Load Forecasting- Foundational Step for Enabling Energy Transition.

 

Source- ESIG- 2023 Long Term Forecasting Workshop

The era of stagnant load growth is over. With the upcoming electrification of heat and transport driven by the need for reducing carbon emissions, our electricity consumption is forecasted to double. This forecasted electricity growth transforms the existing planning process- the electric system will change from summer peaking to winter peaking, it changes periods of resource adequacy, planning on transmission and distribution system, availability of generation resources, and everything in between. The task of identifying that the electric load will be is the task of Long-Term Forecasting process.

This Long-Term Load Forecasting is the foundational process for a utility’s operations. These long-term forecasting often look ahead 10 years in ahead in the future and anticipate what the load will be in the future. Based on this plan, the electric utility then plans for development of its infrastructure to be able to meet the electric demand. In an energy market, the load term forecasting provides the market signal the price for Forward Capacity Market, development of Transmission Planning, process for Generation Interconnection, and other processes.

Long term forecasting consists of econometric models based on historical load growth and weather, which is then adjusted based on exogenous forecasts of various factors including energy efficiency, state policy, building electrification, transportation electrification, and other trends. Proper load forecasting needs a strong understanding of the emerging trends, and how these impact the electric load in the future.

Load forecast provides future energy load, but also future demand. The demand modeling provides what the future electric peak load will look like. Using historical weather history (30+ years), a weekly weather distribution is developed that provides what is the total variance of the weather that will be in each week. For each week a Weighted Temperature Humidity Index (WTHI) is used to forecast the demand for each week.

The forecasts provide 50/50 and 90/10 load. The 50/50 load forecast is the load that has a 50% probability of the forecast will exceed. 90/10 load forecast is that there is a 10 percent probability that the forecast will exceed. In other words, the 50/50 load level is a peak demand that is expected every two years, 90/10 is the extreme weather level that is expected once every ten years. The Transmission Planners use the 90/10 peak demand data to plan the load to plan for meeting system reliability to meet all the expected peak. For other resource adequacy measure planners can use the 50/50 peak.

With the energy transition, there is a wide variability in the future load in terms of forecasted solar PV installs, energy storage system, installed wind energy, electric vehicles, and electrification of buildings. These provide a challenge in terms of being able to forecast exactly what the future load will look like. With electrification of the building, the system transitions into a winter peaking system from summer peaking system. The high adoption of solar PV transitions the daily load curve into a duck curve with a sharp peak during in the evenings. Electric Vehicles double the use of electric use.

Our society's successful energy transition relies on accurate load forecasting, providing critical insights into the future grid. This enables the integration of clean energy, resource balancing, adequate energy reserves, and robust transmission infrastructure. As the energy landscape evolves, embracing advanced technologies, distribution-level forecasting, enhanced weather forecasting, and scenario planning will be essential for accurate and reliable load forecasting.

Energy Storage Design

We owe it to electric power system for enabling our modern society. The  electricity is divisible, transportable, and can be converted to other energy forms which all makes it the most convenient form of energy. The challenge with electric power system has been that the lack of storage ability. This means that for most part the electricity that we use in our everyday lives is generated instantly as we consume it. Large part of the electrical engineering, design, and effort goes into maintain this intricate balance between the supply and demand.  Energy storage technologies are exciting part of the power engineering as it changes the old status quo. However, the energy storage technologies are cost prohibitively expensive for everyday practical use and limited cases.

Energy storage can be categorized into two types- inverter based resources and generator based resources. Generator based resources have been the traditional energy storage system such as pumped hydro but they have limited availability. The inverter based resources are the battery storage systems, which are more popular systems.

When considering energy storage technologies for grid use, we need to think about four main parameters – i) voltage, ii) real power, iii) reactive power, and iv) energy capacity. The fourth parameter is unique to energy storage as energy storage system only have limited availability and grid planner needs to consider.

For implementing a energy storage, we could conduct a time series loading analysis. With Energy storage, we need consider both charging and discharge situation as well.

