a distributed electrical power grid. An order is received via a graphical user interface on a requestor device. The order includes a request date and type of service. The order is as part of a request for service or maintenance of a piece of selected electrical equipment in a distributed electrical power grid. A database of requests is accessed to identify conflicts with other orders for the distributed electrical power grid. Based on a conflict being identified, removing the request from a planning workflow and sending a cancellation notice to the requestor device. Otherwise, in the event of no conflict, in one embodiment a status tag is retrieved indicating a repair state (e.g. a defective state, a missing state or a damage state) of the piece of selected electrical equipment A first confirmation notification is sent to the requestor device to confirm the request. In one embodiment the confirmation is populated with the status tag of the piece of selected electrical equipment.
Next, based on receiving a first confirmation of the request from the requestor device, storing the request with a status of new (SNEW) in the database and sending a request notification to the requestor device that the request has been placed. Otherwise in response to not receiving the first confirmation, cancelling the request and sending a cancellation notice due to lack of verification to the requestor device.
Next a planning manager (CCSL) reviews the request for other types of conflicts. Based on another type of conflict being identified, changing the status of the request to modify (RMOD) in the database and sending a modify notice to the requestor device. Otherwise, if the planning manager does not identify any conflicts, building out sub-steps (PQ steps) required to fulfill the request. A second confirmation notification is sent to the requestor device to confirm the request to confirm the request. In one embodiment the second confirmation notification is populated with the status tag of the selected electrical equipment and storing the request with a status of approved (APPV) in the database;
Continuing further, based on receiving the second confirmation of the request from the requestor device, leaving the status of the request to approved (APPV) in the database, otherwise changing the request date out to a future date, changing the status of the request to modify (RMOD) and sending a date modified notice to the requestor device.
Lastly, based on the status of the request being approved (APPV), the request is dispatched to a crew to for maintenance.
In one example if all the orders are not completed, the above process includes a step of determining that at least one order in the request is not completed by the crew and placing the order back on the calendar for tomorrow. Otherwise, if all the orders are completed, the process includes receiving a work complete confirmation by the crew in response to the order being completed and updating the status of the request to finished (FINI).
In another example, the present invention allows coordination between entities performing the work on same outage segments. In this example, the process includes retrieving a status tag indicating a repair state (e.g. a defective state, a missing state or a damage state) of the piece of selected electrical equipment. Next, based on the type of service for the selected electrical equipment, a de-energized section of the distributed electrical power grid will have power shut off. Any other electrical equipment is identified in the de-energized section of the distributed power grid with at least one previous pending order for a previous date. The order and the pending previous order is scheduled on a same date. The customers of the downstream element only experience one instead of two outages due to an improved scheduling process.
In another example, based on the status of the request being approved, the system automatically identifies at least one switchgear and/or one or more reclosers in the distributed electrical power grid that controls the piece of selected electrical equipment. The system automatically sending a control signal to the switchgear and/or the reclosers to maintain a lockout stage that prevent re-energizing the at least one piece of selected electrical equipment during a scheduled maintenance period in the request.
The accompanying figures where like reference numerals refer to identical or functionally similar elements throughout the separate views, and which together with the detailed description below are incorporated in and form part of the specification, serve to further illustrate various embodiments and to explain various principles and advantages all in accordance with the present disclosure, in which:
As required, detailed embodiments are disclosed herein; however, it is to be understood that the disclosed embodiments are merely examples and that the systems and methods described below are embodied in various forms. Therefore, specific structural and functional details disclosed herein are not to be interpreted as limiting, but merely as a basis for the claims and as a representative basis for teaching one skilled in the art to variously employ the disclosed subject matter in virtually any appropriately detailed structure and function. Further, the terms and phrases used herein are not intended to be limiting, but rather, to provide an understandable description.
