Greening the Grid: Best Practices for Grid Codes for Renewable Energy Generators

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>>Katie: Hello everyone. I’m Katie Cantos and welcome to today’s webinar,
which is hosted by the Clean Energy Solutions Center
in partnership with USAID. Today’s
webinar is focused on Greening the Grid: Best practices for Grid Codes for Renewable
Energy Generators. Before we begin I’ll quickly go over some
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an introduction to the key concepts for understanding renewable energy grid codes
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this service to those in your networks and organizations. Today’s webinar is co-moderated by Jennifer
Leisch, who manages the USAID-NREL partnership, overseeing a portfolio of clean
energy integration projects. Jennifer leads the
USAID Greening the Grid and directs the agency’s work to account for greenhouse gas
emissions reductions as well as USAID clean energy programs. And now I’d like to provide a brief introduction
for today’s speaker. Adarsh Nagarajan is
a research engineer in the Power Systems Design and Studies group at NREL, with a
focus in distribution systems analysis relating to clean energy systems. And with that
very brief introduction I’m very pleased to welcome Adarsh to the webinar.>>Adarsh: Thanks, Katie. Thank you all for attending the webinar. This webinar will
present necessary background for understanding renewable energy grid codes and review
how grid codes are developed in the United States and internationally. Grid codes are key mechanisms that state entities,
utilities, nations use to ensure safe and reliable interconnection processes when connecting
new resources. It may be PV, solar,
wind, storage, anything that shows up. Recent development in inverter interface energy
technologies poses new challenges to the design and implementation of grid codes. In this webinar we will talk about some of
the most recent inclusions to the grid codes such
as right-throughs, which means what should these new technologies do when there is an
event on the system; voltage regulation, which means what should these devices do when
there is no issues on the system for inverter interface energy technologies. Grid codes have been evolving in its ability
to support and organize a lot of ideas surrounding new technologies. Legacy grids involve centralized generation
and consumption typically far away from the point
of generation. The legacy system included
three categories: one is generation, second is transmission, third is distribution. However,
increased generation in the low-voltage or medium-voltage area is causing disruption
in the legacy system practices and posing a need
for advancing grid codes. Our system is evolving in numerous ways in
parallel. There are new technologies that are
showing up frequently, and there is increased penetration from these new technologies. And all these devices are expected to be smart
and be able to communicate with each other and with the grid in general. Along with all this there is significant growth
in electrification of transportation. With all this the system needs more flexibility,
which can be achieved by enabling or leveraging these new technologies the right
way. This grid code webinar will mostly
speak about the most recent 1547-2018, which is dedicated vertically for distributed
energy resources, which I will caveat in the next few slides, while what do I mean by
IEEE 1547 standards for DER? For the next few slides I would like to point
out how the new technologies are evolving in
the last 10-15 years, and I’ll be referring in particular to solar energy just to make
the point. Before 2014-2015 timeframe all the all-over
USA and some parts of the world saw a significant increase in solar energy. That installation could be for — at that
emission level could be the distribution level at different
voltage levels, but there was significant increase. After 2015 there was no indication of using
these devices for providing any controls, which means all these devices were used only
to generate active bar and were not dispatchable or flexible in no way. Even if there were older issues or any issues
in the system these devices here would just keep
generating unless there was an event, like a
fault. After 2014-2015 is when the grid code started
looking at all these things and started understanding what if these technologies can
be curtailed or regulated in a particular way
to make sure the grid doesn’t get affected. 2017 onwards there’s a significant increase
in energy storage, along with solar, which is a
photo app solar fresh storage, which makes solar so much more dispatchable, and there
is not even any reduction in active power option
for all generation from all this technologies. The same analogy also applies to wind, if
you look back, wind or [inaudible] power but now wind can do numerous things — wind is
so much more dispatchable as of course a few years back. The rule of inverter in phase technologies
are involving. IEEE 1547 has
been a major voluntary standard that’s evolving with time. This is a footprint of how the
1547 standard evolved in the past 15 years. Just a caveat: 1547 standards very good for
all resources that get connected to distribution resources, however but the evolution
has been signification in 1547. Before
2003 all the inverter interface technologies such as solar systems, energy storage that
got connected to residential level could not do
anything except generate active power. If there
was any abnormal conditions the system had to pick. However, in 2014 IEEE came out
and amended the old standard and said, “If at all a particular facility or region or
state wants to use this technology to perform some
voltage regulation, when you provide write-through frequency response they might
start trying. There is nothing wrong about
trying. But it’s not a standard yet. In the meanwhile, specifically California
and Hawaii, along with a few other states, started trying pilot studies, which means
they started using this freedom of trying, or
