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A Distribution Transformer Monitor (DTM) is a specialized hardware device that collects and measures information relative to electricity passing into and through a distribution transformer. The DTM is typically retrofitted onto pole top and pad mount transformers. A pole top (above ground) or pad mount (below ground) transformer commonly powers anywhere from 5-8 homes in the US and is the last voltage transition in stepping down voltage before it gets to the home or business. [1] The conventional placement of Distributed Temperature Monitoring (DTM) devices is typically observed at the terminals of transformers. However, there are instances where these devices are directly affixed to the secondary power lines.
DTM apparatus commonly comprises precision-centric sensors, either of the non-piercing or piercing variety, in addition to communication modules integrated on board for seamless data transmission. Adequate provisions for power supply are also incorporated within the DTM setup. The captured data from the DTM unit is relayed to a central data collection engine and/or the established Supervisory Control and Data Acquisition (SCADA) / Meter Data Management (MDM) system, where pertinent information pertaining to the transformer is stored and made accessible to users. Often, analytical platforms come into play to decipher the data gleaned and reported by the DTM, thereby enhancing the comprehension of the acquired information.
The Distribution Transformer Monitoring (DTM) system, often referred to as an intra-grid sensor, occupies a distinctive position within the distribution grid. It is capable of providing both real-time and historical data about the transformers it monitors. Beyond individual transformer monitoring, DTMs constitute crucial information access points within the grid's architecture. When deployed in a network across the distribution grid, these devices offer multiple data points. For electric utility operators, these data points can range from basic bellwether measurements to comprehensive insights into intra-grid conditions and performance, depending on the deployment density.
The strategy for deploying DTM devices varies according to the specific needs and objectives of the utility in question. Deployments may be surgical, meaning strategically limited to key areas of the grid, or they can be comprehensive, covering larger grid sections such as line segments, specific circuit feeders, or entire substations. The decision on the placement and density of DTM deployments is influenced by the targeted data requirements and operational goals of the respective electric utility.
Remote Over-The-Air (OTA) updates/upgrades are supported by certain DTM device offerings. This OTA capability, when supported, allows the operator to perform remote configuration and/or executable code (i.e., Firmware) updates of the DTM device(s) without the need for costly truck rolls or unit replacement. By supporting OTA Firmware updates/upgrades, providers can progressively broaden and deepen the suite of data points captured by the DTM device, making it reasonably future-proof, thus escalating value and relevance to the utility operator throughout the lifespan of the DTM device(s).
DTM sensors transmit timely, accurate intra-grid readings for Voltage, Energy, Current, and Temperature, thus empowering a long list of derived performance and power quality understandings for operations personnel. [2] These fundamental data points provide direct relevance to electric utility operators. Additionally, these data points can be extrapolated to reveal enhanced grid performance and asset health information. Given the physical location of the DTM within the heart of the distribution grid, in addition to the DTM reporting frequency capability, the versatility of this intra-grid sensor is expansive.
Utilities across the U.S. are beginning to turn to transformer technologies to improve distribution reliability and efficiency, as well as customer service and operating costs. [3]
Examples of applications derived from direct and/or indirect information presented by the DTM include:
Given the physical deployment position of the DTM (i.e., on the distribution transformer), there are no known health concerns related to this family of intra-grid sensors. DTM devices are created with user/installer safety in mind and otherwise bear no known measurable environmental impact.
Utility spending on asset management and grid monitoring technology is to hit almost $50 billion by 2023, according to a new study from Navigant Research. [4] Given the pioneering stage of the DTM technology, significant business case information is limited in availability for public review. Arguments against DTM deployment commonly assert that the secondary transformer value of $1000.00 to $2000.00 US (average) does not justify applying a retrofit DTM to monitor the transformer assets’ performance. However, the DTM value is based upon a combination of features/benefits that include not only the transformer condition monitoring importance, but also a series of data visibility and reconciliation features from within the heart of the distribution grid that is otherwise unavailable to the electric operator (see Applications).
In essence, while the Advanced Metering Infrastructure (AMI) or smart meter providers supply a series of data points to utilities, the DTM offers another dimension of real-time and historical data access for the grid operator and is capable of detecting information that AMI assets cannot capture and/or report with the necessary frequency to the operator. Each utility must evaluate, among other things, their unique grid management needs, their levels of unidentifiable losses that can be remediated/mitigated by DTM deployment, their Demand Response savings potential through Volt/VAR and conservation voltage reduction (CVR) related practices supported by DTM devices, and their need for real-time and/or historic data from within the heart of the distribution grid when formulating their business case justification. Investment decisions relating to DTM deployments involve a collection of monetary benefits that include savings for the utility through decreased operations costs, reduced power outages, lessened power outage durations, reduced peak demand costs, and recoverable power theft losses; and indirect financial benefits associated with improved power delivery and quality to rate payers, reduced truck rolls which lessen service costs in addition to yielding decreased environmental impacts, improvement of the utility's Key Performance Indicators (e.g., SAIDI, SAIFI, CAIDI, etc.), and improved stakeholder/shareholder value through enhanced bottom line fiscal performance by the utility.
