Transmission month: how to make the existing grid work better

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Welcome back to Volts, where every week is Transmission Week!


In my three transmission posts so far, I have focused mostly on
the challenges of building new long-distance energy transmission
lines in the US — the poor planning, the inefficient financing,
the permitting and siting hassles.


Today I’m going to turn to a different subject: the various ways
that the performance of the existing transmission system could be
upgraded and improved through so-called “grid-enhancing
technologies” (GETs).


To be honest, I probably should have tackled this subject first.
Though new lines are going to be needed regardless, it is faster
and cheaper to upgrade the existing system, with fewer regulatory
barriers. GETs can achieve short-term relief from grid congestion
while new lines are being developed.


There are three techs that are typically classified as
grid-enhancing technologies, and I will focus on them in this
post. In my next post, I’ll cover a couple of extra options that
I haven’t found any other way to fit in.


Let’s jump in.


(I should note here up top that I will be drawing heavily from a
2019 report on GETs from the Brattle Group and Grid Strategies.)


Closer monitoring to improve line performance


When electricity passes through transmission lines, they heat up.
As they heat up, they sag. If too much electricity is run through
a line, it can exceed its maximum operating temperature or sag to
the point that it brushes up against trees or other structures,
potentially sparking fires.


Grid operators want to avoid that, so they do not load lines to
their full rated capacity. They set an operational limit well
below theoretical capacity, to create a safety margin.


But how far below capacity should the limit be set? That is the
question.


The heat and sag of a given line are changing in subtle ways all
the time. They vary with the ambient temperature, humidity,
barometric pressure, and wind speed. If it’s warmer, the line
will heat up faster; if there’s a breeze, it will heat more
slowly. Because the heat and sag are in constant flux, so too is
the maximum safe capacity of the line.


“The number we love to quote is, an increase in wind blowing
across a power line of three feet per second results in a 44
percent increase in the capacity of that power line,” says
Jonathan Marmillo, co-founder of LineVision, a company that makes
equipment for monitoring lines. “That's the equivalent of a light
breeze.”


(Note: this means that the capacity of transmission lines
increases as the production of wind energy increases. Handy!)


But transmission system operators do not generally have that kind
of real-time information about the heat and sag of their lines.
They are forced to estimate, to use an average. In some cases,
they assign a line a single “static rating,” well below full
capacity. In some cases, they assign the lines seasonal ratings,
adjusting for seasonal conditions. These estimates are,
necessarily, conservative.


As a result, “most transmission lines are loaded at 40 or even 30
percent of their rated capacity,” says Marmillo. That’s an
enormous amount of usable capacity going unused, to hedge against
the lack of information.


That has changed with the development of “dynamic line ratings”
(DLRs), whereby lines are continuously monitored and their
capacity continuously updated.


DLRs have been around for a couple of decades, but the first
generations of devices were cumbersome. They were installed
directly on the power lines (which involved taking the lines out
of commission) and proved unreliable in operation.


Technology marches on, though, and the latest generation of DLRs
is vastly improved. LineVision’s DLR devices, for instance, have
“no-contact” installation, which means no messing with the lines;
they attach to the transmission tower. They are topped with LIDAR
— the same technology used by autonomous vehicles — which gathers
fine-grained data that is then crunched to determine the “net
effective perpendicular windspeed,” the most important variable
for determining line temperature. “We essentially use the
conductor as a giant hot wire anemometer,” says Marmillo.


Of course, if you abandon averages in favor of real-time
measurement, sometimes capacity will be below what the static
average would have indicated. But “we see capacity above static
[ratings] about 97 percent of the time,” says Marmillo. It turns
out those static ratings are extremely conservative.


Allowing more power to travel through lines relieves grid
congestion, which is valuable to grid operators. Marmillo says a
recent installation of LineVision’s device on a PJM line paid
itself back in three months.


DLRs are particularly cheap if you compare them to more dramatic
solutions to grid congestion. “The cost of deploying a DLR system
on a transmission line,” says Marmillo, “is less than 5 percent
the unit cost of reconstructing or rebuilding the line.”