leveraging these devices to provide better services. And that led to a significant upgrade
in 2018, which led to the most different standards. Now, all these DER that get connected shall
be capable of actively regulating voltage; it
should provide support during abnormal voltage frequency conditions and should be
capable of frequency response. And now it may provide inertial response. Maybe this
might become a shell in the next few years. Just to get into a little bit of detail of
how individual state utilities led to a significant growth on the understanding of all these new
technologies. The reason why I’m pointing
out those two states is because – just to give a context. NREL was significantly involved
with all these states as the technologies evolved. California and Hawaii, after 2014,
started throwing out these new technologies, specifically inverter-interface technologies,
to understand what these do. In between 2003 and 2014 what happened was
there was significant penetration from new technologies such as solar. And until a point there was very little idea
about what could be the downside of having new technologies
for execute generation. However, after
the penetration level exceeded a certain point, what was when the studies related to PV
hosting capacity became relevant. Once that became relevant there were numerous
studies performed, funded by California Department of Energy that led to a point where
there is a safe percentage of solar that can be included in an area that’s safe for operation. However, the growth kept increasing in
Hawaii and California. That led to a point where even if there is
an issue, instead of stopping inclusion of these technologies the
better way is to use them to mitigate the problems. That was an NREL started working with California
and Hawaii to understand how can these inverter technologies be used to manage
its own voltage, or maybe provide frequency support or voltage support or reduce
its active power generation to maintain the voltage in the grid. Here the idea is to make sure, in long term,
the grid doesn’t fail, and also using these technologies enable increased
penetration in the future. Some of the essential services expected from
solar and wind are voltage support, frequency regulation, which is also referred
to as automated generation control, ramp control services as decided by the local balancing
authority, spinning reserves, again as referred by the balancing authority. The graph on the right is an example of how
these technologies, solar or wind, can be used for dispatching, instead of treating
it as a variable resource which is non- dispatchable. It’s a graph that has X-axis which is time,
in seconds; Y-axis is power in megawatts. As you can see, the green curve is available
megawatts from a resource, whereas the commanded megawatt, which is the
bark blue, which is kind of overlapping with the orange, is what we were trying, at
NREL, to see whether can a resource be dispatchable to my wind advantage. And with that we can clearly see that the
measured megawatt can exactly follow a certain commanded megawatt within a certain buffer,
which means that all the research and development happening in leveraging these
technologies are particular renewable resource which was previously considered as
a variable, non-controllable resource, can be mostly regulated and controlled. Before getting into a little more details
I would like to get into some key definitions, just
read out what it means. If there is any questions on this I’m very
happy to answer later on. So here I’m trying to caveat a few words. A DER stands for Distributed Energy Resource. It typically used to include solar storage
and controllable loads. And DERs typically get
connected at a residential level or medium voltage level. But however, to reinforce
certain standards doesn’t apply to controllable loads, it only applies to generators. DG has been another word which has been used
in this area which is referred to as distributed generation, which is a proxy for
solar if you go back in time. A big distinction
between distribution and transmission, any voltage level above 59 kV in the USA is
referred to as transmission or bulk energy system, whereas any voltage level, any system
that’s below 59 kV is referred to as distribution. It can go as low as 120 volts, or the
distinction between downstream distribution depends on nation to nation, however in
USA this is the number where 69 kV is what the big pot is. Every new technology that gets connected should
be capable of communicating in two levels. It should be able to connect in two levels. One is the moment you connect the
system it should be able to provide electrons back and forth, and that’s referred to as
electrical connection for the flow of electrical power. And these devices should also be
capable of communicating with the grid, maybe for just measuring, or maybe for
communication or controls. That’s referred to as logical connection,
or data connectivity. And most of the renewable resources are always
interfaced with inverters. These inverter
systems make the DC power that gets connected as a renewable resource to AC, that’s
what the consumable way of electric power is. A quick run-through of active power, reactive
power and apparent power. Any resource
such as solar, wind, storage, generate primarily is used for active power, because that’s
measurable, that’s easy to monetize, that’s what is actual power that’s unit is watt. Reactive power is basically that extra power
that’s needed to compensate any consumption inductive and capacitive power
differentiated. Active power is typically
used for frequency control; reactive power is typically used for voltage control, although
active power sometimes is used for voltage control it’s more effective for frequency
control. Combination of these two becomes a vector
sum and becomes apparent power. The most
typical way to describe all these three is the power triangle on the right. As you can see,
the X-axis is active power; the Y-axis is reactive power. They are mutually perpendicular
to each other, and both of the vectorally add up to apparent power. Power factor, on the other hand, it’s one