Generally, the terms “a” or “an”, as used herein, are defined as one or more than one. The term plurality, as used herein, is defined as two or more than two. The term another, as used herein, is defined as at least a second or more. The terms “including” and “having,” as used herein, are defined as comprising (i.e., open language). The term “coupled,” as used herein, is defined as “connected,” although not necessarily directly, and not necessarily mechanically. The term “configured to” describes hardware, software or a combination of hardware and software that is adapted to, set up, arranged, built, composed, constructed, designed or that has any combination of these characteristics to carry out a given function. The term “adapted to” describes hardware, software or a combination of hardware and software that is capable of, able to accommodate, to make, or that is suitable to carry out a given function.
The term “confirmation” is portion of the workflow for maintenance and repair in which a party, typically a requestor or dispatcher must affirmatively respond to a prompt for the workflow to continue down a maintenance path or repair path. In the event of no confirmation is received, the workflow will branch to an alternative path that puts the order in a holding or cancelled state.
The term “conflict” is an incompatibility between two orders. The incompatibility is typically due to which portion or portions of a distributed power grid is being de-energized during a given time-frame due to another user requesting the same or adjacent portion of the grid during the same time-frame.
The term “crew” means a group of one or more personnel, employees or contractors to work to maintain or replace electrical equipment.
The term “de-energized” means a piece of electrical equipment in which electrical energy is shut-off or the electricity has been disconnected.
The term “distributed power grid” is an interconnected network for delivering electricity from producers to consumers. It includes generating stations that produce electric power, electrical substations for stepping electrical voltage up for transmission, or down for distribution, and high voltage transmission lines that carry power from distant sources to demand-centers.
The term “down-stream electrical equipment” refers to electrical equipment on the same electrical circuit that is also de-energized when a component typically geographically closer (i.e. up-stream electrical equipment) to the electricity generation plant or sub-station is de-energized.
The term “electrical equipment” means and one or more components, assets or infrastructure in a distributed power grid that is both required for operation and maintained or repaired. Examples of electrical equipment include transmission lines, wires, switches, transformers, insulators, circuit breakers, connectors, lighting protection, busbars, isolators and more.
The term “feeder lines” or just “feeders” are the power lines through which electricity is transmitted in power systems. Feeder transmits power from generating station or substation to the distribution points.
The term “graphical user interface” or GUI a visual way of interacting with a computer using items such as windows, icons, and menus, used by computing devices including computers, smart phones, tablets, laptops and other connected devices.
The term “order” is a component or portion of a request. For example one request may generate two or more orders. The may be one order for delivery of electrical equipment and another order for scheduling personnel or a crew to install the equipment.
The term “recloser” or “automatic circuit reclosers (ACRs)” are a class of switchgear to detect and interrupt momentary faults. ACRs can be thought of as high voltage rated circuit breakers with integrated current and voltage sensors and a protection relay.
The term “request” is a request for maintenance or repair of electrical equipment in a distributed power grid.
The term “status tag” is a tag, which may be physical or just exist in a database or both, that indicated a repair state of electrical equipment. The repair state denotes defective state, missing state, or damaged state of the electrical equipment.
The term “switchgear” is composed of electrical disconnect switches, fuses or circuit breakers used to control, protect and isolate electrical equipment. Switchgear is used both to de-energize equipment to allow work to be done and to clear faults downstream.
The term “work flow” is a series of business processes and rules in which an order must pass from initiation to completion.
The present invention provides an automated outage and work-flow planning system for in a distributed electrical power grid with planned de-energization of electrical equipment as opposed to responding to an unplanned power outage. The present invention provides an automated systemic that provides core conflict resolution and outage planning. The present invention automatically notifies requestors of upcoming work orders. In addition, the present invention reduces scheduling in efficiencies by requiring requestors to confirm, to decline, or to edit on the fly their pending work order(s).
If an outage is scheduled at one point in a distributed power grid, then power is also cut to downstream resources. The present invention allows planned work to be scheduled on downstream resources while power is out due to work on upstream resource. Unlike prior solutions, the present invention provides a unique improvement because the overall customer outage time is reduced. State differently, the customers of the downstream element only experience one instead of two outages due to an improved scheduling process.
