By Ric Austria

(This Blog presents the salient points of a presentation made to the North Carolina Utilities Commission in 2022 on the subject. A redacted version of the presentation can be found at this link. The author is Executive Principal at Pterra Consulting, and has conducted courses on Transmission Planning and related topics for over 40 years. He pioneered the concept of planning for Robustness and Flexibility, which are discussed further in this Blog.)

Transmission planning is changing. That is to say, it has always been changing, evolving to adapt to the changing electric supply and delivery landscape. From the early days of PURPA to deregulation to the development of energy markets to the first wind farms and on to zero emissions target portfolios, inverter-based resources, storage, offshore wind, high-voltage direct current (HVDC) transmission, distributed generation, data centers, and more, the building blocks for transmission plans have been constantly changing. In parallel, the perceptions on the role of electric energy in global commerce and livelihood, the desire for a greener energy mix, the acceptable costs for maintaining reliability and the aim for sustainability and resilience have likewise been factors for change. Furthermore, the end-game calls for electric transmission and the “ugly” structures that enable the transfer of potent energy have grown louder: that the future is in microgrids or beamed transmission, or portable energy sources, and other non-wires alternatives, and hence, that we need those towers and poles less and less, and eventually not at all. Perhaps, but not just yet, not by far. For the moment, whether that be a brief one or a longer timeframe, we still need to plan for transmission. To do so, we need to have a proper process for transmission planning, one that is appropriate for the present time to address the needs and objectives that we value today.

Recently, the prime drivers for change in the USA are federal and state mandates for improved planning, use and management of transmission systems. FERC’s initiative for an improved planning process to state mandates for various targets on solar, storage, offshore, mini-nuclear, and the like, are now necessary and important considerations in planning. (The FERC NOPR and examples from New York, New Jersey and California are discussed in more detail in the linked slide deck.)  Significant elements of these mandates, to name a few, are: “right-sizing” replacement transmission lines, consideration of advanced technologies, coordinated planning across states and regions, impact of distributed generation, unified planning models, and public policy transmission needs. These considerations introduce significant, even game-changing and paradigm-shifting, factors in developing transmission plans. However, the desired attributes and features for such plans can still be generalized into the following three key characteristics:

1. Long-term viewpoint. Transmission lines have 40-plus years of effective lifetimes and plans need to account for at least a significant portion of that period.
2. Plans need to provide for a future transmission grid that maximizes the desired attributes, or, if stated from the orthogonal perspective, that poses the least regret.
3. Because the future is uncertain, the plan needs to have a built-in roadmap that provides for alternate tracks for when less expected events take place.

And yet, there is more. While not yet widely accepted, there is a growing and insistent demand to design transmission systems, not based on a capacity model but on an energy model. The capacity model for the transmission system is embodied in the so-called Umbrella Principle, which states that “if an electric grid is able to reliably withstand extreme conditions such as high peak demand, and uncustomary climate and/or market conditions, then it can reliably weather any other operating condition.” The thin membrane represented by the fabric of the umbrella defines the capacity boundary within which the grid operates reliably. The capacity model leads to transmission plans that are defined by extreme conditions of use. Energy planning, in contrast, relies on the application of advanced technology and non-wires alternatives, such as dynamic line rating, programmable storage, power flow controllers and advanced distribution management systems, among others, to mitigate extreme grid operating conditions. The least-cost objective of energy planning is thus modern technologies and programs in combination with transmission infrastructure plans. Energy-based transmission planning is starting to appear in the industry such as in the energy headroom measurements posted by New York utilities and the Energy Storage NOPR released by FERC.