Implementing an energy storage project involves steps below:

1. Identifying Need: This involves planning, time series analysis, and power flow modeling to determine where energy storage can be most beneficial.
2. Conceptual Design: Developing an operational and use case procedure, conducting transient and steady-state analyses to design a system that meets the identified needs.
3.  Initial Engineering Design: Includes land assessment, interconnection study, and protection studies to lay the groundwork for the storage system's integration into the grid.
4. Detailed Engineering Design: Focuses on grounding study, equipment study, and harmonic study to ensure the system's technical and safety requirements are met.
5. Community Outreach: Engaging with the community, obtaining necessary permits, and ensuring stakeholder support are crucial for successful project implementation.

Dynamic Line Ratings

Building new transmission lines can be prohibitively expensive. It's not simply a matter of erecting poles and wires; obtaining essential environmental and land use permits from communities and localities can be especially challenging. Transmission lines dictate how much bulk power flows through the system. In situations where the transmission system is constrained and building new lines is not an option, how can we maximize the use of existing transmission lines? This is where Dynamic Line Ratings (DLR) come into play. As discussed below, DLR represents a new paradigm for assessing transmission line capacity and utilizing them to their maximum potential while staying within safety limits.

Physics of Dynamic Line Ratings
The amount of electricity that transmission lines can conduct is limited by several factors, including conductor type, size, voltage level, distance, and environmental conditions. For existing transmission lines, size, type, distance, and voltage are fixed parameters. One major environmental factor affecting transmission lines is temperature. Each transmission line has a maximum temperature limit; when it heats up, it can sag, reaching a maximum sag limit as well. Environmental temperature fluctuates with time and season. DLR adjusts the capacity of transmission lines based on real-time ambient conditions and actual field measurements. This approach contrasts with previous static line ratings, which were fixed and only varied seasonally without real-time measurements.

While the concept seems straightforward, DLR can be complex because actual conditions depend on multiple factors, including wind, ambient temperature, solar irradiation, and others, all of which influence the line rating calculation. Among these factors, wind has the greatest cooling effect on the lines.

Source- ISGAN- https://www.youtube.com/watch?v=xzWoQkVVhFc

As shown in the image above, the transmission capacity doubles from 1000 A to 2000 A as wind speed increases from 0.5 m/s to 5 m/s. The actual calculation of DLR can be intricate. IEEE 738 provides a thermal model for the application and calculation of real-time monitoring and modeling of transmission lines, used in practical applications. The model considers factors such as clearance, temperature, current, and weather parameters to calculate the gains and limits, providing the dynamic ampacity of the transmission line.

These parameters can be based on field measurements or model-based simulations; however, field-based monitoring generally offers higher accuracy.

Sensor installation technologies can be classified into four types, ranked chronologically:

1. Line-mounted sag sensor: Measures sag, wind, and temperature to calculate conductor temperature and clearances. This method provides the highest accuracy for DLR.
2. Line-mounted clearance sensor: Measures clearances, inclination, and vibration to infer sag and conductor temperature.
3. Line-mounted conductor temperature sensor: Measures conductor temperature and inclination to infer sag.
4. Indirect sensors: Do not measure parameters directly on the transmission lines but use information from weather stations and modeling. This is the least accurate method.

Uses

1. Underground: While DLR is primarily used for overhead lines, there are techniques for applying it to underground lines as well; however, the benefits are greater for overhead lines.
2. AC vs DC: Currently, DC circuits cannot use DLR sensors because these sensors are powered by induction from AC lines. In static DC lines, these sensors cannot be powered with existing methods.
3. Voltage applications: DLR can be applied from 20 kV to 800 kV.

Questions and Challenges

Although implementing DLR technologies seems straightforward, there are market and technical challenges to widespread adoption:

• Rethinking market incentives: In market-based systems, a key question is whether the incentives are aligned for transmission system owners to implement DLR. Revenues for transmission system owners vary by region, market, or product. In some cases, higher transmission constraints lead to higher transmission capacity prices. Can this be balanced through increased electricity throughput? Are there other direct incentives for transmission owners to adopt DLR technologies?
• Rethinking grid operations: Traditional grid operation methods use static capacities for transmission lines. Transitioning to a dynamic method with field sensors complicates system operations. Do system operators have the capacity to monitor, control, and settle markets at this level?
• Forecasting methodology: Transmission operations depend on load forecasting, capacity, and generation to meet demand. How does this process evolve with DLR implementation?