way to identify how much – what percentage of
apparent power is active power. Ideally these should be one. That means all of the
apparent power needs to be active power, but it depends on the need and the voltage to
say that what proportion of apparent power should be active and reactive power. And that
measurement unit is power factor. To quickly illustrate what is active power
and reactive power – I have two examples here
– one example on the left: the wheelbarrow analogy. In order to make the wheelbarrow
move we have to apply force to the handle. The force to be applied in the forward
direction only after lifting the handle. Active power force that propels the wheelbarrow
in the forward direction, whereas reactive power
is that force that serves to keep the wheelbarrow in the lifted position. As you can understand in this analogy the
force that’s applying the power direction becomes effective only after lifting the wheelbarrow
from the ground. That’s where
reactive power is more effective: it could just keep efficiency high and not fall below
a certain acceptable number. On the analogy that’s on the right the second
technology which is the inclined plane angle, here if I want the ball to roll in
the forward direction I can’t make it happen unless
there is some extra force that’s needed to keep the ball away from rolling down. There’s where we can say that the force that’s
used to keep the ball from rolling down is reactive power, so the force that’s used to
keep the ball moving in the forward direction is
active part. This slide is just to give a quick detail
of what an inverter is because a lot of things that
I’ll speak in the next few slides is all about leveraging inverters and technology. Inverters
are those devices that convert DC power to AC power, or in the bigger sense these are
that technology that enables the user of renewable resources and make things more
controllable. Solar and storage are almost always beefy,
which means that part is not consumable in local grid. That’s the reason inverters make it go from
DC to AC and makes it controllable and usable. On the left we have an example, a picture
of residential inverter which is very small in size, as opposed
to on the right it’s a megawatt-scale inverter, which is huge. Grid codes play an important role when there
are adapters of new energy technologies. Just to – so here what I’m trying to make
is to distinguish what records do and how at
what point the grid codes break, meaning what voltage or power level. As you can see on
the left I am referring to a solar farm that’s connected at the transmission level, like
220 kVr, about, whereas on the right you can those
renewable resources like the roof-solar, which I on the residential scale, or connected
at 12 kVr below. There is a significant
difference between these two. On the left all these solar or wind that get
connected at megawatt level, or that get connect to 100 kVr about systems there is
no yet significant grid code that says what should devices be doing. Whereas as opposed to on the right all the
rooftop solar, or those systems that get connected to medium voltage
or lower there is a significant need for grid code and therefore 1547 is dead. One of the reasons why, so far, there has
not been a standing up standard on those systems that get connected to transmission
level is maybe because there are fewer players. To give an example, in a single feeder there
could be a few hundred, maybe up to 1,000, rooftop solars as opposed to in the
whole USA there could be a few hundred such big projects that have multi-megawatt solar
connected to, or wind connected to transmission level. Typically transmission [inaudible] inverters
interface technologies operate through power switches agreement and it’s easy to monitor
and control and go in case by case. However,
with all the recent developments there’s been a new standard that’s currently being
developed which is 2800.1, which might take that form in the next few years. On the
right on this slide, which is of the residential roof-top solar, since there are a lot of
players, numerous vendors – and at the same time there could be few hundred
installations happening in a single region or state, there’s a significant need for standards
that govern. And secondly, there has not been a clear incentive
mechanism as to what should, or what will, the investor or the customer get if
they provide all test support. So there has been a
little bit of confusion on. And that’s the really all these standards,
irrespectively, say that you should be able to provide some services,
whether there is incentive or not, just to keep the grid running and from failing. And all these – and just to give one of
the quick descriptions, there is no one word that
says, or that refers to those solar or wind that get connected to bona fides systems,
as opposed to DERs, or those that’s referred
to solar or storage that get connected to medium
voltage or lower. So from now on, if I say DER that’s happening
at distribution level, and if I say anything that’s connected to [inaudible]
that’s the transmission level systems. The basic expectation out of DERs in the real
world, is to be a good citizen, which means these devices should be able to provide some
local service just to keep the grid from failing, or keep the old data within acceptable
limits. In the past all these systems used to
just generate active power and shut down when there was any problem, whereas what is
expected from now on is to also do something when there is a little bit of problem on the
grid. It could be outage; could be frequency or
anything. Additional interest of investing. As the penetration of these DERs increase
for utilities, instead of investing in additional technologies
when we get issues, they can use these systems to provide some service or adopt them. Some of the key considerations for grid codes. There still are too many devices that
operate in a local region; all these devices that go on distribution should be capable
of mutually agreeing on what voltage support
modes are, should be capable of providing voltage frequencies supporting a particular