The present invention overcomes the problem with the prior art when the switching and repair actions are not fully automated. The present invention includes the time a dispatched work crew requires to have the outage added to the repair time in the restoration estimations. This time for a dispatched crew is dependent on a work crews' current position, and the ability for the crew to repair the outage depends on the equipment inventory. Unlike previous system, the present invention provides time estimations to restore and repair and equipment availability, that is, the total switching times.
The present invention provides visibility to real time work to accurately enable dispatch resources to prepare for the day's work and not bottleneck the resources as they call for permission to execute planned switching and outage work.
Turning now to
The transmission lines 106 are electrically connected to a step down transformer 110. The step-down transformer decreases the voltage from primary to secondary to be used by typical 26 kV and 69 kV sub-station customer 112, a 13 kV and 4 kV customer 114 and a 120 v and 240 V customer 116 as shown.
Referring now to
A transmission line 256 is connected to the primary winding 254 of each three-phase transformer 252. Additionally, a switch 258 (e.g., a high-side TX interrupter) are physically and logically positioned upstream of each primary winding 254, such that there are R number of switches 258. In situations where a given switch 258 is opened, power does not flow to the primary winding 254. Conversely, in situations where the given switch 258 is closed, power flows through the transmission line 256 to the primary winding 254. Further, a switch 259 (e.g., a transmission line switch) are coupled along the transmission line 256. If the switch 259 is opened, no power is provided to any of the downstream primary windings 254 of the three-phase transformers 252. Conversely, if the switch 259 is closed, power flows to each switch 258 and to each downstream primary winding 254 of a corresponding three-phase transformer 252.
Q number of feeder lines 260 are connected to the secondary winding 255 of each three-phase transformer 252, where Q is an integer greater than or equal to one. Moreover, each three-phase transformer 252 can have a different number of feeder lines 260 connected thereto. Each feeder line 260 carries a three-phase voltage signal that are provided to a plurality of customer premises via additional electrical equipment (e.g., additional transformers and transmission lines). A three-phase voltmeter 262 are coupled to each of transmission lines, such that there are Q number of three-phase voltmeters 262 downstream of each secondary winding 255 of each three-phase transformer 252.
A power provider 264 can provide three-phase power on the transmission line 256. The power provider 264 are representative of a power generator, such as a power plant such as a wind farm, a solar system, a thermal solar field, a fossil fuel based power generator (e.g., a coal or natural gas power generator) or a nuclear power generator and attendant constituent structures or any combination thereof. Alternatively, the power provider 264 could be implemented as a stored power system (e.g., a battery system).
A utility server 270 communicates directly or indirectly with electrical components of the power distribution system 250. The utility server 270 includes a memory for storing machine executable instructions and a processing unit comprising one or more processor cores that access the memory and executes the machine readable instructions. In some examples, the utility server 270 are implemented as a stand-alone server or part of an enterprise system (e.g., in a computing cloud) or in communication with such an enterprise system, such as a supervisory control and data acquisition (SCADA) system 272 that may be coupled to a DOPT tool described further below.
The utility server 270 includes a graphical user interface (GUI) 274 that outputs data uniquely identifying the given switch 258 or 259 from the plurality of switches 258 or 259. In some examples, the alert are output by the GUI 274 as a chart. In this manner, defective switches (e.g., switches with an open pole) can be easily identified without the installation of additional hardware on the power distribution system 250.
Each of the K number of substations 304 transforms the high voltage AC power signal into a mid-voltage power signal. For example, it may be desirable in some circumstances to step down (or to step up) voltage via one or more substation 304 electrical components, to phase-shift and/or otherwise to adjust current phase or amplitude, for instance, to achieve a desired power function as specified by the kind of load and/or to minimize energy lost in the power distribution system 300. As one example, each of the K number of substations 304 includes J number of three-phase transformers 310 (labeled “XMFR”) for transforming and conditioning a 230 kV or 115 kV AC signal into a 13.8 kV AC signal or 23 kV AC signal. It is to be appreciated that in yet other examples, different input and output voltages could be implemented. In each such situation, each substation 304 can have the same or different number of three-phase transformers 310. It is noted that the power distribution system 300 may include more than one power provider 302.