(Note: there’s an open FERC proposal on the subject of line
ratings, in which the commission plans to require seasonal line
ratings within two years, and for RTOs and ISOs to put in place
systems that are prepared for DLRs within a year.)


So that’s technology one: DLRs to better understand and exploit
the real-time capacity of existing lines.


Controlling the flow of electricity to ease congestion


The Brattle report says: “Power flow through an AC line is
proportional to the sine of the difference in the phase angle of
the voltage between the transmitting end and the receiving end of
the line,” and I’ll just go ahead and trust them on that.


Left uncontrolled, power will simply cascade through the system
according to Kirchhoff's laws. But it is useful for grid
operators to be able to route power away from congested areas and
toward less congested areas. To do that, they need flow control
devices.


The first kind are special transformers called “Phase Angle
Regulators” (PARs) that directly manipulate the phase angle to
control the flow of power. They are well-known and accepted in
the industry, but they are expensive, to the tune of millions of
dollars a year, which has limited their deployment to a select
few high-traffic lines. Plus, the accelerating pace of change in
the electricity system has made their size and inflexibility more
problematic. “These are 40-plus-year fixed assets,” says Jenny
Erwin, marketing director for Smart Wires Inc., a company that
makes flow control devices, and these days, “it's just much
harder to plan out what you need 40 years from now.”


The other family of flow control devices are Flexible Alternating
Current Transmission Systems (FACTS), which are generally
power-electronics devices that control the flow of power through
a line or voltage on a system by, for example, increasing or
decreasing reactance on a line.


Older versions of FACTS were also quite large and expensive, but
due to advances in electronics and control software, they have
been made much smaller and more modular. “What used to be done
with copper and steel,” Erwin says, “we are able to do with
silicon and software.”


Now, reports Brattle, FACTS “typically cost significantly less
than PARs, can be manufactured and installed in a shorter time,
are scalable, and in many cases, are available in mobile form
that can be easily redeployed.” (Smart Wires, a California
company that’s been around since 2010, is currently the only
company making these modular FACTS.)


Several studies have found that FACTS create value by easing grid
congestion and deferring transmission system investments. For
example, Brattle summarizes the results of a 2018 study from the
Electric Power Research Institute (EPRI): “simulating the 2016
PJM system with 13 power flow control devices placed in optimal
locations to reduce thermal overloads indicated annual production
cost savings of $67 million. Considering the initial investment
cost of $137 million, the payback period is roughly 2 years.”


The possibilities opened up by modular FACTS have only just begun
being explored. Most deployments and studies have focused on
individual lines, but as more and more lines become dispatchable,
it stands to reason that there will be emergent system effects.
It’s one thing to have a dispatchable line; it’s another to have
a dispatchable grid.


Erwin acknowledges that this is, in fact, Smart Wires’ long-term
vision. “We like to think about it as crawl, walk, and run,” she
says, and implementing a fully dispatchable grid “would be
running.” The company is taking small steps in that direction in
the UK, installing FACTS on several lines across a wide swath of
territory and linking them up so that they communicate with one
another.


But she stresses that the comprehensive vision “is not required
to unlock value. You can extract meaningful value today, because
every new FACTS adds a degree of control and efficiency.” For
much more on this, see this technical report from EPRI and many
other reports compiled by Smart Wires.


So that’s technology two: power electronics to control the flow
of power across the grid.


Reconfiguring the grid to route around congestion


The flow of energy through an electricity system is determined by
the level of output of the generators, the level of consumption
of the loads, and the “topology” (physical configuration) of the
transmission lines connecting them.


There is already hardware deployed across the grid, in the form
of circuit breakers and communications systems, that can, by
switching open or closed, change that topology. Grid operators
have long had switching procedures in place to reconfigure the
grid as necessary to maintain reliability.


But “finding good reconfigurations is computationally
challenging,” says electrical engineer Pablo Ruiz, a consultant
at Brattle, associate research professor at Boston University,
and co-founder of NewGrid, Inc., a grid software company spun off
from an ARPA-E project. Traditionally, reconfigurations have been
implemented on a limited, ad hoc basis, guided by operator
experience.


Recently, however, engineers have learned to calculate
reconfigurations more quickly using software. Thus the budding
field of “topology optimization.”


Ruiz draws an analogy with transportation. The old way of
handling congestion was to raise tolls on the main roads,
convincing drivers to stay home (or in the case of power,
generators to curtail their output). Topology control software,
Ruiz says, is like the navigation app Waze, showing drivers how
they can route around congestion. That will mean less curtailment
and less congestion.


The software doesn’t do the reconfiguring itself — that’s still
for the grid operator. “The analogy with Waze is actually pretty
accurate,” Ruiz says. “It's a decision-support tool. This is not
about self-driving cars; the operator is still the driver.”


Naturally, though, it makes me wonder about the possibility of
self-driving grids — grids that route power optimally and
automatically. Ruiz thinks something like that will eventually
happen, but expects a long road of incremental advances in
automation before then.


Anyway, in the meantime, recent deployments of topology control
software in the UK have shown that “just by optimizing the
configuration of the grid, you can increase grid capacity by,
depending on system conditions, between 4 and 12 percent,” Ruiz
says. “These are very large transfers, so if you can get 10
percent more with existing infrastructure, without any new
capital investment, that's a big deal.”


Studies by Brattle in the US and National Grid in the UK have
confirmed that topology optimization can relieve transmission
constraints and save power consumers tens of millions of dollars
annually. “Broad application of the technology for real-time and
day-ahead congestion management support would reduce the cost of
congestion by about 50 percent,” he says.


Even with the misaligned incentives of today’s utilities
(software investments, unlike infrastructure investments, do not
receive a guaranteed rate of return), Ruiz thinks topology
control will pencil out for them. It might reduce the need for
some smaller transmission-expansion projects, but it will relieve
congestion on lower capacity lines by routing power to (currently
underutilized) high-capacity lines — thus improving the economics
of those larger, more expensive projects.


Topology control will also improve the business case for a
national macrogrid, since it can help ensure that every
high-voltage trunk line is fully utilized.


So that’s technology three: software to map out the best and most
efficient configuration of the grid, from day to day and hour to
hour.


The extensive benefits of GETs


The Brattle report I mentioned at the top of the post recounts
several examples of successful deployments of GETs. It estimates
that wide deployment would produce benefits that rival the value
of creating regional transmission organizations (RTOs) and
competitive power markets. The benefits of GETs include not only
relieving grid congestion, deferring new capital investments, and
saving ratepayers money, but also boosting reliability and
resilience and generally improving system performance.


The most interesting attempt to assess the full benefits of GETs
comes in a forthcoming report prepared by Brattle for the WATT
(Working for Advanced Transmission Technologies) Coalition, a
group of companies developing GETs.


The study won’t be released until February 24, and unfortunately,
the folks at the WATT Coalition are too short-sighted to allow me
to share the results in advance (grumble).


I can say, though, that it is a detailed engineering analysis
focused on a single (wind-rich, increasingly congested)
transmission region. It examines the effects of a full deployment
of GETs across the region.


Long story short, GETs double the amount of new renewables the
regional grid is able to accommodate through 2025. Building
enough new power lines to do that would be wildly expensive and
take decades; GETs do it almost immediately, with an investment
that pays itself back in about six months. It also creates jobs,
reduces carbon emissions, and saves the region money.


In terms of the clean-energy transition, GETs are an easy win, a
quick way to bring more renewables online and reduce emissions
while also, helpfully, saving money. Utilities just need to do
it.


Making utilities want to get GETs


The core problem for GETs is the same problem I have been
identifying for years: the incentive system in which US energy
utilities operate. They do not make money by selling electricity
or by providing superior service. They make money by receiving a
guaranteed rate of return on capital investments.


Naturally, they want to make more capital investments.


If a technology comes along — energy efficiency, distributed
energy resources (DERs), or GETs — that promises to defer or even
head off the need to make new capital investments, the utility’s
profits are directly threatened. All those technologies may serve
the public’s social, economic, and environmental goals, but they
do not serve the utilities’ financial interests.


Even when utilities do not face a disincentive to improve their
operational performance, they have no positive incentive, no
reason to set aside money and resources. The costs of congestion
and interconnection backups are simply passed along to
ratepayers.


Everyone in clean energy is aware of this basic incentives
mismatch. “It's really an incentives issue,” says Erwin. “Clearly
there is a misalignment in incentives,” says Ruiz. “There's no
question about it.”


Consequently, deployment of GETs remains confined to a few
demonstration projects. Brattle summarizes:


The slow pace of adoption of these new technology options may
largely be driven by two factors. First, the technology options
by themselves are not being recognized enough for their
capabilities. … Second, there is insufficient incentive for
either the transmission operators or owners—the two market
players who are best suited to adopt these technologies—to
innovate and change their operations, which requires a concerted
effort.


Reforming US utilities is a mountainous task, and nobody has time
to wait around on it. In the meantime, the best that can be done
is to create incentives where they are now lacking.


FERC can do so by mandating that utilities and RTOs examine
alternatives to new transmission — upgrades to the existing
system — in transmission and operational planning processes. It
can implement new rules that reward utilities for meeting
performance metrics, so-called “performance-based regulation” (as
is common in the UK and Australia). It can encourage
benefit-sharing (and cost-sharing) among transmission owners and
other market participants, both sharing congestion costs and
spreading out the benefits of new GETs. And FERC could push
utilities to subject new GETs projects to competitive bidding.


A group of 13 senators recently wrote a letter to FERC asking
that it take these steps to encourage GETs.


Congress could help by offering tax credits or other financial
incentives to utilities to improve existing transmission systems
with GETs. Money is the best incentive of all.


And maybe, some day, we could think about reforming utilities
root and branch, to once and for all align their incentives with
pro-social behavior. A fella can dream.


GETs are part of the digitization of energy


One of my pet theories — which I first wrote about in 2016 — is
that Vaclav Smil is wrong. Smil is a venerable energy analyst
famous for throwing cold water on all the talk of a rapid
transition to clean energy; he points out that previous energy
transitions have taken more like a century than a decade.


One reason I think the clean energy transition will move faster
is that it is not merely a transition from one set of physical
energy sources to another (though it is that too). It is also in
part a transition from the physical to the digital.


Where physical commodities generally get more expensive over
time, computing power is consistently getting cheaper and
cheaper. In area after area, engineers are figuring out how to
substitute “intelligence for stuff” — i.e. computing power for
commodities.


Think, for instance, about solar trackers. Solar panel
manufacturers used to experiment with a variety of shapes for
panels, to try to catch more of the sun’s energy as it passes
overhead; that manufacturing is expensive. Now panels can be
mounted on trackers that automatically sense and follow the sun —
so manufacturers mainly just make flat panels. The intelligence
of the trackers has substituted for the stuff of the panels. (See
also: digital circuit breakers that allow building owners to get
more out of their existing electrical systems.)


(I had to mention digital circuit breakers as an excuse to show
this amazing video.)


GETs are another great example. The same physical grid can
virtually double its capacity through the combined application of
GETs: better sensing, better calculating, and better control.
Rather than make twice as much grid, we can make a grid twice as
smart. Intelligence for stuff.


Inevitably, as the costs of sensors, chips, and computing power
continue to decline, we are going to infuse them into all our
infrastructure: transportation, buildings, and power. We are
going to get more performance out of our existing capital stock
through the application of intelligence.


Once progress is hitched to computing power, the clean energy
transition will no longer be limited by the slow innovation and
turnover cycles of physical commodities and machines. Things move
much more quickly in the digital space.


Consequently, the transmission grid we’ve already got may have
much more potential than we’ve given it credit for. But
fulfilling that potential will involve pushing utilities to value
getting more out of the transmission assets they already own.
It’s a fairly easy fix, for a large impact. Biden should get on
it.


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