Needless to say, there is much in flux in transmission planning processes. Some of the best practices that we can note are:

• Coordinated planning involving more stakeholders, including state and local agencies, generation developers, customer groups, banks, regulatory agencies, research and development institutes, taxation authorities, etc. While not all parties can participate in the detailed simulation and modeling aspect of transmission planning, their input and oversight enable a broader perspective than the traditional centralized planning process.
• Involvement, if not actual integration, of distribution planning. A significant portion of new and planned energy resources are smaller scale, interconnecting at distribution voltages. The issues of net metering, backfeed and upramp/downramp capacities have a significant impact on transmission systems.
• Broader study sets. As noted earlier in this Blog, system use is changing. Even when still applying the Umbrella Principle, the number of unique conditions for grid stress has increased, necessitating more models and more simulations of future conditions.
• Directed renewable development. Two efforts to attract the development of renewables where existing and planned transmission capacity is or will be available are: (1) renewable energy zones, or REZ, where bulk transmission capacity is planned ahead of supply availability to attract developers, and (2) hosting capacity and energy headroom which identify where transmission headroom is limited and where utilities may garner regulatory support/approval to expand the transmission to attract future developers. Directed development reduces the uncertainty of planning for the future.
• Formalized procedures to accept advanced technologies and programs as planning components. Several are ongoing, such as FERC’s efforts to standardize dynamic line rating and utility efforts to use advanced distribution management to interconnect energy-only resources.

The link includes a sample outline for a capacity-based transmission planning process. While this is perhaps still best practice for today, it is easy to envision drastic changes to the process as the broader considerations discussed in this Blog have noted.

By Francis Luces, Ric Austria

Power projects planning to participate in the wholesale market are required to undergo impact studies as part of the interconnection application process. The studies, as a minimum, evaluate the performance of the projects under instantaneous, steady-state and transient conditions. The timescales of phenomena and equipment studied are as illustrated in Figure 1.

In the specific case of transient studies, the impact of a proposed project on the voltage and frequency control capability of the overall grid is evaluated. Traditionally, it was sufficient to consider a timeframe of 0.5 to 10 Hz (10-100 msec) for a type of study known as transient stability. The computer models (and software, such as PSS/E and PSLF) used to conduct these studies are known as phasor-based models. These models capture phenomena limited to the target timeframe.

By R. Austria, M. Gutierrez, F. Luces

Very popular pre-2000, when computer processing bandwidth was at a premium and engineers had more time to put together study information on the desktop (the wooden one, not the one filled with integrated circuits), equivalencing appears to have gone the way of the calculator, the clock and the calendar. Ok, so not quite, as the smartphone does not yet have an “equivalent” function. This will have to wait until analytical programs for power system analysis are made portable. But nonetheless, today’s power engineers will more readily go for the brute force approach of “model everything” rather than take the extra time and effort of creating a simplified model.

By R. Tapia, M. Gutierrez and M. Infantado

Introduction

Independent System Operators (ISO) constantly face the challenge of assessing the impact of facility additions to the power grid. They normally require a system impact study for any proposed interconnection of a large generating plant or transmission project. The purpose of this analytical study is to determine the potential adverse impacts of the interconnection of transmission facilities to a power system and whether it would cause any of the following:

• Post-contingency thermal overloading on transmission lines and transformers,
• Voltage criteria violations on substations,
• Negative impact on the dynamic response of power system facilities,
• Degradation on the transfer limit of transmission interfaces,
• Increase in substation short circuit current that could possibly exceed the fault duty of existing circuit breakers.

The system impact study determines the impact of the proposed project by comparing simulation results of the case with the project in service against the case without the project. If adverse impacts were to be found, appropriate solutions to mitigate the violations would be required, except for the extreme contingency assessment which is performed for information purposes on issues such as avoidance of widespread load interruptions, uncontrolled cascading, and system blackouts among others.

Unlike base load power plants such as nuclear and some coal plants which operate near full capacity for days at a time, solar photovoltaic (PV) and wind farms are variable resources whose output is dependent on the minute-by-minute change in weather conditions. For solar PV arrays, clouds and atmospheric interference are the sources of variability. While for wind power installation, gusts and weather patterns are the main culprits. This difference in operating characteristic for variable resources requires a novel approach to determining the impact of transmission capacity on the size of the plant.