Each of the J number of three-phase transformers 310 includes a two-dimensional index number (i,j). In such a situation, the first number, i identifies a substation 304 in which the three-phase transformer 310 is located. The second number, j, indicates the number of the three-phase transformer 310 within a respective substation 304. As an example, the first three-phase transformer 310 in the Kth substation 304 is labeled and referred to as the three-phase transformer (K,1). Similarly, the Jth three-phase transformer 310 in the first substation 304 is labeled and referred to as the three-phase transformer (1,J). In this manner, each three-phase transformer 310 are uniquely identified.
Each of the J number of three-phase transformers 310 at each of the K number of substations 304 are implemented a delta-wye transformer. In such a situation, the transmission line 306 are connected to a primary winding (e.g., a delta winding) at each of the J number of three-phase transformers 310.
A transmission line switch 312 (labeled SW-T) are logically and physically positioned along the transmission line 306. The transmission line switch 312 has two states. In an open state, the transmission line switch 312 disconnects power flowing between the power provider 302 and each of the J number of three-phase transformers 310 at each of the K number of substations 304. Conversely, in a closed state, the transmission line switch 312 allows electricity to flow from the power provider 302 to each of the J number of three-phase transformers 310 at each of the K number of substations 304.
Similarly, switches implemented as high-side TX interrupters 314 (labeled “SW”) are physically and logically connected upstream of each of the K number of three-phase transformers 310 along the transmission line 306. Each of the high-side TX interrupters 314 includes a closed state that allows power to flow to a downstream three-phase transformer 310 and an open state that prevents power from flowing to the downstream three-phase transformer 310. Each high-side TX interrupter 314 is labeled with the same index number as the downstream three-phase transformer 310. For instance, the high-side TX interrupter (1,1) is upstream of the three-phase transformer (1,1).
Feeder lines 320 are connected downstream from each three-phase transformer 310. More particularly, each feeder line 320 are connected to a secondary winding of a respective three-phase transformer 310. In examples where each three-phase transformer 310 is implemented as a delta-wye transformer, each feeder line 320 are coupled to a wye winding of the respective three-phase transformer 310. In this manner, components upstream from each three-phase transformer 310, including each high-side TX interrupter 314 and the transmission line switch 312 are galvanically isolated from the feeder lines 320.
In the example illustrated, each three-phase transformer 310 has three (3) feeder lines 320 connected downstream. However, in other examples, there could be more or less feeder lines 320 connected to each three-phase transformer 310. Additionally, different three-phase transformers 310 can have different number of feeder lines 320 connected. Each feeder line 320 carries a three-phase voltage signal that are monitored by a respective three-phase voltmeter 322. Each three-phase voltmeter 322 monitors a voltage on each phase of the feeder line 320 (carrying a three-phase voltage signal). Additionally, each three-phase voltmeter 322 generates voltage data characterizing a present voltage on each phase of the feeder line 320. Each three-phase voltmeter 322 is labeled an index number (i,j,k), where i,j identify the upstream transformer and the index number k identifies the particular three-phase voltmeter 322 and the feeder line 320 to which the three-phase voltmeter 322 is connected.
Each feeder line 320 supplies voltage to a plurality of downstream customer premises 330. Each customer premise 330 are implemented as an industrial or residential consumer of electric power. Additionally, each customer premise 330 are equipped with a smart meter 332 (alternatively referred to as a meter) that monitors an incoming power signal and consumption at the respective customer premises 330.
In the example illustrated, the plurality of customer premises 330 and the smart meters 332 are collectively represented by a single component. In practice, there are thousands or millions of individual customer premises 330. Additionally, electrical infrastructure downstream from the K number of substations 304, such as step-down transformers are omitted for purposes of simplification of explanation. Furthermore, it is understood that each customer premises 330 may be connected (directly or indirectly) to a subset of the feeder lines 320 in contrast to the example illustrated, in which every feeder line 320 is connected to the collective representation of the plurality of customer premises 330.
