Future of Energy Storage

 

Source- MIT Energy Initiative (Future of Energy Storage Study )

A decarbonized electric sector will require replacement of existing fossil fuel resources with intermittent renewable energy resources. Energy storage technologies are a key constrain for this transition. The energy storage technologies and products available now are not in the scale that is needed for the decarbonation. A study estimates than upto 12 TWh of grid storage will be needed by 2050, this is more than 500 times the existing 24 GWh of storage that exists in the US.

Battery Storage Technologies

The characteristics of energy storage can be classified into two types- power (kW) vs. energy (kWh).  Based on the chemistry battery storage technologies used, each of them can be better suited for providing large power or providing large volume of energy storage. For example, of the three types promising energy storage technologies, lithium-ion batteries are more for providing high power, but not suited for storing large volume of energy as the materials is expensive, Redox-Flow batteries are neutral, while Metal-to-Air batteries can provide cheaper volume but not large power. Looking at the grid need, to replace the existing gas-powered plants, we need long duration battery storage that can provide multiday energy storage.

Li-ion is not the sole solution for grid need- Based on the costs, the energy storage technology can only compete with natural gas system if priced at $20/kWh. This is more than 10 times more expensive than the existing lithium-ion battery storage price of $250/kWh. To get to this lower price will require finding cheaper battery chemistry than lithium-ion, which inherently is a more expensive element. Even while the costs of lithium ion have decreased astronomically in the past years, to meet the grid need just with lithium-ion will require more than 20% annual growth for the next 20 years. This growth will be challenging to sustain. While li-ion will continue to play an pivotal use in EV and for high power applications, li-ion is not the solution for long duration battery energy storage applications.

Redox flow batteries are better suited for long duration storage- Redox flow batteries are essentially a electrochemical reactor. The flow batteries where different chemicals that have different electric potentials, and these chemicals are passed through a electrochemical reactor that allows the passage of electric charge creating a energy source. The energy produced is proportional to the size of the tanks of electrolyzes, and the power is depended on the size of the reactor. The challenge with the redox is that they have lower energy density than compared to li-ion. The state of art is the vanadium redox flow battery. There are companies such as Largo Clean Energy and Cell Cube are developing this technology. However, the there is only Vanadium as it is a rare element.  A solution should rely on working on using the elements that are abundant like sulphur and iron, or engineering new organic compounds.

Metal-air batteries hold promise for long duration storage- Metal air batteries – Aluminum Air, Iron Air, Zinc Air- chemistry works where the metal or the metalloid is oxidized (essentially the chemistry works as rusting-discharging and reducing the rust-charging) and can used to produce electricity. Air electrodes are currently inefficient; however the lower cost of electrode metals hold promise that this technology could lead to development of cost-effective large duration battery storage. Form Energy is developing Iron-Air battery storage, Noon Energy is working on Carbon-Air batteries. This technology needs more research and development.

Mechanical (Non-battery related) energy storage technologies

There are several promising technologies that are being developed that do not use battery chemistry for energy storage. These technologies include use of hydrogen storage, thermal storage, compressed air, and gravity storage technologies.  

Pumped hydro- The most mature long duration energy storage is the pumped storage hydro that has more than ten hours of energy storage capabilities. This pumped hydro storage essentially requires a selective geographical terrain where water can pumped up (stored energy) that can be later discharged when needed. In US, the areas geographical areas where the pumped hydro facilities have been build has already been build out.

Compressed Air- Compressed air technology compresses atmospheric air to high pressure, which creates considerable heat and compressed air. The heat is stored at a thermal energy storage. The compressed air is pumped underground caverns for storage. To discharge, the compressed air is pulled from underground and send through a turbine (and uses the previous thermal energy for are expansion) to generate electricity when needed. If the thermal energy is not stored, then later in the discharging process, the system will require external fuel to create heat to decompress the compressed air.