Relevance to the smart grid: Distribution Transformer Monitor (DTM) devices provide a solution to the smart grid revolution. GTM Research (a division of Greentech Media) expects strong growth from the U.S. market for transformer monitoring hardware, increasing its current valuation of $112 million annually to $755 million by 2020. [5] To date, smart grid providers have presented electric utility operators with significant management and control tools for substations, and have introduced Advanced Metering Infrastructure (AMI, or smart meters) to improve data access at the beginning and endpoints within the distribution grid. However, the expansive, and arguably most vulnerable segment of the grid remains the section between substations and endpoint meters—comprising over 6 million line miles (US grid), and 40+ million distribution transformers (US grid) -- which is now collectively coined the "heart of the grid".
Presently, the “heart of the grid” area is somewhat devoid of a sufficient density of versatile, cost-effective sensors, thereby leaving operators with limited visibility into this critical area. To further evolve from a traditional reactionary management and problem resolution state within the “heart of the grid” space, to a more proactive posture that is congruent with the purpose and value of a ‘smart grid’, the emergence of the DTM is timely. While efforts have been made to leverage substation and endpoint meter data, along with supporting algorithms to speculate and postulate occurrences and needs within the “heart of the grid”, it is evident that grid operators require precision-accurate, timely information from within this expansive segment of the grid in order to proactively and efficiently manage its performance. The need to effectively combine all three critical points of measure (i.e., substations, endpoint meters, and DTM data from within the “heart of the grid”) may be collectively required to advance a comprehensive smart grid experience.
Why Distribution Transformer Monitors are fundamental for creating Grid Modernization—Achieving valuable results that Advanced Meter Infrastructure cannot reliably address:
Power-line communication (PLC) is the carrying of data on a conductor that is also used simultaneously for AC electric power transmission or electric power distribution to consumers. The line that does so is known as a power-line carrier.
Distributed generation, also distributed energy, on-site generation (OSG), or district/decentralized energy, is electrical generation and storage performed by a variety of small, grid-connected or distribution system-connected devices referred to as distributed energy resources (DER).
A substation is a part of an electrical generation, transmission, and distribution system. Substations transform voltage from high to low, or the reverse, or perform any of several other important functions. Between the generating station and consumer, electric power may flow through several substations at different voltage levels. A substation may include transformers to change voltage levels between high transmission voltages and lower distribution voltages, or at the interconnection of two different transmission voltages. They are a common component of the infrastructure. There are 55,000 substations in the United States.
Automatic meter reading (AMR) is the technology of automatically collecting consumption, diagnostic, and status data from water meter or energy metering devices and transferring that data to a central database for billing, troubleshooting, and analyzing. This technology mainly saves utility providers the expense of periodic trips to each physical location to read a meter. Another advantage is that billing can be based on near real-time consumption rather than on estimates based on past or predicted consumption. This timely information coupled with analysis can help both utility providers and customers better control the use and production of electric energy, gas usage, or water consumption.
An electricity meter, electric meter, electrical meter, energy meter, or kilowatt-hour meter is a device that measures the amount of electric energy consumed by a residence, a business, or an electrically powered device over a time interval.
Power-system automation is the act of automatically controlling the power system via instrumentation and control devices. Substation automation refers to using data from Intelligent electronic devices (IED), control and automation capabilities within the substation, and control commands from remote users to control power-system devices.
Advanced Distribution Automation (ADA) is a term coined by the IntelliGrid project in North America to describe the extension of intelligent control over electrical power grid functions to the distribution level and beyond. It is related to distribution automation that can be enabled via the smart grid. The electrical power grid is typically separated logically into transmission systems and distribution systems. Electric power transmission systems typically operate above 110kV, whereas Electricity distribution systems operate at lower voltages. Normally, electric utilities with SCADA systems have extensive control over transmission-level equipment, and increasing control over distribution-level equipment via distribution automation. However, they often are unable to control smaller entities such as Distributed energy resources (DERs), buildings, and homes. It may be advantageous to extend control networks to these systems for a number of reasons:
A smart meter is an electronic device that records information—such as consumption of electric energy, voltage levels, current, and power factor—and communicates the information to the consumer and electricity suppliers. Such an advanced metering infrastructure (AMI) differs from automatic meter reading (AMR) in that it enables two-way communication between the meter and the supplier.
In electrical engineering, a load profile is a graph of the variation in the electrical load versus time. A load profile will vary according to customer type, temperature and holiday seasons. Power producers use this information to plan how much electricity they will need to make available at any given time. Teletraffic engineering uses a similar load curve.
A phasor measurement unit (PMU) is a device used to estimate the magnitude and phase angle of an electrical phasor quantity in the electricity grid using a common time source for synchronization. Time synchronization is usually provided by GPS or IEEE 1588 Precision Time Protocol, which allows synchronized real-time measurements of multiple remote points on the grid. PMUs are capable of capturing samples from a waveform in quick succession and reconstructing the phasor quantity, made up of an angle measurement and a magnitude measurement. The resulting measurement is known as a synchrophasor. These time synchronized measurements are important because if the grid’s supply and demand are not perfectly matched, frequency imbalances can cause stress on the grid, which is a potential cause for power outages.
Load management, also known as demand-side management (DSM), is the process of balancing the supply of electricity on the network with the electrical load by adjusting or controlling the load rather than the power station output. This can be achieved by direct intervention of the utility in real time, by the use of frequency sensitive relays triggering the circuit breakers, by time clocks, or by using special tariffs to influence consumer behavior. Load management allows utilities to reduce demand for electricity during peak usage times, which can, in turn, reduce costs by eliminating the need for peaking power plants. In addition, some peaking power plants can take more than an hour to bring on-line which makes load management even more critical should a plant go off-line unexpectedly for example. Load management can also help reduce harmful emissions, since peaking plants or backup generators are often dirtier and less efficient than base load power plants. New load-management technologies are constantly under development — both by private industry and public entities.
The smart grid is an enhancement of the 20th century electrical grid, using two-way communications and distributed so-called intelligent devices. Two-way flows of electricity and information could improve the delivery network. Research is mainly focused on three systems of a smart grid – the infrastructure system, the management system, and the protection system. Electronic power conditioning and control of the production and distribution of electricity are important aspects of the smart grid.
An electrical grid is an interconnected network for electricity delivery from producers to consumers. Electrical grids consist of power stations, electrical substations to step voltage up or down, electric power transmission to carry power over long distances, and finally electric power distribution to customers. In that last step, voltage is stepped down again to the required service voltage. Power stations are typically built close to energy sources and far from densely populated areas. Electrical grids vary in size and can cover whole countries or continents. From small to large there are microgrids, wide area synchronous grids, and super grids. The combined transmission and distribution network is part of electricity delivery, known as the power grid.
Meter data management (MDM) refers to software that performs long-term data storage and management for the vast quantities of data delivered by smart metering systems. This data consists primarily of usage data and events that are imported from the head-end servers managing the data collection in advanced metering infrastructure (AMI) or automatic meter reading (AMR) systems. MDM is a component in the smart grid infrastructure promoted by utility companies. This may also incorporate meter data analytics, the analysis of data emitted by electric smart meters that record consumption of electric energy.
FNET is a wide-area power system frequency measurement system. Using a type of phasor measurement unit (PMU) known as a frequency disturbance recorder (FDR), FNET/GridEye is able to measure the power system frequency, voltage, and angle very accurately. These measurements can then be used to study various power system phenomena, and may play an important role in the development of future smart grid technologies. The FNET/GridEye system is currently operated by the Power Information Technology Laboratory at the University of Tennessee (UTK) in Knoxville, Tennessee, and Oak Ridge National Laboratory (ORNL) in Oak Ridge, Tennessee.
The OpenHAN standards for home networks was promoted by groups such as openAMI and UtilityAMI. Both efforts aim to standardize powerline networking interoperation from a utility point of view and ensure reliable communications co-extant with AC power outlets. Both utilities and vendors of home control have promoted such standards aggressively. The openHAN label usually denotes standards favored by the utilities, not other service providers. It should be distinguished from the openADR standards that were promoted to ensure open access to customer electricity use data by all service providers.
Smart grid policy in the United States refers to legislation and other governmental orders influencing the development of smart grids in the United States.
A distribution management system (DMS) is a collection of applications designed to monitor and control the electric power distribution networks efficiently and reliably. It acts as a decision support system to assist the control room and field operating personnel with the monitoring and control of the electric distribution system. Improving the reliability and quality of service in terms of reducing power outages, minimizing outage time, maintaining acceptable frequency and voltage levels are the key deliverables of a DMS. Given the complexity of distribution grids, such systems may involve communication and coordination across multiple components. For example, the control of active loads may require a complex chain of communication through different components as described in US patent 11747849B2
The UCLA Smart Grid Energy Research Center (SMERC), located on the University of California Los Angeles (UCLA) campus, is an organization focused on developing the next generation of technologies and innovation for Smart Grid. SMERC partners with government agencies, technology providers, Department of Energy (DOE) research labs, universities, utilities, policymakers, electric vehicle manufacturers, and appliance manufacturers. These partnerships provide SMERC with diverse capabilities and exceptional, mature leadership.
In Iran, like many other developed countries, Smart Grid implementation is regarded as a unique way for encountering many serious environmental and economic challenges that mankind is faced today. FAHAM is the National Smart Metering Program in Iran. The functional, technical, security, economic, and general requirements of this project was published as a document after a longtime workgroup of various stakeholders including representative of grid operators, meter manufactures, communication providers, business layer software providers, domestic and international consultants. The procedure of producing this document was base on EPRI Methodology. In these technical documents all of the business and functional use cases, the conceptual architecture, mandatory international standards for electric, water and gas metering systems(for all types of consumers), telecommunication requirements, system interfaces and security mandates are defined. The ministry of energy decided to perform a pilot project called FAHAM-phase1, in order to experiment the execution and technical challenges for implementing Smart Metering for all of the consumers.