way, should fail-safe and should not cause any fire hazard, and all these devices, DER,
should be capable of communicating in a particular way and complies with some acceptable
set of protocols, which means all these devices should be speaking somewhat in similar
language and should be capable of understanding. And as the penetration keeps increasing a
second need here is — or the most important need is how quickly are these devices pluggable
and playable, or what’s the minimum time required to just connect and make it
run? In order to make a grid code, especially in
the world of distribution systems, or DERs, there are numerous stakeholders as opposed
to what happens at well systems. The hardest
part is to make a grid code agreeable to all these diverse stakeholders. Every device
should be performing a very particular way, and that’s what can be done, only if all the
inverter manufacturers talk with each other and talk with the state entities. All the distribution utilities, state governments,
should work in tandem with the inverter manufacturers, along with their governing
entities such as public utility commissions. Along with all this voluntary organizations
such as IEEE, NIST, National Energy Code, Underwriters Laboratories – there are numerous
to keep mentioning. All these voluntary
organizations should somehow provide – get the funding, and should kind of push this
momentum in the direction that helps the nation. On top of all this comes the consumers. These are the people who really buy, or invest
in these devices. These no-policy, or technology or grid codes,
should act against the need for buying these technologies. If a consumer wants to buy it these grid codes
should enable them to buy it and make them usable
in a particular way. On top of all these, national labs and universities
play a very important role in documenting all these and pushing these technologies
or grid codes in a very particular, usable way. Along with all these there are sufficient
legal firms that try to make sure that no policy acts against its usability. Just to provide an example, in California,
in order to make the grid codes to the current state, smart inverter working group was set
up in 2014 and right now there are only 200 organizations that sit for a phone call or
meet a few times a year to make sure all stakeholders’ interests are properly answered. Among all the stakeholders the key stakeholder,
I would say, is vendor because – it’s inverter vendor is because inverter is that
technology that connects all these renewable technologies to connect to the grid. And in order to make all these devices work
a particular way inverter vendors should be
in tandem with all these verticals that we state
here, such as local/state rules, UL, which is for performance standards, voluntary
organizations such as IEEE, NEC-NIST and SunSpec, which is for communication,
which is particular to USA here. But this is a particular example how many
organizations or institutions that inverter organizations
should work with. As already discussed, 1547 is
a voluntary grid code and that governs all the DERs that get connected in the mainline
USA. From September 2017 onwards California and
Hawaii said all the inverters that get connected to the main grid should be capable
of providing some advance inverter functionalities. And to make it happen it take four to five
years. However, after that
happens, in 2018 is when IEEE updated all its standard grid codes and announced that
it’s going to be a national requirement. However, it doesn’t mean that every state
will start using technology then and there. The requirement here is, to give you an example,
if Arizona wants to make, or comply with 1547
then the PUC should make an announcement or some sort of a legal binding
document that says that we will comply to 1547 2018. If they don’t do it they should come up with
an equivalent rule such as Rule 21 or Rule 14H, that can override 1547. So what is 1547? 1547 is a standard for interconnection and
interoperability of DERs with associated electrical power system interfaces. 1547 governs all that that happens
between a DER and the local grid. 1547 is a standard which suggests, or which
provides the requirement from a device and it’s not
a design handbook but it’s not descriptive, it’s
all about what technique to be done. 1547, to the specific as I already have said,
is only for those systems that connect to distribution level; there is no size limit;
it can be as large as it can get in a load. 1547 took
a lot of effort. To give an example, it had – it took almost
three to four years to make this happen. It had up to 120 industry experts in working
group. Working groups are those set
of people who dedicate to make a standard happen, and in the end it was balloted with
up to 400 people, and the last few years developed
[inaudible] 1500 comments that were resolved. As you can see, it’s a big effort to make
a standard happen. What 1547 did was it
categorized the operation of DERs into two verticals, which is what should the device
be doing when the grid is operating normally,
or in other words when there is a continuous operation, or what should the devices be doing
when there is an event on the grid, or a fault. So within 1547 2018 provided two modes, which
is category A and B when a DER is operating in a normal, all data operating
condition. Whereas it provided three categories,
1, 2 and 3, when there is a fault, or an event, on the system. Category A and B, as you can
see, has different limits. There are quite a few things, but the main
difference is percentage of a load reactive part. Category A is a little more conservative on
how much reactive our should be limited to because
that, in a way, limits the active part curtailment on the inverter on the solar. Whereas Category B is for those scenarios
with a high penetration of renewables, and the provides
higher limit on reactive part. On the other hand Category 1, 2 and 3 provides
time limits on at what point should – up to what time should the DER provide some dynamic
support, and Category, 1, 2 and 3 go from provide very little support to a lot