Thermal Energy storage- Thermal energy uses heat as storage and use the heat later for generating electricity. The thermal energy is stored upwards of 1200 degree Celius. There are designs that retrofit  the existing coal or natural gas plants where these steam turbines are run through thermal storage rather than burning coal or natural gas. This technology has a potential for  long duration energy storage.

Hydrogen- The hydrogen storage can use as either electrolyzer or used as combustion. The challenges with the using hydrogen is two fold- ability to cost effectively store hydrogen, and second the challenge of using hydrogen as hydrogen is orderless, colorless, and highly combustible. However, the commercial

North American Generation Plan Model Validation (NERC MOD) Testing

 

Garbage-In, Garbage-Out. This is why it is important to ensure that in any modeling the inputs and functions are modeled correctly, and the model outputs are validated and reassured before being used for practical applications.

For generator modeling, NERC has set specific standards and specifications to ensure that the generator models are accurate.

There are different types of timescale at which the machine response incurs- from the fast electromagnetic, to electric mechanical, and to steady state. For each of these different analysis, people use different types of analysis.

For steady state analysis, we do power flow analysis, essentially solving an ohms’s law. For dynamic behavior analysis, we look into time domain and review transient stability analysis. NERC and FERC have provided standards for steady state analysis. These standards are important to understand, protect, validate controls and models for transmission system. For example, when there was blackout in WECC in the early 1990, the power modeling actually showed that the grid should be functioning fine. This showed the need to ensure that the power models should be validated to ensure accuracy.

The question is how accurate is accurate enough? The test vs. simulation generally should be accompanied with  an error threshold.  NERC Reliability Standards in the US, however does not provide performance standards, but states the accuracy target is effectively achieved by checks/balances afforded by all parties having to reach agreement on the acceptability of associated models. The US systems provide this leeway because systems are complicated with multiple variables, they call can be modified to get an result.

NERC includes models for positive sequence models, the new standards and guidelines are moving towards validation of electro-magnetic transient (EMT) point on wave models. There are several kinds of model validation for generation services. These can include – i) Open Circuit Generator Saturation Curve Measurement, ii) Open Circuit Automatic Voltage Regulator Voltage Reference Step Test, iii) Normal Synchronization, iv) V-Curves Measures, v) Reactive Capability tests, and others.

These standards help to ensure that the models behavior the way the actual physical assets behave. Quality-In, Quality-Out

EV Charing and Power Distribution Infrastructure Implications

 

In China 50% of the new vehicles sold are either full EV or Plug-in hybrids. In US, the growth is slower around 15% of new vehicles sold. The growth continues to increase as with more advances in EV technology and cost reductions through economics of scale in battery technology. With the technological breakthrough of battery technology, the range of the EV cars will likely continue to increase, which will lead to increase in adoption of EVs. All the EVs means it will require the electric grid to be able to handle the charging.

Battle of the Charging Connectors- The most common one charging type is the CCS1 type charging port which includes both low voltage AC level 1), high voltage AC (level 2), and DC charging. In US, we use the model SAE J1772 charging. Tesla has its own charging standard called the NACS (North America Charging Standard). There was a competition between the standardization of the chargers between CCS1 and NACS. The Tesla’s NACS eventually won out, with all the EVs starting to use NACS charging port regardless of which company makes the EV. The NACS standard will change the J172 standard to SAE standard of J3400. For older models, there are adaptors that can be use vice versa. With the transition, all the charging stations in the US will eventually will have the NACS.

Levels of charging- There are three types of charging levels- Level 1 that is single phase AC either 120 V or 240 V. The utility source is connected to the EVSE. These EVSE does not include any power electronics, its only job is interface, communication, and protection. The EV itself includes a AC to DC inverter that the EV uses to charge the battery. Level 3 or the DC Fast Charging puts out the DC directly into the EV, and skips the AC to DC conversion.  DC fast chargers can charge at 400V to 800 V. The DCFC usually are connected to 3 Phase AC utility source. The Tesla super chargers have liquid colling, sensors, and connectors.