The transmission line switch 312 are connected to a utility network 340. Similarly, each high-side TX interrupter 314 are connected to the utility network 340 via a data monitor 342 installed at each of the K number of substations 304. The data monitor 342 are implemented, for example, as a computing device (e.g., a programmable logic controller or a general purpose computer). The data monitor 342 includes a utility network interface (UNI) 344 for communicating on the utility network 340. The utility network interface 344 could be a wireless or wired network interface card configured to communicate on the utility network 340. The utility network 340 could be a mesh network, such as an Internet Protocol version 6 (IPv6) network or a network that employs the Transmission Control Protocol/Internet Protocol (TCP/IP).
For purposes of simplification of explanation, individual connections between the utility network 340 and each data monitor 342 are omitted. Instead, a collective connection between each substation 304 and the utility network 340 is included to collectively represent communications between components within a respective substation 304 and the utility network 340. The transmission line switch 312 and each high-side TX interrupter 314 provides switch data characterizing an operating state (e.g., tripped, open or closed). Additionally, each three-phase voltmeter 322 provides voltage data characterizing a (real-time) measured voltage for each phase of a respective feeder line 320 to the corresponding data monitor 342.
A utility server 350 (e.g., a computer system) can also be connected to the utility network 340 via a utility network interface 352 (e.g., a network interface card). The utility server 350 are implemented by a utility provider (e.g., a power provider), such as a utility provider that controls the K number of substations 304 and/or the power provider 302. The utility server 350 includes memory 354 to store machine executable instructions. The memory 354 are implemented as a non-transitory machine readable medium. The memory 354 could be volatile memory (e.g., random access memory), non-volatile memory (e.g., a hard drive, a solid state drive, flash memory, etc.) or a combination thereof. The utility server 350 includes a processing unit 356 (e.g., one or more processor cores) that accesses the memory 354 and executes the machine readable instructions.
In some examples, the utility server 350 are (physically) implemented at facilities controlled by the utility provider. In such a situation, the utility server 350 could be representative e of multiple servers (e.g., a server farm). Additionally or alternatively, the utility server 350 (or a portion thereof) are implemented in a remote computing system, such as a computing cloud. In such a situation, features of the utility server 350, such as the processing unit 356, the utility network interface 352 (and/or other network interfaces) and the memory 354 could be representative of a single instance of hardware or multiple instances of hardware with applications executing across the multiple of instances (i.e., distributed) of hardware (e.g., computers, routers, memory, processors, or a combination thereof). Alternatively, the utility server 350 could be implemented on a single dedicated computing device.
The utility network 340 can, in some examples, be implemented on (e.g., connected to) a public network, such as the Internet, a private network (e.g., a proprietary network) or a combination thereof (e.g., a virtual private network). In this manner, the utility server 350 establishes a bi-directional communication with each of the K number of data monitors 342 (or some subset thereof) via the utility network 340. Similarly, the utility server 350 establishes a bi-directional communication with the transmission line switch 312 that may be outside the K number of substations 304.
The memory 354 stores application software for controlling operations of the utility provider. In some examples, the application software can include operations as part of a power delivery diagnostic center (PPDC) and/or a supervisory control and data acquisition (SCADA) system. For example, the memory 354 stores application software for processing and billing systems, various monitoring, customer service, troubleshooting, maintenance, load balancing, accounting and other types of activities that may be used to operate a utility provider.
The memory 354 includes a graphical user interface (GUI) 360 that operates as a front end for a distribution outage planning tool (DOPT) 366 which may be communicatively coupled with other systems such as defect detector that monitors data generated by the components of the substations 304 and/or the transmission line 306 to detect potentially improper operation and/or equipment damage. More particularly, the DOPT 366 with the defect detector may monitors the switch data from the transmission line switch 312 and each of the J number of high-side TX interrupters 314 at each of the K number of substations 304 as well as voltage data from each of the three-phase voltmeters 322. The monitored data are employed, for example, to identify a potential open pole (or other defect) on the transmission line switch 312 and/or on a high-side TX interrupter 314. In some examples, switch data from the high-side TX interrupters 314 and/or the transmission line switch 312 and/or voltage data from the three-phase voltmeters 322 are provided directly to the utility server 350. In other examples, switch and/or voltage data may be provided from another server (e.g., operating on a SCADA system).