DLR is a proven technology already used in places like Germany and Belgium. In the US, FERC is actively looking to implement DLR in the wholesale market. While in 2021, the FERC order 881 required the transmission companies to require dynamic line ratings that accurately reflect the system, that is just the first step. As mentioned above, implementation of DLR has several challenges. FERC is now looking to reform the market rules such that DLR can be effectively implemented in the whole system. With the intent FERC, it is just a matter of time when DLR becomes a norm in the US market, which is a logical step forward for the energy market. 

Grid Forming Inverters Part 2

Grid Forming Inverters (GFIs) are a new generation of inverters designed to address the challenges faced by Inverter-Based Resources (IBRs) in an inverter-dominated field. The traditional goal of existing inverters is to maximize current output to the grid, with minimal additional capabilities. However, as IBRs become more popular, there is a need for additional functions from these inverters, such as automatic voltage control, capability to provide frequency response, fast frequency response, and system stability maintenance. These features are typically provided by traditional synchronous generators.

In a system dominated by synchronous generators, when an IBR generator provides input into the system, the IBRs follow the grid frequency, making them Grid Following Inverters (GFL). However, in a future scenario with fewer synchronous generators and less inertia in the system, the additional GFL IBRs can cause the electric system to become unstable. This instability arises because all the GFL IBRs interact with each other, and since each is designed to follow the other, there is nothing to stabilize the system.

GFMs are voltage source inverters that provide fast controlled current injected into the system to balance the system, rather than operating at maximum power point tracking (MPPT) like GFL inverters. They are designed to mitigate the issues faced in an inverter-dominated field.

 A weak grid refers to a situation where the distribution or transmission system has a low short circuit ratio. In such scenarios, when the impedance value fluctuates, the sensitivity of the voltage fluctuates as well. In weak grid scenarios, GFM IBRs can help stabilize the system.

Types of GFM Control Methods: Several types of GFM control methods are being developed that can be largely classified into phaser domain or time domain approaches. These methods can be Virtual Sync machine, Matching control, Dropped Based control, and Virtual oscillator control.

However from the grid control level should be agnostic of the type of technology used for GFM inverters. Fundamentally, the grid control is concerned about two outputs: Real Power (P) and Reactive Power (Q). In traditional GFL inverters, both P and Q are constant. In basic GFM inverter, P can change based on the situation while keeping Q constant. An advanced GFM inverter can change both P and Q based on system conditions.

Real World Applications: In the near term, GFM inverters are being used in microgrid designs and transmission systems with low fault current and low inertia. In the future, it is anticipated that GFMs will be utilized in the distribution grid, necessitating stable and reliable coordination between these inverters. Examples of current GFM utilization include:

a. Microgrids:

·    Micanopy microgrid in FL, which has 8.5 MW of Battery Energy Storage System (BESS) to support the town of Micanopy and nearby neighbors during grid outages.

·    National Grid NY, with a 20 MW, 40 MWh BESS and a 75 MVA circuit. The system includes 5 substations, a 46 KV sub-transmission line, and 10 feeders that can separate to form an island.

·    Watertown, Canada, where a section of the medium-voltage (MV) feeder operates as a microgrid with 1.6 MW and 5.2 MWh BESS.

b. Grid Islands:

·    Dersalloch Wind Farm in Scotland, which is exploring black start capabilities with wind farms.

While GFM IBRs can help strengthen weak grids, they are not a universal solution for every situation. Other solutions to strengthen weak grids include strengthening the transmission system to increase short circuit strength, re-tuning fast control loops to recognize low short circuit conditions, re-imagining IBR controls to introduce additional flexibility in operation, and the addition of synchronous condensers.

The electric grid needs to adapt to meet the forthcoming Electric Vehicle load.

 

The demand for electricity has been stable for years, or even decreasing with our electronic equipment getting more efficient. However, with the advent of Electric Vehicles, Electric Heat Pumps, Large Data Centers, the demand for electricity will surge in the years ahead, and our power grid today is not ready to meet this increasing demand. Typical Electric Vehicles charging at homes are done at 5kW-10kW, these essentially double the size of the electric load for a home.

The challenge for the electric utilities to be able to meet this doubling of electric load due to electric vehicles. The electric utilities are also challenged in ways the utility cannot practically go ahead and double the capacity of the power grid without having significant increases in the electric rates. Below discusses the strategies for utilities to enable electric vehicles.

Planning- Electric utilties needs to innovate its grid forecasting and planning process to granulary indentify where the electric vehicles are being connected to the grid. A nible utility will be able to identify where exactly where the grid is already constrained and areas where the electric vehicles will likely happen, for example- high way exits, hotes, parking lots, specific neighborhoods. Knowing where, when, and how many the electric vehicles are being connecting to the grid is important first step for the utility.

Time of Use Rates- The utility then can offer tools that offer smart charging to incentivize specific behaviors to alletiave grid constraints. These includes options such as offering Time of Use rates, Managed Charing, Demand Charges and other flexible charging.

 

Image Credit: ESIG

Each of these options have their strengths and weaknesses. While a Time of Use rate can solicit a strong response from the customers, in a sceneiro of mutiple EVs in the system where are all programmed to charge at the time of use rate starts on, then this stacks all of the EV load at the same time that can be larger than what the grid can provide. A better solution is to stagger the EV load during the offpeak time.

Image Credit: ESIG

Managed Charging- Managed charging options provides a nimble approach than time of use rate where the utility can provide incentives to charge at a specific time. These could be provided on a staggered time such that all the EVs don’t start charging at the same time.  

 

Automated Load Management- In an advanced scenario, the utility or the third party can provide a dynamic charging, the grid capacity is shared dynamically with the EVs such that each EVs are charged but the total capacity does not exceed the utility’s existing capacity. They can sense which EVs need more charge or prioritize specific vehicles based on need or other profile.

 

Building  new infrastructure- The flexible charging options only work successfully to the existing limit of the infrastructure. There is also decreasing marginal gain from each additional vehicles that are added with flexible charging. After a level, the utility will need to go ahead of size the systems larger with planning that more EVs will coming online in the future.

 

The integration of Electric Vehicles into the grid presents significant challenges. By adopting innovative planning techniques, implementing smart charging strategies, and investing in infrastructure, utilities can manage the increased demand effectively, and support the electrification of transportation that has been a long time coming. 

Detecting and Managing Energized Downed Conductors

Detecting energized downed conductors in utility distribution systems remains an challenge problem. When there is downed energized conductor, in many cases, the electric utility is not aware of the issue until it is reported. Meanwhile these downed energized conductor poses serious safety hazard causing electrocution when contact with humans or in some cases can result in an wildfire. The challenge in detecting energized downed conductors lies in the fact that when a wire is down, it does not draw much current creating a high impedance fault which usually does not trigger imbedded protection systems. Storms and car accidents are common causes of downed wires as shown in image below.

Image Credit:Downed Wire Safety (Unitil)

The amount of current drawn in a downed conductor depends on the soil type. Grounded downed conductors typically carry 10-20A, which is below the typical fuse rating of 80A, preventing the fuse from being activated. Normal relays are not effective in detecting such low impedance faults.

The existing prevent use of single phase reclosers also add to this issue, because the recloser, only sees a fault, but will now know that the conductor has broken and thereby the recloser will continue activate  to try to clear the circuit and continue to energize the line. 

There are new technologies that are being developed to address this issue. Advanced relays, AMI meters, and algorithms that analyze current signatures are being currently being explored. One such algorithm called "arc sense" examines cycle-to-cycle variations to detect these impedance faults.

Other technologies that work with Advanced Metering Infrastructure (AMI) can help identify voltage losses, which are then reported to the recloser through an Outage Management System (OMS). In cases where SCADA indicates the recloser is closed but the OMS reports an outage, it indicates a live downed wire.

To effectively track downed conductors, utilities require AMI, outage visualization, and SCADA on the distribution system. However, not all devices provide outage notifications, and many utilities struggle to accurately track the number of downed conductors. For most utilities, it is challenging to track downed conductors. In most case, the utilities don’t have a special code restoration code to track downed conductors.

To address these challenges, it is crucial to track downed conductors, understand their location and cause, and implement detection technologies. Overall, detecting and managing energized downed conductors requires a combination of technological advancements, regulatory attention, and proactive measures to ensure the safety and reliability of utility distribution systems.

Grid Forming Inverters is key to enable 100% Renewable Grid

  

Given the existential threat[1] of climate change, our electric grid needs to shift away from carbon fuel resources to a renewable power resource. Traditional hydrocarbon based generation systems are based on rotational kinetic energy that are synchronized with the frequency of the power grid. This synchronous provide rotational inertial energy to the power grid that can withstand small voltage or frequency fluctuation in the power grid providing a foundational characteristic of a stable power grid. Replacing these Synchronous generation system with renewable energy systems such as PV, wind, or storage that are Inverter Based Resources (IBRs) reduces the rotational inertia in the system thereby reducing the ability of the power grid to stabilize.

Traditional IBRs are “Grid Following (GFL) Inverters” depend of the grid frequency to synchronize it output. These GFL IBRs output current  that is synchronized to grid. On the otherhand the Grid Forming (GFM) Inverters can make its own voltage waveform which helps to maintain system voltage. GFM IBRs can provide very fast responses to the disturbances in the power frequency to help maintain the frequency of the power grid thus providing increased inertia to the grid. These GFMs can also provide blackstart capabilities to the grid.

As the grid becomes more saturated with IBRs, there is need to include more GFMs IBRs. A new metric – “voltage forming ratio”- quantifies the how saturated the power grid with IBRs. This ratio is calculated by dividing the Output of Inverter Based Resources (IBR) by Total Generation capacity. There is a liner decrease in stability of the system with penetration of GFL IBRs, however to keep the grid stable, the GFL should be a serious concern around 60 percent penetration. These depends on the system characteristics, types of disturbances, and the location of the grid. GFM can increase stability of grid in all these scenarios of high penetration of IBRs.

The GFM IBRs are an emerging technology that has yet to see mass adoption. While GFM IBRs have demonstrated their potential they are challenges of standardization before they replace GFL IBRs. The capabilities and the functionality have not been standardized. The vendors and manufacturers need to work on the interoperability in order to increase adoption of GFMs.

To work on this issues of interoperability, group of industry, government, and researchers have created a group UNIFI (https://unificonsortium.org) that is seeking to address the challenges of integrating GFM IBRs in the grid. By developing uniform specifications and technical requirements to cover GFMs for all IBR applications, it will address the challenges of interconnection, integration and interoperability of these systems.

The proposed specifications for GFMs can be divided into two categories- 1) Requirements during Normal Grid conditions, and 2) Requirements Outside of Normal Conditions. Under normal conditions, the GFMs can change its output based on the grid conditions and dispatch energy, but also provide damping to the voltage to stabilize frequency and thereby increasing the strength of the grid. During operations outside of normal conditions, the GFMs can provide ride through by injecting current during and after a voltage sag to aid in voltage recovery. During asymmetrical faults, the GFMs can maintain a balanced internal voltage. In case of the abnormal frequency, the GFMs can aid in the frequency recovery and stability. Other features can include islanding, black start, regulating harmonics and others.

As these capabilities are standardized, then it will make it easy for the GFM IBRs to have mass commercialization thus enabling the transition to 100% renewable energy to power our grid.

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[1] https://www.un.org/sg/en/content/sg/statement/2018-09-10/secretary-generals-remarks-climate-change-delivered