Charging limits- The latest version of the Tesla DC fast charges can charge at 800V+  upto 350kW maximum charging. This charging capacity is anticipated to increase to make the charging faster. In real charging scenarios, the EVs cannot be charged at the high power 250KW level the whole time. The fast charging works best for depleted batteries. The new ChargePoint chargers can charge upto 500KW. Tesla envisions that their charging go upto 1 MW. Tesla is using these 1MW charger (Mega charger) to charge their tesla semi trucks. There are other companies that are building DC lower chargers at 20-50kW chargers. These could be used at businesses, hotels, car dealerships instead of AC charging for fasting charging to electric cars.

Installing chargers- The NEC limits that the maximum output can be only upto 80% of the circuit breaker rating, i.e. if you have a 100 amp circuit breaker, then at 80% limit, you can only power at 19.2kW at 240Volts. For level 1, and cars can charge at 1.5kW at 120Vs. Unlike DC charging curves, the level 2 charging stays flat for most of the time when it is charging. Because if it is a continuous flat load, the distribution planners have to think about how to meet these types of load. For homes that don’t have a 200Amp panel, the chargers can be connected directly to the electric service utility meter. This is upstream from the service panel, and reduces the need to change the electric upgrades to install level 2 system.

Utility upgrades- As a power utility, all these EV charging will impact the distribution grid. The primary feeders for the distribution utilities have limits to how much they can power.

Feeders- These feeders have thermal limit on how much power than transmit. Considering the thermal limits- if we put 10 fast chargers charging at 175 kW we get 1750 kW that already limits to the how much the power line can provide. Also in mind that these EV are new loads, the feeders are designed for the prior load. If we had Level 2 load charging at 10kW, we can get up to 1000kW with 100 level 2 chargers on the feeders.  

Distribution Transformers- In upstream, these distribution transformers will be overloaded as well.  The common transfomers are rated at 25 to 50 kVA. These transformer limit will quickly overloaded.

What’s next- As EVs are essentially a huge power pack, the EV can provide Vehicle to Home Power that allows the home to be isolated as a microgrid and power the home during an outage. In the future, the EV could even be bi-directional Vehicle to Grid and sell power back to grid.

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

Growth Opportunities for the Electric Utilities in a era of Climate Adaptation

Its a cold and wet Saturday in Raleigh. Cooped up in my apt, I continue my favorite way to pass time  of  thinking about our energy system. Here's some of my uncoordinated thoughts- 

US Climate Report (released in the auspiciously during thanksgiving day) tells us that US can lose up to 10% of its GDP by climate change- if we do nothing. Snippet from the executive summary of the report- 

"Our Nation’s aging and deteriorating infrastructure is further stressed by increases in heavy precipitation events, coastal flooding, heat, wildfires, and other extreme events, as well as changes to average precipitation and temperature. Without adaptation, climate change will continue to degrade infrastructure performance over the rest of the century, with the potential for cascading impacts that threaten our economy, national security, essential services, and health and well-being."


As scary this is, this provides us electric utilities with the "wild west" of growth opportunities. The antiquated electric grid system needs to be revitalized to make it adaptable to climate change. Here's some of my thoughts on how it can be achieved.

Understanding electric utility firm behavior

In terms of investment theory, electric utilities in the US are often considered a mature industry. A typical electric utility operates with a tried and true business model with a regulatory compact allowing some form of monopoly with a guaranteed rate of return. As long as the utility continues to provide electricity often through large generating assets that are depreciated over decades, the return the utilities get on their equity does not change much. This "un-exciting" but reliable firm behavior allows a stream of guaranteed dividends that are attractive to many risk averse investors.