To demonstrate operations of the utility server 350, several extended examples are provided. In a first example, (hereinafter, “the first example”), it is presumed that the high-side TX interrupter (1,J) (labeled “SW (1,J)”) has been tripped, opened and reclosed (e.g., toggled). In this situation, the high-side TX interrupter (1,J) provides switch data to the data monitor 342 of the first substation 304.
In response to detecting toggling (e.g., tripping, opening and/or closing) of the high-side TX interrupter 314 the DOPT 366 through a defect detector monitors the voltage data from three-phase voltmeters 322 for each of the feeder lines 320 downstream of the high-side TX interrupter 314 for a predetermined amount of time (e.g., 5-20 minutes). More particularly, in the first example, in response to toggling of the high-side TX interrupter (1,J), the DOPT 366 through a defect detector monitors the voltage data from voltmeters (1,J,1), (1,J,2) and (1,J,3).
A requestor 380, can place service requests through the secure network 370 to DOPT application 366 running on the utility server 350. The requestor may be using a requestor device 382 running a program with a graphical user interface, such as a wireless portable device or smartphone, tablet, laptop, or access a dedicated webpage. The data in the request may be in different non-standardized format dependent on the hardware and software platform used by the one of the requestors. The utility server 350 converts the non-standardized information into the standardized format and stores this standardized updated information in the memory 354. Using this standardized data the system can start processing a request as described in
In still another embodiment, smart meter data is used to help generate an order. Examples of how smart meter technology may be used is found in U.S. patent application Ser. No. 16/110,260 filed on Aug. 23, 2018 with inventors Bryan J. Olnick et al. entitled “Proactive Power Outage Impact Adjustments Via Machine Learning”, Attorney Docket Number 089174 and U.S. patent application Ser. No. 15/443,358 filed on Feb. 27, 2017 with inventors Giovanni Herazo et al. entitled “Remote Tracking Of Automatic Lateral Switch Operations”, Attorney Docket Number 083972, the teachings of each of these two references is hereby incorporated by reference in their entirety. The use of data from a smart meter at a customer or a business premise and other orders are partially generated based on artificial intelligence (AI) failure prediction process. The AI analyzes data from a multiplicity of smart meters. This AI order may be only a portion of a request or fill the entire request.
Continuing further, the present invention provides a distribution outage planning tool (DOPT) 366 that coordinates the scheduling of maintenance tasks (e.g., work orders) on a power distribution system. The DOPT includes a conflict resolution module and a work validation module. The conflict resolution module ensures that work order requests are permissible based on currently pending work orders before scheduling each work order. Upon scheduling non-conflicting work orders, the work validation module is configured to request verification that work for a pending work order is actually going to commence and provides the option to reschedule the work order.
More particularly, the DOPT includes a conflict resolution module receives a stream of work order requests. Each work order request includes a time and date, a component identifier identifying the electrical equipment requiring serviced and a code characterizing the type work that will be executed. The conflict resolution module includes a plurality of configurable rules characterizing permissible and impermissible work orders based on a timing of existing work orders. As an example, the rules may specify that during a time window assigned to a given work order for given transmission line or feeder lines, no other work can commence on the given feeder and/or connecting feeder lines. Conversely, in that same situation, work order requests for a relay upstream of the given feeder may be permitted during the same time window as the given work order. Accordingly, the work order request for work on the relay upstream of the given feeder line is accepted and scheduled as another work order. Thus, the conflict resolution module obviates the need for manual (and often inaccurate) review of work orders.
Further, the DOPT includes a work validation module shown as flow 400 in
By employing the DOPT the manual review of work orders requests are obviated. Additionally, time lost due to work orders for work that does not actually commence (but is scheduled) are curtailed.