Figure 1

Wind farms are unique to power systems in that the construction and development time is much shorter than that of transmission lines and other bulk system facilities.  Wind farms can be placed into service well ahead of any planned upgrades, or even proposed non-wind power plants.  In these situations, the wind farms may be allowed to interconnect on a conditional basis or an energy basis; i.e., if congestion is present, they may be first to lose transmission access or have to share the available capacity with other generators, including other wind farms.  Hence, it is important to be able to estimate potential curtailment subject to transmission congestion.  In a previous article, we introduced the raw elements of the methodology for estimating curtailment of wind farms due to transmission congestion.  (See A Methodology for Estimating Potential Curtailment of Wind Farms, Pterra Tech Blog, September 2010).   We now look at the overall methodology applied for the purposes of making annual or seasonal projections of curtailment. 

Figure 1

A wind farm integrated into a transmission grid is subject to curtailment due to temporary or long-term insufficient capacity on the transmission lines.  Maintenance outage of a nearby line, dispatch of competing wind farms and availability of other generators are examples of system events that may limit injection capacity.  In general, events that increase transmission utilization present potential curtailment conditions for wind farms, and so the daily and seasonal load cycles, and changes to interchange and import/export patterns can influence injection capacity as well.

In measuring the potential curtailment of a wind farm for, say, the incoming year, it is important to take into account the wind availability as well.  It may seem likely that curtailment will occur when the load is highest and transmission use is greatest; however, this condition may occur in summer when wind availability is low.  Hence, we have the common situation that at summer peak, the available transmission is low, but the wind capacity is also low, resulting in no or minimal curtailment.  Some operating wind farms have observed that most curtailments occur in the spring and fall periods where grid use may be relatively low but wind farm capacities are high.

One approach to estimating potential wind farm curtailment is to simulate the hourly chronological performance of the combined generation and transmission system taking into account outages, unit commitment, least cost dispatch and load variations.  This method is widely known as production simulation.  In addition to being data intensive and laborious to setup, the simulation duration can be significant, especially if one chooses to run multiple years in a Monte Carlo simulation.  This Blog presents a methodology that is based on an analytical model that is generally much simpler to develop than production simulation models and provides some unique insight into how and how often curtailments come about.

If we think about wind turbines as induction generators, one would assume that these would be VAR (reactive power) sinks, demanding vars from the grid to be able to deliver watts. However, that may be true from the point of view of only the wind turbines themselves. In reality, wind farms are far more than a group of small generators. Electrically, wind farms that deliver at bulk power levels to the grid behave more like a small urban subtransmission grid with characteristics that are far removed from those of a large power facility such as a coal, oil, nuclear or natural gas plant.

In this Blog, we discuss the amazing story of how a lowly 2,000 MW HVDC line was able to support a transmission capacity increase of 3,200 MW. 

On Nov 10, 2009, a massive power failure blacked out Brazil’s two largest cities and other parts of Latin America’s biggest nation leaving millions of people in the dark. Transmission connecting the large Itaipu dam to Brazil and Paraguay apparently tripped disconnecting some 17,000 megawatts of power. I was on Copacabana Beach years ago for a training course and can only imagine the disruption that the outage may have caused. A blackout in a major city is not a fun time.

But blackouts are interesting to study. More often than not, the initiating cause is something innocuous, such as the infamous overgrown trees in the 2003 Northeastern US-Canada blackout. (An announcement just came out that the 2007 Brazil blackout that was blamed on hackers was due to sooty insulators!) So when the news report says, “A storm near the hydro dam apparently uprooted some trees that caused the blackout,” I am inclined to consider that the trees hit some transmission lines which could have led to the isolation of Itaipu. That’s not so far-fetched. You never know what a failure-bunching event such as the major storm that hit Itaipu could do to redundancy and good planning practice. Reliability is only as good as the next blackout!