Firm behavior because of low growth potential (boring but my rational revolves around this)

A comparison of the "return on assets" on these electric utilities with the other firms (for instance software firms) shows the stark contrast in firm behavior. The software firms, often are considered to have high growth potential and these firms enjoy return on assets on median of 15%. Electric utilities who are not really considered to have any growth potential enjoy about 6% return on assets. I am including return on assets, rather than return on equity because the return on equity is affected by leverage. Electric utilities often have high leveraged (high debt and equity ratio) compared to software firms.

This return on assets difference then affects the plowback ratio- which is how much firms decided to invest their profits back on the firm rather than giving out dividends. Electric Utilities have low plowback ratio, giving out much of its earnings back to the investors. Software companies often do not pay out their profits as dividends, instead, they reinvest all of their profits back into the firm, since they can continue to grow.


kWh sales

Almost a cliche- "electric utility gets its electricity by amount of kWh sales". This is true, and however many states have tried to revert away from this model (revenue decoupling, increased competition), they cannot completely get away from it, as fundamentally, this will continue to remain true. However lets look at that closely - "to make money the utility has to sell kWh" - if the power lines are down, the utility wont make money. If the transmission lines goes out, the utility wont make money. If the entire town burns down (like the town of Paradise, of the city goes underwater- like NYC during Sandy), the utility will not make money.

So the utility and the utility regulators need to open its eyes and break from the traditional norm allowing investments in resiliency.

What the utility do to-

Utilities are seeing this across the states, are they are going back to the same old play-book. They come back to the regulators with a billions of dollars of resiliency plan, with startling amount of money. Any regulator in the right sense of mind will not approve of such high cost resiliency plans that requires astronomical increase in electricity prices.

The utility need to take it from to software firms play-book, and increase its plow-back ratio so that it can invest itself in making the grid resilient. A billion dollar resiliency plan cannot be funded solely by plow back ratio, but it shows the regulators that the utility understands the severity of the situation and is committed to making long term change.

Instead of going to the regulator will a multi billion dollar resiliency investment plant - and asking for 9% to 12% return on investment. The utility needs to prove that it really understands the needs for resiliency, and is committed to make improvements in the grid not just to get greater return, but to make sure that the grid will continue to operate in the future of climate uncertainty. 

Start with pilot projects - The utility needs to be proactive. It can start by using the its profits back into investments in resiliency as pilot projects, or making certain critical improvements. These pilot projects will not need lengthy regulatory approval since the utility is using its own profits. And it should not expect return on these investments. However, these projects will help the regulator understand the need for such investments and make them more favorable to such investments in the future. 

What will happen to the stock price?

But you might say- Achyut that makes no sense, if the dividends are decreased, then the utility stock will fall. Well that is not necessary true. Stock prices are calculated based on the future value of the earnings. Any long term investor  will welcome this opportunity since the investment in resiliency will further cement the utility's financial position in the future. Investors are not looking to investment in utilities for capital gain! They should not be. If the stock of electric utility is going up as software firms then something is not right! Investments in electric utility are low risk, and commensurate stable return.  

The immediate stock price may go down, but that is fine, utilities are in for the long haul. Utility firm cannot have be on the same mind-set thinking about the quarterly earnings.

What can utility regulator do?

Utility regulators are in tremendous position to make change. This change can effectively happen if the regulators decided to include the cost Carbon and resiliency costs are included in the LCOE and benefit cost calculations.
Many regulators are binded by the legislation (often on "lowest cost" states), but even then, revision of the what is meant by the 'lowest cost" is required. Should the customers pay the lowest kWh for 5 years, and then after the grid goes down, pay all the astronomical cost to put it back together?
 Someone has to pay for the utility upgrades, and the portion of the money will be recovered from the kWh sales. Balancing this act is the duty of the regulator. But the regulator cannot be blinded to every grid modernization proposals that the utility puts forward. The utility should make a good faith effort in making sure it understands the critical need for new infrastructure- for its customers, not just to appease shareholders. The regulators should bind the return on investments on conditions of increased reliability that goes beyond typical reliability indices (SAFI, SADI- discussed on next blog post). 

All challenges are opportunities- but only if we make them to be. 

The best of writings require several edits, this article has not been edited. While all the errors are my own, it is not representative of the best of my writing ability. 

Yes, the electric industry is excited about the solar eclipse as well!

One might assume that electric industry would be concerned about the effect of solar eclipse on the electric grid, after all, if the sunlight is blocked for a period of time, then the solar PV systems would not be able to generate any electricity, and thus adversely impact our grid. The logic is correct; however, consider a question- the sun does not shine at night, and the electric grid seems to be doing fine every night!

Balancing supply and demand

The fundamental principle underlying today’s electricity system is that the electricity that is consumed must be matched with the electricity that is generated at that very instant. When a lamp switch is turned on, the power station in that grid must generate the exact amount of energy required to power the lamp, and decrease generation by the same amount when the light is turned off. Essentially, at current economics, there is very minimum storage of electricity to draw from. All electricity demand must be met by generating electricity at that very instant. The electric utilities, balancing authorities, and system operator performs this job of balancing the demand and supply of electricity. The balance of the system measured in the frequency of the power supply is monitored very closely with a high degree of precision and accuracy.

Although the act of balancing each unit of energy consumed with each unit of energy supplied seems like an impossible challenge, grid operators are proficient at doing so. While energy from the solar output is will drastically decrease during the eclipse, the grid operators have a number of tools in both supply and demand side to help them prepare for the event. 

Managing supply side

Certainty: Unlike traditional power plants whose output can be precisely controlled by the grid operators, renewable energy sources like solar and wind are intermittent and the power output is dependent on the availability of resources. Most grid operators use sophisticated grid models to forecast what the renewable energy looks like which helps grid operations to plan ahead. In this case of an eclipse, the grid operators know with a high degree of certainty at what time and how much of the output will be disrupted due to the eclipse. Because of this high degree of certainty, the grid operators can plan well ahead in time to make sure that other power plants are turned on to meet the demand while the power from the solar systems are curtailed.

Redundancy: Electric power systems are designed with adequate redundancy so if any critical component fails, there is a backup available immediately. In terms of power capacity, the power plants are built and available to generate 10%-20% more than the peak demand of the system. Even if the power from the solar PV is reduced, there are power plants that can turn on and deliver the required power. Electric power markets have defined market rules to price and deliver energy and capacity during normal and critical moments.

Negligible portion: Our electricity comes from diverse sources. In 2016 electricity from the solar PV constituted less than 1% of the total electricity consumed in the U.S. The energy mix varies by utility, state, and balancing authority, but even in North Carolina- ranked second among states with the total solar PV capacity installed- solar PV accounts for about 1% of the total electricity delivered. Since solar PV total only contributes such a minimal amount of the energy delivered into the system, any impact due to eclipse is not going to have a tremendous impact on the grid.

Demand management: In addition to managing the supply of electricity during the eclipse, the grid operators also have the option to control the electric demand during the period of the eclipse, which should help with balancing. Commercial and industrial sector uses the bulk of the electricity generated at any given moment. Unlike the residential sector where the electricity rate is static, the electric rates for large industrial and commercial customers are more dynamic and most are enrolled in demand response programs that provides financial incentives to curtail energy use during periods of stress in the electric grid. The grid operators can call upon the large industrial and commercial users to reduce their load during the period of eclipse to help balance the energy shortfall from solar PV.

Figure 1: Solar PV array output the eclipse. Green shade provides the total energy generated by the solar array. The blue line provides the sun's irradiance, and yellow line follows the ambient temperature. Image courtesy FREEDM Center at NC State University. 

Still a not a easy task: Back to the earlier question- although the electric grid does run smoothly run at night when there is no sun, the eclipse does pose certain challenges. The grid operators may not have idea when a particular individual is going to turn on their light, but they have a really good sense of habits and seasonality of electric demand on aggregate. The grid operators are fairly adept at managing the predictable load profile. The solar eclipse will provide different circumstance when all of the solar PV output from the system will turn off in a short period during the eclipse, and all of them will come back up on after the eclipse. This sharp changes are challenging to balance. The grid operators will have to ramp up their generators during the eclipse, and rapidly ramp down after the eclipses. With certain exceptions, most electric power generators, usually not designed to ramp up and down at such short intervals.

The balancing of the grid during the eclipse will depend on how the grid operators are able to use their supply and demand tools to hand the sharp drop in solar PV production during eclipse, and rapidly increased production after the eclipse.

Reasons for excitement for electric industry

Although the energy from solar is currently at low significant levels, the electric industry and the solar industry are both excited about this event. There are two certainties – i) in the long term solar energy will constitute a much larger portion of the energy mix, and ii) there will be another eclipse, or other abnormal events that require a similar balancing of the grid. This Great American Eclipse will provide a rare opportunity to grid operators to prepare and test their grid balancing measures. There might valuable lessons to learn from this experience which can help prepare for similar conditions in the future. 

Connecticut 2015 energy legislative changes

CT legislature passed three major renewable energy bills this legislative session. As of today SB 1070, HB 6838, and SB 928 have been passed by both houses and is before the Governor Malloy for approval. He is very likely to sign all three bills into law as much of it has been put forward by his administration, especially HB 6838, which has been his signature initiative. Broadly, all these bills makes significant changes to the renewable energy policy in the State.

SB 929 authorizes the Department of Energy and Environmental Protection (DEEP) to create a pilot “shared clean energy” program. Shared renewable energy program or popularly known as community energy program allows residents to purchase a share of energy produced by a solar farm, and claim the energy and environmental benefits associated with this. This program expands the solar  (or other renewables) energy for people who do not own their own houses to put solar in the roofs, or live in situations where solar PV is not practice. A developer in the community would be able to install a large solar array, and could “sell” portion of the electricity to any residents. Purchased electricity share of the electricity from the community energy farm would be deducted from the residents electricity bill. Total amount of such community solar projects are capped at 4MW in Eversource territory and 2 MW in UIL territory.

This program however will be offered as a pilot program, and DEEP is required to analyze and offer recommendations as to the viability of making such community energy projects into a permanent program. This bill follows a very recent example of successful legislation in Maryland (HB 1087) to establish pilot community energy projects as well.

Enabling community solar projects or shared renewables is significant step towards creating energy justice as it allows people to receive benefits from solar energy previously would not have been able to because of various reasons. More solar projects will help decentralize CT’s energy sources and will enable to receive clean and affordable energy from local sources. It is perhaps a good idea that the program is capped, since the program would have otherwise have created exponential demand similar to Minnisota. Pilot program will help to figure out nut and bolts of offering such program, and given how intrinsically beneficial solar energy is, this program would surely be continued in the future.

One key attribute about such community solar projects is who is allowed own them. If it is the utility who owns and provides such service then this is would not mean change from the current status quo in the monopoly energy market (which has been popular in Virginia). However, in CT, the law allows any party to build such solar projects, which is definitely the right way to go.

SB 1078 shuffles up the responsibilities of the Board of Public Utilities (BPU) (their version of public service commission) and the Department of Energy and Environmental Protection (DEEP). This bill shifts the responsibility of procuring large scale renewable energy, demand response, and natural gas as provided in the state’s Integrated Resource Planning from the BPU to DEEP. DEEP can issue multiple solicitations to contract up to 10% of the total load served by the state’s electric companies. Renewable energy procured under this would be used for state’s RPS compliance.

I am not sure why exactly why the legislature decided to shift this responsibly from BPU to DEEP, but this would be a huge change how the energy would be procured. This model is very similar to New York where, the state agency- NYSERDA procures all the energy for RPS compliance. Maybe this is CT slowly transitioning into the NY central procurement model.

Although, the bill specifies that the utilities can use the renewable energy credits for its RPS compliance for can sell the RECs out side of state. More of REC sales analyzed in section below.

HB 6838 has been Governor’s Malloy’s signature initiative, and has been very popular in the media. The bill expands the State’s Residential Solar Investment Program’s goal to 300 MW of new residential PV by 2022, from its previous goal of 30MW by 2022. This ten fold increase in the goal would be facilitated by creating Solar Home Renewable Energy Credits (SHRECs)..( this in a state that already has LRECs, and ZRECs; a new addition to its REC alphabet soup).

CT has an unique RPS in that it does not have a solar carve out like other states. It has tried to create distinction between solar and other resources by creating Zero emission RECs (ZRECs) and Low emission RECS (LRECs) and has imposed utilities to purchase a percentage of each. This bill requires the utilities to purchase SHRECs at predetermined price, which creates a market for these SHRECs. This is very creative and impressive in that this bill effectively creates a pseudo solar carve out, in the state RPS that does not have a solar carve out.

Any residential homeowever who installs solar through participating in the Solar Investment Program offered by DEEP would forgo their rights to the environmental credits to DEEP. DEEP would then sell these SHRECs to utilities in a long term contract to generate more revenue to provide incentives to for more home solar. 

This self-funding cyclic process is great, and if you give it a thought, it appears that the all the homeowners would be paying for the solar (which they should) by a increase in their general electric bill, but if you read the bill closer, it specifies that the utilities can sell these SRECs out of state to generate revenue which then must be used to relieve the ratepayers in CT.

This bring the issue of double counting of these RECs, especially since there SHREC by law are going to be priced significantly lower than other markets. Other unique attribute about CT is its fixed Alternative Compliance Payment (ACP), which is the amount that the utilities would have to pay if they do not meet the state’s RPS goal. The law has fixed this payment to $55 MWh, which effectively provides the ceiling price for these RECs, since a utility would rather pay the ACP then purchase RECs for higher price.

So since these SHRECs can be sold out of state where they may be priced higher, this would be a significant revenue stream for CT. In a way they are funding their solar growth, it other’s back- the same way one could argue Vermont has been doing it. Vermont does not have an RPS, so most of the SRECs in VT is sold in CT, so one solar panel is being counted toward meeting Vermont’s own goal, and to meet CT RPS- effectively counting the output from the same solar panel twice.

CT although has been careful saying that the if the SHREC is used to comply with the State’s RPS then the must be retired, which is great, and limits these RECs from being double counted. But for the RECs that the utilities sell out of state, it is a little complicated.

The trouble is that CT has two goals - RPS Class I requirement, and 300 MW goal under this program. I assume most of the SHRECs will be retired for the compliance towards RPS, but there will be a lot that the utilities will just sell out of state. While this may not be used to comply with the RPS, it will be counted towards meeting this 300 MW goal- which I would argue is a kind of double counting.

But CT has been careful against possible legal challenges. It its last changes to the bill House changed the language in the bill from being a "goal" to a "cap" which I think that takes care of the double counting in a legal way. Since one could argue that there is no goal under the Residential Solar program. 

I dont mean to be critical, this bill is going to be great for home solar deployment, but it is as not tight that I would hope for; but again with one of the highest electric rates in US, the legislatures probably wanted to put in a check that the cost dont escalate further.

Anyways, this sums up little of complexity in electric markets. Electric markets natural tendency is to act like a monopoly, and for various reasonable arguments we have tried to make turn it into competitive market. This process was described as a person trying to push a large bag of spaghetti up hill- if you push on one side of the bag, the other side bulges down. This is similar to what we observe in electric market, there are just number of ways, one can shuffle around, and one has to be careful while modeling such market.