If an outage is scheduled at one point in a distributed electrical power grid, then power is also cut to downstream resources. Thus, if planned work are scheduled on downstream resources while power is out due to work on upstream resources then there's an improvement because the overall customer outage time is reduced (the customers of the downstream element only experience one instead of two outages due to an improved scheduling process).
The flowchart and block diagrams in the figures illustrate the architecture, functionality, and operation of possible implementations of systems, methods, and computer program products according to various embodiments of the present invention. In this regard, each block in the flowchart or block diagrams may represent a module, segment, or portion of instructions, which comprises one or more executable instructions for implementing the specified logical function(s). In some alternative implementations, the functions noted in the blocks may occur out of the order noted in the Figures. For example, two blocks shown in succession may, in fact, be executed substantially concurrently, or the blocks may sometimes be executed in the reverse order, depending upon the functionality involved. It will also be noted that each block of the block diagrams and/or flowchart illustration, and combinations of blocks in the block diagrams and/or flowchart illustration, are implemented by special purpose hardware-based systems that perform the specified functions or acts or carry out combinations of special purpose hardware and computer instructions.
Turning now to
Next, the process immediately proceeds to step 404 in which a request for switching order is created. The process continues to step 406.
In step 406 a test is made to determine if the request is a rush request or a normal request. In the case of a rush request, the process flows to step 410. Step 410 is a prior flow, which is outside the scope of the present invention. In the case of the request not being a rush request, the process continues to step 412.
In step 412, a calendar conflict check is performed. The purpose is to check for any other previously scheduled outage of the same components for a given time and given date. In response to a previous scheduled outage already planned, the process continues to step 470 in which the request is changed to modified status (RMOD) and sent back to the requestor. This RMOD will be discussed further below. Otherwise, if there is no calendar conflict, the process continues to step 416. The status of the request is change to temporary new status (SNEW), that is new on the schedule, and the process continues to step 418.
It is important to note that in one example any downstream sources that will be de-energized during a work order for an upstream component can be identified. The system may optionally reschedule any previously downstream equipment maintenance to be during the same time the upstream equipment is being maintained. Other determining factors like availability of crews, availability of maintenance parts, length of relative maintenance of each piece of electrical equipment is also determined The order and the at least one pending previous order is scheduled on a same date.
Unlike prior solutions, the present invention provides a unique improvement because the overall customer outage time is reduced. State differently, the customers of the downstream element only.
In step 418, a first notification (CN1) and verification (CR1) are performed. The parameters of this CN1 and CR1 are configurable. For example, one configurable parameter is an amount of time (e.g. hours, days, weeks, months) before request start date. The notification may be a text, email, automated interactive voice response system or other notification in which the requester starting the request in step 402 must give a response or answer. This type of notification may also be configurable. One this first verification is confirmed, the process moves from temporary SNEW status to just NEW status. It is only when the NEW status is achieved that a switching lead can reviews the request.
There are three possibilities with the response to CN1 as follows: i) no response, ii) response or iii) response with new date. In the case, there is no response to CN1, in step 416, the process continues to step 460. Otherwise, in the case there is a response received with in the configurable time the process continues to step 420. Otherwise, the requestor is asking for new date for the request in which the process flows back to step 412.
Step 460 is a cancelled status (CNCL). Note one of the benefits of the present invention at this point in time is these is not work done by the distribution control center (DCC). At this point, the request can be cancelled. This CR1 test ensures that there was no wasted effort by the DCC. The flow ends after step 440. Otherwise, the process continues to step 420 in which the status NEW is maintained and the process continues to step 422.
At this point in time, the control center switching lead (CCSL) is aware of the initial request. In step 422, a test is made. Specifically, the test determines whether the control center switching lead (CCSL) sends request back to requestor. The reasons to send the request back to the requestor includes not enough details in the initial request or power loads are too high because of seasonal demand during the specific requested time period. In the case that the CCSL sends request back to requestor, the process goes to modification status RMOD in step 450. Otherwise, in the case the CCSL does not sends request back to requestor, the process continues to step 424.