of support in Category 3. California and Hawaii
run with Category 3. So Category A and B it’s all about providing
voltage support. And the way it works is the
inverter, which is the interface between the renewable resource and the grid, or generator
and the grid, should be able to regulate its reactive power, depending on voltage at the
point of common coupling. Just to clarify, the standard mentions that
reactive power has the priority over the active power, which
means even if there’s a voltage event in the system inverters flush twice to inject the
reactive power, and then it starts curtailing the
active power to make necessary voltage improvement. As third Category A is the more
conservative as opposed to Category B. This is when the voltage likes to happen – that
means when there is an event on the system. Could be a fault, could be a tree falls on
a line or whatever could happen when there’s an event on the system what should
DER be doing? In that sense what were watts
expected out of these DERs before the recent update on 1547. It’s a graph with X-axis as
time; Y-axis as voltage. If the voltage at the point of common coupling
or interconnection exceeds, above or below – above 110 percent or below 88 percent
it was expected out of DER to just trip, or don’t do anything, cut down. Whereas after 2018 we want more of it, which
is if there is a voltage event, which is about one-tenth percent
of below 88 percent, we still want something out of the device. It can keep generating up to 12 seconds, which
is the most time in Category 3. As the voltage becomes lower the limited time
is limited to one second. There is a very detailed description of this
in 1547. And most importantly, as the
penetration of these DERs increase these devices should be communicable, which means
they should be able to talk. They should talk somewhat similar. They should be able to
understand. There are numerous communication protocols. So what 1547 did is they
listed these three, which is 2030.5 or also referred to as smart energy provides 2.2,
which was a Zigby, DNP 3, which is a very popular
protocol, or SunSpec Modbus. SunSpec Modbus is a variant of Modbus but
it’s specifically for inverters. That means
any DER that gets connected in USA should be capable of managing one of three, one of
these three. And one more thing that happens significant
in the past year is in order to make communication as easy as possible SunSpec,
the organization came up with the communication standard, which means every
inverter now can be certified with SunSpec to have communication possible. That means all inverters should be all performing
a very particular way. Going on to the next part of the slides, or
the webinar, which is International Grid Code Development. Europe has been a leader, as well as in the
area of grid codes and adopting to renewable technologies, which is – and
in this case, in the interest of time we are limiting to Germany, Italy and Spain. Germany has been a leader specifically when
it comes to penetration levels to have very high penetration. There are two main standards that govern renewable
penetration in Germany, which is BDEW and VDE 4105. BDEW became active in 2009; VDE 4104 became
active in 2012. The next slide I’m
going to separate them – what are they? BDEW – so the prominent functionalities
end up by these grid codes are feed-in management,
which is ability to limit its active power in
order to make the grid better; provision for reactive power, which means ability to inject
reactive power for better voltage management; and third, dynamic grid support. When
there is an event or a fault, for whatever reason, the device should be performing a
particular way. So BDEW arranges the grid architecture as
shown in the top right corner. As you can see,
the way they are arranged they start with the basic topology and they insist that the
most important, the second more important thing
is communications. That means all of these
devices should be able to talk a particular way. Then comes information, which is all of
these devices should, whenever they talk, should be able to be saved in a particular
way and should be able to be retrievable and communicable. Then comes the functions, which is active
power management, reactive power management, right through all these. The last layer is business, which is making
users of it, the aggregators where third party vendors
come in and try to use all these layers and make a business model out of this. As you can see, the architecture here seems
to be the thing that [inaudible]. So a lot of people think of functions first,
but here they suggest communications first, which I wanted
to point out. Between BDEW and VDE they are not the same. A lot of people kind of use it
interchangeably but they’re not the same. BDEW is applicable for those interconnections
that happen at medium voltage, which is in Germany anything above 6 kV up to 30 kV,
whereas VDE is applicable for those systems that connected to residential level, which
is typically 400 volts or lower. But the reason VDE 4105 insists on reactive
power support, where voltage support is mostly needed, as opposed to BDEW, where let’s
say we speak a lot about frequency support. And as you can see, these standards were in
place well ahead of time, 2012. And
let’s hope that Europe took it well. They inherited most of these requirements
and at the European level ENTSO-E, which is European
Network of Transmission System Operators for Electricity inherited all these
and made it a blanket standard or requirement in Europe. Similarly Italy and Spain as well did the
same thing; they upgraded their requirement as soon as BDEW came out in 2009,
and that means in Italy, December 2011 is when all the medium voltage standards came
in place and AEEG from March 2012 came in requirement, which means as soon as
somebody in Europe identified the need for these decides or the point sequences if the
penetration increases, identified the rest of the
Europe more or less. And the same thing happened in Spain as well. Going through a specific example in India,
because I have been part of a few efforts in
India. With my reference I’m trying to say how is
India taking care of increased penetration in renewables. India, as you can see, is governed by CEA. CEA covers all the requirements and
standards on renewables penetration, along with the support of MNRE and numerous
other organizations. India is having a significant increase in
wind and solar. The way the
penetration of transmission level interconnected renewable resources are handed is very
well. There are a lot of pilots going on in India
that by already trying frequency regulation and automatic condition controls,
whereas one zone that could be organized is the DER standards. As I mentioned, that’s where the hard part
is. In U.S. it’s a little bit
more than ten years to make standard out of all the requirements. When I was in India I could see a lot of multi-megawatt
projects going on in solar and wind, and the hard part is the odd year. So one of the good practices that developing
nations, or nations that are seeing these DER penetrations can do is maybe they can
learn or we all can share our knowledge and learn
from how these lessons learned from the past can be implemented, which means – at that
time when the requests for information keep coming it’s better to categorize them quickly,
screen them, and identify whether that means a quick run through or that needs to
be dealt in detail. So typically in California, in Hawaii what
they do is they break the interconnection requests into three categories. One is immediate pass-through, needs a quick
screen, which takes a few days, maybe weeks, and a
detailed run which is a case-by-case, which can take months. And more than that, it’s good to have a few
bonds, such as at the site of the DER, which needs to be interconnected,
not exceeding a certain percentage of the maximum peak loads. They can get immediate requirement and pass-through
or that needs to be analyzed. In a typical scenario in California utility might be a few hundred cases or
requests that can come every week. And it can be the case in most of the initial
[inaudible]. So
as long as not well organized what happens is it becomes a big burden and very hard to
pass through. And more than that, as the advance inverters
of all these 24/7 standards coming in, just along with saying yes to interconnection requests
the requirement here is to also use the technology and make benefit out of it. That means if I way I want reactive power
support from these DERs it’s also important to have
a way to optimally identify them and use them. Just to summarize, some of the key things
that I mentioned I wanted to throw light on. 1547 or grid codes, do not apply for all interconnections
that happen at all voltage levels. They both are handled separately. In USA P2800.1, which is currently a work
in progress with NERC and IEEE is trying to come in play
in the next few years to handle those interconnection requests that need to happen
at transmission level. Could be PV and
storage. Whereas 1547 is applicable only for those
interconnections that happen at medium voltage or lower. Since there is a big count, sheer magnitude
and count of these DERs it’s hard to come up
with a new standard as opposed to transmission levels. It’s better to just learn from all
these existing standards that have been thought through. There has been a lot of effort
that has gone through to make these grid codes happen and a lot of arguments and time
has been spent on this, which means to say that every number you see in a standard or
a grid code has been well thought through. If I say 44 percent there’s a reason why there’s
44 percent – why not 43 percent? Every detail that you see in a standard there
is some analogous report by a national lab or
a university as to justify that particular requirement or a number. It’s much easier to learn
from these kind of – there is Europe, there is USA, there is Australia. All these new
standards can be picked up and learned from for all the other future developments. And all these standards are documents that
keep changing, which means every few years they need to adapt and be managed. It’s better to always keep tabs on what are
the next things that can happen. More than anything, one thing which I would
insist is if third party vendors or customers are buying these technologies such as DER
it’s going to be an advantage for utilities or
transmission coordinators to use these technologies to make advantage out of that and
maintain power factor or voltage in a local system. So that’s my slides. Thank you.>>Julie: Great. Thank you, Adarsh, for talking about the need
for an evolution of grid codes, both in the U.S. and internationally. I think there’s a lot that can be learned,
especially without needing to reinvent the wheel, as you’ve pointed out. So before we go into questions and answers
I’d like to encourage our viewers and listeners to submit any questions you might
have in the questions pane. And we already
have a few questions coming in. Before we go to those I want to encourage
everyone to find more resources, not only on grid codes
and the evolution of grid codes at many other grid integration-related topics at So the first question that we had come in,
and I think is very relevant is a question about
cost. So how does meeting more stringent requirements
for these DERs and for these more advanced grid codes, does it impact the
overall cost? Or does it add incremental
costs to the system?>>Adarsh: I would say the answer is yes. These grid codes do add some cost. However,
the point here is the incremental benefit that we can get out of these devices certainly
exceed the cost that gets added because of these new technologies. So give an example, if there is a high penetration
scenario in a particular region and if every inverter costs a little bit more because
of these new technologies the benefit that the
grid gets out of it from avoiding upgrades, or totally avoiding the need for voltage control
equipment such as capacitor buying for voltage regulators certainly exceeds the extra
costs that comes from this avoidance. And these costs, because it’s implemented
at the worldwide national scale level they’re very minimal. So certainly there is more benefit than to
the cost. And when it comes to
energy storage these grid codes might say that use a battery in a particular way but
there is a lifetime associated with the battery. That’s another scope that is still currently
being evolved and being tried to understand. And there are things that have been done as
well to manage that part. For example, if an inverter that’s currently
used for [inaudible] reactive power support might die a little faster than
not using it. In order to manage that there is
some research going on as well. But this is summarized, what has been learned
so far as the costs are certainly – the benefits are
more than the cost that needs to be added, and
also the life of the device is then significantly decreased because we are using these for
new benefits out of this.>>Julie: Great. You talked quite a bit about DERs and a question
has come in on efforts – if there are similar efforts at the transmission
levels for wind and solar, or if these grid codes can be applied in the same way or are
there major differences that people should be
looking out for?>>Adarsh: That’s a good question. As I brought up previously, P2800.1 is currently
an ongoing work in progress. It’s a little bit of a primary state at this
point but that’s one standard that’s currently being worked upon
to address the questions related to interconnection and transmission level. The idea here is maybe 1547 provides some
blanket requirement that all these DERs, all these inverters are technologies that get
connected at transmission level can do, however that needs to be custom tailored, and that’s
the reason by 2800.1 is focused on being developed. It’s at a hard level which is the primary
level where people are still working on and maybe in the next few years there’s
going to be some draft document submitted out of it, just have to wait for it.>>Julie: Data privacy and cybersecurity is
a very hot topic right now, as I’m sure you’re aware of. And so how are cybersecurity and privacy considerations
included in current grid codes? Are they included, or how might people address
that?>>Adarsh: Yes, so that’s one more effort
going on. Cybersecurity requires – there’s a
very high level requirement at the 1547 – if you just scroll the document it’s included;
it’s being addressed at a very high level. It’s not the scope of 1547 to get into details
of cybersecurity or its layers or the way it’s
handled. There is a separate standard that
addresses that particular side of cybersecurity. So that’s already been addressed to some
extent in a different standard and also it is currently being evolved at this point of
time.>>Julie: Islanding is certainly an issue
that has come up in terms of providing additional resilience at facilities and the grid. Are there certain ways that islanding is being
addressed in some of these grid codes? How are DERs being asked to respond in this
situation?>>Adarsh: That’s where the grid codes specific
to fault right through kind of coming feature. If you go long back in time, as soon as there
was a fault or a bad voltage or a bad frequency system needs to disconnect, which
means it needs to go into islanding mode is to shut down, do nothing. There was sufficient requirement on that after
that time it should shut down, how fast can it identify,
what are the scenarios where the system might not be able to identify it because that might
lead to personal issues. If there’s a fire hazard
the system will then shut down in time and you have a fireman who goes on the house. And if it’s still working it’s going to be
a personal [inaudible]. So NEC and other organizations tried to come
up with a lot of requirements on that. However the most important thing now is if
there is a bad frequency event, if there’s a
low frequency event which is already high load, load generation scenario and because
of that all the local generation shuts down that
will further exacerbate the whole scenario. And that’s the reason why 1547 came up with
three categories to identify how to behave or how not to behave. [Inaudible] as I said Category 3 is how Hawaii
and California have chosen when to island. The idea here is to be able to identify what
should the device be doing when there is a fault. And if the device is still operating and there’s
a fault – could be a fire – in order to avoid that what NEC did is came up with
a red button, which is if there is a solar panel
on the house and if the person doesn’t know whether the panel is operating or not what
the fireman should do is go and press the red button, a single switch, outside the house,
that disconnects the device, irrespective if it’s right through, not a right through
frequency event, voltage – or whatever it is. Personal safety takes the priority there. So as I said, 1547 says device should be operating
above 12 seconds but we don’t know whether what common scenario there. And that’s where all other standards cover
those questions, which have NECs and [inaudible]
come in and say, “Hey, that could be a problem. So that needs to be addressed in a particular
way. So what we show here is more like
people’s site books. There’s a whole world outside other than that
which needs to be understood to get the whole context.>>Julie: Another question. We talked a lot about DERs, rooftop solar,
which is a pretty established technology but what about emerging
technologies? You touched a little on
this. Like the high meter battery storage is easy;
how are those being incorporated into grid codes. What are you seeing as that evolves?>>Adarsh: Sure. Storage, there is another effort going in
place that’s going to be 1547.9 subcommittee that will address some of the
questions related to storage. Let us go to the
storage itself; we’ll go back to the some of the questions someone already asked which
is if I use the storage directly will the battery
die in the next few days? It’s a lot of sensitive
area surrounding there. So there again, NREL is leading its way there. We are trying to
come up with those considerations that needs to be thought through even before, or what
are the things that need to be done to address or modify the current 1547 2.9. That’s still
under development and there are a lot of research projects currently going on with
utilities in the USA that’s trying to understand how a customer would typically use
storage and why would they use it? Because all the usage of storage is driven
by human behavior or tariff schemes as opposed to inverters
for solars which is driven by voltage and frequency. So there’s a human component in voltage storage
which makes the whole thing a little more interesting and also complicated. The second technology that you spoke about
which is electric breakers, which is certainly yet another topic. There is a lot of standard development, SAE
that is currently going on – electric breakers is certainly coming
a major thing which is currently also under development. So as you can under 1547 gives blanket rules
that are expected of it but there are all these subcommittees that break
down to see what needs to be striked or what needs to be added to make some sense out of
this or it almost needs to be inherited to make it applicable to new technologies.>>Julie: So we have all of these wonderful
grid codes, trying to ensure the safety and reliability of the grid with new technologies
coming online. How do we make sure people
comply? So is compliance an issue? And how in the U.S. is compliance ensured
to these grid codes?>>Adarsh: So in the end what makes things
compliant is in U.S. it’s UL, Underwriters Lab. That says that every inverter should be part
– should go through UL 1741 SA, which means all the [inaudible] should behave a
particular way. That’s in U.S. In other nations
there’ll be their local standards, maybe ISO, maybe something else. All these – so there
are – everything should happen in two levels, which is the local entity or the nation
should come up with a requirement, for example what happened in California. The
governor of California sent us a letter that says all IOUs for utilities should comply
to a certain rule, that’s Rule 21, in their territory. That says that – okay, so now it’s a blanket
rule that things should work a particular way, but there is no requirement that inverters
operate a particular way. That’s where the UL comes up and says, “Okay,
hold on. So
before you make the inverter go on a particular roof or somewhere you will need to pass
these set of tests, test conformance standards. And there’s also a [inaudible] for
communication now. So all these things when passed are checked,
then that means you can say the blanket rule that, okay, all these
devices operate a particular way; compliance is taken care of. It should operate in different levels to make
sure all inverter vendors are aware of all these. And that’s the reason why I spent a slide
on this topic where a transfer in stakeholder process is a key to make sure
everybody, all important stakeholders, are on
the same boat. Otherwise it’s going to be a gap between what
needs to be done as opposed to what is going on because they might
say [inaudible] or I don’t even know. I’m
doing a very different way or – it’s – that leads to a lot of diverse scenarios that’s
very hard to manage.>>Julie: So it really sounds like it’s all
about the inverter.>>Adarsh: That’s one thing. So that’s where all the growth is happening. For example, if
you go to a 1547 standard goal and to say that [inaudible] that they say that this [inaudible]
code is applicable to all generators – could be
diesel generator, could be something else. But
however when you look at the proportion of the growth happening there is a significant
growth happening when it comes to inverter interface technologies as opposed to diesel
generators. So what are the odds that somebody might go
and buy a diesel generator? But
the whole idea is any generator or technology that has the ability to operate in parallel
with the grid, not when there is a shut down or a microgrid scenarios, that’s where the
whole grid codes comes into picture. But inverters are the key interface that makes
these technologies or any other resources, could
be emerging technologies like storage or car, electric breakers, all these technologies
applicable and controllable and usable. So there is a significant need for inverter
manufacturers and vendors to work in tandem, state nations or entities.>>Julie: The last question for you is if
I were living in a country where perhaps I didn’t
have a large penetration yet of the ERs or I was starting to see the scale-up of DERs
rapidly what advice would you give me to start thinking about grid codes or the evolution
of my grid codes? Where do I start? Where do I go?>>Adarsh: First thing I would say is this
is my firsthand experience being in working with utilities in the first decade, which
is don’t wait for too long, not knowing – or it’s
very little we can leverage there, but don’t wait for too long. Look at these technologies
as assets, more than just somebody wants solar, just let them go with it. Be aware of all
the development happening in their part of the world. There is a very particular need or
purpose behind every sentence, every grid code in their part of the world. The reason why everybody is working on a grid
code is to handle a problem that they had in the past. Maybe if you’re a nation or if the country
– not right now I’m seeing some penetration, it’s a good scenario for them
to just learn from what’s already being done and
just make it a standard before anybody gets to a high definition scenario. So don’t wait
too long, just jump on things, learn – there are numerous things that happen surrounding
this to share the knowledge, make it a requirement even before it goes out of hand.>>Julie: Excellent, Adarsh. Thank you so much. And I do want to point folks, again, to for more resources, and now I’m going to pass this over to Julie to
finish up.>>Katie: Great. Thank you again, and on behalf of the Clean
Energy Solutions Center I’d like to extend a special thank you to our
expert panelist and to our attendees for participating in today’s webinar. We very much appreciate your time and hope
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