In step 424, a test is made. More specifically the test is whether a new or edited power quality (PQ) steps are required. In the case no new power steps are required the process continues to step 432 with an approved status (APPY). Otherwise with new PQ steps required, the process continues to step 426.
In step 426, new PQ steps are composed. Power quality steps may address-high harmonic in distribution system, low power factor, voltage transients, voltage flicker, active power and reactive power and to ensure customer load is not lost during the switching process. Due to poor power quality the performance of various sensitive loads is very poor. Once the new PQ are written, the process continues to step 428. In parallel to the process continuing to step 428, a second path is taken. Specifically this second path is a second notification (CN2) is dispatched step 452. Like CN1 this CN2 has configurable parameters including time periods and how the notification is sent, for example, by email, text, interactive voice system, or other systems, which record an answer. However, unlike CN1, at this point in this flow, the control center switching lead and perhaps a dispatcher has already begun work. Rather than cancel the request, the system tries to modify the request for increase efficiency.
In step 428, the new PQ steps are part of the request are placed as evaluation status (EVAL). Next, the orders are created and written in step 430. These orders are typically written out by a first dispatcher. The process continues to step 432 in which the approve status (APPV) is set. The process continues to step 434 in which the steps on the order are rechecked. The rechecking is typically performed by a second dispatcher. The process continues to step 436.
Step 436 is a Boolean AND logic. Both the steps of i) the order check and ii) a response to notification CRS received in step 454 must be successful for the process to continue.
The response for step 454 is a final check. In step 454, three responses are possible as follows: i) no, ii) different date, or no answer. In the case the response is “no”, just like a response not received with the first notification CN1, the process goes to step 460 in which the order is set with cancelled status (CNCL). If the response is a different date the process returns to step 412 for a calendar check. In the case there is no answer, a test is made in step 448.
In step 448 a test of the request end date being equal to today. This test makes sure that previous scheduled work may still be scheduled. If it is equal to today, then there is not enough time to carry out the order and the request date is automatically reset to tomorrow in step 450. The process returns to step 452 for a second notification CN2. Otherwise, if the request date in step 448 is not end date of today, the process continues to step 470 with a modified status (RMOD).
Once the Boolean AND gate logic has both successfully received the i) the order check and ii) a response to notification CRS received in step 454, only at this point does the process continues to step 438. In step 438, a test is made to see if a crew solicits the system for a request. In the case the crew solicits the system in the process continues to step 440.
In an optional embodiment, as part of step 440, the system automatically identifies at least one switchgear and/or one or more reclosers in the distributed electrical power grid that controls the at least one piece of selected electrical equipment. Next, the system automatically sends a control signal to the switchgear and/or the reclosers to maintain a lockout stage during a scheduled maintenance period in the request. The lockout stage prevent re-energizing the at least one piece of selected electrical equipment during a scheduled maintenance period in the request.
In step 440, a test is made if all the order required for the request are completed. If yes, the process finishes in step 444. Otherwise, the orders that ware not completed are tracked by going back to step 448 to determine the request dates.
In the RMOD status in step 470, the process continues to step 472 to see if a settable time-period pass the RMOD date has elapsed. If the time has elapsed, the process gods to step 476 in which the request is set to cancelled status (CNCL). Otherwise, in the case the time-period has not passed, the process goes to step 476 in which request is resubmitted and returns to step 406 to set the status to temp (TEMP). If request is in RMOD for configurable x for a time-period (hours, days, weeks, months), it will then be cancelled. If the request is resubmitted before reaching the time-period it will then move to TEMP status and go back through Calendar Conflict. This is typically sent in a configurable time-period before the request date. For example, a one day before verification for the first order will be based on the request start date. The remainder of the day before verifications will be based on the order start date.
Although specific embodiments of the subject matter have been disclosed, those having ordinary skill in the art will understand that changes are made to the specific embodiments without departing from the spirit and scope of the disclosed subject matter. The scope of the disclosure is not to be restricted, therefore, to the specific embodiments, and it is intended that the appended claims cover any and all such applications, modifications, and embodiments within the scope of the present disclosure.
What is claimed is:
