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<DIV><FONT color=#0000ff size=2 face=Arial><SPAN class=117333116-14102010>CSI
Field Verification method requires multiplying the CEC-AC Watt rating of the
system by the percentage found in the table. (Not STC DC as originally posted).
Correction made in body of message below.</SPAN></FONT></DIV>
<DIV><FONT color=#0000ff size=2 face=Arial><SPAN
class=117333116-14102010></SPAN></FONT> </DIV>
<DIV><FONT color=#0000ff size=2 face=Arial><SPAN class=117333116-14102010>-
Imperfect Janitor</SPAN></FONT></DIV>
<DIV>
<HR tabIndex=-1>
</DIV>
<DIV></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT color=#0000ff
size=2 face=Arial>Marco,</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT color=#0000ff
size=2 face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT color=#0000ff
size=2 face=Arial>Are you looking for an instantaneous AC power output
number based on equipment configuration and environmental conditions? Accurate
to within a few percent one way or the other? To have a general idea if the
system is performing properly or not?</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT color=#0000ff
size=2 face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010></SPAN><SPAN
class=218551404-13102010><FONT color=#0000ff><FONT color=#000000 size=2
face=Arial>You need a lot more than just irradiance to figure it out.
</FONT><SPAN class=218551404-13102010><FONT color=#000000 size=2
face=Arial>Energy generated over time is generally a much better metric for
customer use than instantaneous power output.</FONT></SPAN></DIV>
<DIV dir=ltr align=left>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT color=#000000
size=2 face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT color=#000000
size=2 face=Arial>The basic process requires determining an "Expected" output
and comparing it to a measured or observed value. In our case, we are looking
for watts. AC Output Watts specifically. </FONT></SPAN><SPAN
class=218551404-13102010><FONT color=#000000 size=2 face=Arial>Can't stress
enough how important it is to manage customer expectations. Would love
to hear how the customer ever heard of a PTC rating in the first place, and how
they came to think it would be representative of the power output at the
inverter... I am of the strong opinion that we should present conservative
expectations. Under-promise and over-deliver. </FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT color=#000000
size=2 face=Arial></FONT></SPAN><SPAN class=218551404-13102010><FONT
color=#000000 size=2 face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT color=#000000
size=2 face=Arial>Part of managing expectations successfully includes
establishing an acceptable range of accuracy tolerance. The California Solar
Initiative requires a Field Verification of performance that has pretty wide
tolerances. You might want to use this methodology with your customer. CSI forms
are available from the program administrators (utility company). PG&E's
version is here: </FONT></SPAN><SPAN class=218551404-13102010><FONT
color=#000000 size=2 face=Arial><A
href="http://www.pge.com/includes/docs/word_xls/shared/solar/csi/form_fieldverificationcertification.xls">http://www.pge.com/includes/docs/word_xls/shared/solar/csi/form_fieldverificationcertification.xls</A></FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT color=#000000
size=2 face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT
color=#000000></FONT></SPAN><SPAN class=218551404-13102010><FONT
color=#000000></FONT></SPAN><SPAN class=218551404-13102010><FONT
color=#000000><FONT face=Arial><FONT size=2>To use the form, multiply
the <SPAN class=117333116-14102010><FONT color=#0000ff> CEC AC
Watt </FONT></SPAN>rating of your system by the factor found in the table
for your measured plane of array irradiance and ambient temperature in
degrees Farenheit. As long as your inverter display says the system is putting
out at least that value, it's "acceptable". In my opinion, this is fine for
laymen but far too loosey goosey for any real technical evaluation or
diagnostics. <EM>User Note: Do not attempt to use this method when any part of
the array is shaded.</EM></FONT></FONT></FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT color=#000000
size=2 face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT color=#0000ff
size=2 face=Arial>SolarPro 2-6 (Oct/Nov 2009) had an article on Commissioning
that had a decent rundown on the process from a commissioning/acceptance
perspective. <EM>(Same article that Jamie J is talking about).</EM> You are
looking for the process described on Page 52. If you are planning on providing
your customer with this formula so they can figure it out any time they
want and stop bothering you... I would tweak it a bit so it is more useful
on a regular basis. So they actually stop bothering you
sooner.</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>The basic formula that you are looking for is
this:</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>Minimum Expected Power Output = Total STC Watts * Irradiance
Factor * Temperature Factor * System Derating Factor</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>This formula includes variable and constant values. The System
Derating Factor is made up of several factors, some of which are
variable and some of which are constant. And therein lies the rub for the
purpose of handing it to your customer and hoping never to hear from them again
unless there is a real problem. As opposed to a perceived problem, that
is.</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>From my standpoint, I don't want potentially irrational customers
with scientific calculators trying to estimate a shade factor for
instance. Unless there isn't any shade. Same goes for soiling.
</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>So, back to coming up with a formula that you can hand them so
they can run back and forth between the roof, the inverter, and their computer.
The key here is, well.... A couple things toward expectation
management.</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>First and foremost, a single measurement does not a comprehensive
evaluation make. Ain't happenin'. You (they) need to measure, observe, and
record multiple measurements, over time, to gain a real understanding of the
performance characteristics of a given system. Trends matter. A lot more than a
single point-in-time measurement. If your customer is an engineer or accountant,
tell them it's Statistical Process Control and they'll be
happy.</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>Secondly, point-in-time instantaneous measurements are subject to
changing environmental conditions. Also known as <EM>"the math don't always add
up syndrome". </EM></FONT></SPAN><SPAN class=218551404-13102010><FONT size=2
face=Arial>You need to take all your measurements and observations at
precisely the same instant. This is harder to do than it might seem.
Particularly when the array is remote from the inverter and the prevailing
environmental conditions aren't perfectly stable. One commonly overlooked
variable here is wind. We don't measure the windspeed during our process and,
frankly, without a long string of site-specific measurement data, we couldn't
factor it in anyway. What does matter is the effect of wind on module
temperature. A slight change in windspeed or direction can have a very dramatic
effect on module temperature and, by extension, power output characteristics. If
you record the module temperature and inverter displayed output at slightly
different times, you can end up with very different results. Same with erratic
irradiance. If you have fluctuating temperature and irradiance, good luck trying
to crunch the numbers to any significant degree of accuracy.</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>Thirdly, you need to perform the procedure separately for each
inverter (system). Some will argue about this, but the fact of the matter is,
you either do them separately or you accept a much wider accuracy tolerance. If
your customer is of the belief that they will regularly see the DC PTC
rating of the array show up as AC Power Output on the inverter display.... Their
glasses are probably too thick to accept wide tolerance ranges. Lifetime
thick-lenser typing this, BTW...</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>Fourthly, if that's a word. Instrumentation accuracy tolerances are
what they are. Some are published. Some are not. Some are lies, published as
facts. They are all <EM>"plus or minus something".</EM> Hard part is
understanding when it's plus and when it's minus and knowing what to do with
that information. Pyranometers are NOTORIOUS for range of accuracy issues, and
they ALMOST NEVER match their own specifications in the irradiance range you are
currently measuring. If you are relying on a weather-station or similar DAS info
to provide environmental data, you have some other issues to contend with.
Latency being the biggest underlying culprit. DAS systems are wonderful tools
for establishing trends and identifying out-of-character performance over time.
They suck for instantaneous evaluation. Suck is actually an incredibly
insufficient term for describing how bad they really are for this application.
</FONT></SPAN><SPAN class=218551404-13102010><FONT size=2 face=Arial>Get
handheld instruments and use them. If your customer wants to do this, they need
to spend $200. <EM>($120 for General Instruments DBTU-1300 Solar Power Meter and
$80 for an Infrared Temperature Probe. Best price I've found for the 1300 is
here: <A
href="http://www.ambientweather.com/gedbtu1300.html">http://www.ambientweather.com/gedbtu1300.html</A>)</EM></FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>Fifthly, measure irradiance at the Plane of Array! Any other
methodology for this exercise is bull$&!t. I don't give a rat's hind end
what the instructions say. If you've only got one pyranometer, throw the
leveling base away. </FONT></SPAN><SPAN class=218551404-13102010><FONT size=2
face=Arial>I don't care that the bonehead at the monitoring company tells you
they have some algorithm that compensates horizontal irradiance to system
performance. It is totally OK to measure irradiance in a horizontal plane
when going thru this exercise. As long as you ignore that value and also measure
irradiance at the Plane of Array.</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>Sixth is understanding that baseline power measurements should
be made with zero shading on the array. Period. There is NO MEANINGFUL BENEFIT
to going thru this exercise if any portion of the array is shaded. NONE. When
dealing with shaded arrays, the only metric that is meaningful is the amount of
energy produced over time. And that's not what we're doing
here.</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>Seventh is sort of a mixed-bag of best practice and potential to bite
you in the ass. In theory, the "best" time to evaluate the power output of
a system is when the sun is at solar noon relative the array azimuth. This isn't
always practical. Particularly with array azimuths closer to East or West than
South. In addition to actually having to be present when solar noon rolls
around, the weather also needs to cooperate by moving the clouds over to the
neighbor's house. </FONT></SPAN><SPAN class=218551404-13102010><FONT size=2
face=Arial>Even if the timing is not a problem, during non-winter weather,
the module (cell) temperature is likely to be higher and
climbing at this time than others. Which does a couple things....
Generally speaking, it drives the operating voltage lower when the potential
irradiance is at its peak for the day. When you go thru the exercise of
isolating various factors, you will find that module temperature has just as
dramatic an effect on system performance as irradiance does. When you really dig
into this, you will find that the published Coefficient of Temperature for Power
is pretty much erroneous at module temperatures above about 45C.
</FONT></SPAN><SPAN class=218551404-13102010><FONT size=2 face=Arial>Actual
observed outputs with high irradiance and high module temperatures are generally
lower than your theoretical "normalized" or "expected" calculations. Which, of
course, results in a phone call or email from your customer. In practice, I
basically "open up" the tolerances as the module temperature
rises.</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>Ocho. Soiling. Unless the modules are sparkling clean, there is going
to be some effect from soiling. Estimating actual soiling effect based on
observation alone requires experience. I'm not going to get into a class on
evaluating soiling effects in instantaneous performance verification here.
Suffice it to say that, if there is soiling at all, it's probably degrading
system output between one-quarter and ten percent. The same soiling will have
differing power characteristics at different temperatures and irradiances
throughout the day. </FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>Ninth is Age. How old is the system? Do non-module components degrade
in performance over time? Pick an annual degradation rate and use it. We used to
use 1% per year, but I think that practice is waning. I've seen a lot of
empirical monitoring data that indicates modern systems seem to be aging without
any meaningful degradation at all out to Year 5 or so. Nevertheless, I recommend
multiplying age in years by a factor of about 0.9925. This is really rather
arbitrary on my part... PV system output doesn't degrade from 100% on Day 365 to
99.25% on Day 366. In practice, I believe that we should account for some aging
and this is the balance I came up with. Pick your own number if you
like.</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>Tenthly should have been first. Shading. This procedure should NOT be
done if any portion of the array is shaded. Not by a layman. Not for the purpose
of evaluating system performance. None. Zero. Zip. Zilch. Nada.
</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>Eleventhly is a little moot at this stage, but worth mentioning. If
you had sold the customer a micro-inverter system, they would already know their
answer.</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>But let's move on to actually quantifying the factors and values in
the formula.</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>The Total STC Watts value should be self-explanatory in this forum. I
will reiterate that you need to do this on an inverter-by-inverter basis, so be
sure to only count the array that is connected to the inverter being evaluated.
This is a Constant value for each system.</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>The Irradiance Factor is pretty straightforward, too. To calculate
this, divide the measured Plane of Array Irradiance by 1000. <EM>eg. 850 W/M2 /
1000 = 0.85 Irradiance Factor.</EM> This is a Variable value that must be
measured and recorded each time you go thru this process.</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>The Temperature Factor is not equal to the temperature. This factor
is used to represent the difference in power between STC and the conditions
under which this test is performed. You need to measure the temperature,
<STRONG>in degrees Celsius</STRONG>, at the back of the module every time
you do this test. <EM>(</EM></FONT></SPAN><SPAN class=218551404-13102010><FONT
size=2 face=Arial><EM>I recommend using an infrared temperature probe and
targeting the center of a cell in the middle portion of a module. This can
be difficult on low-profile flush-mounted rooftop arrays. Do the best you
can.)</EM> The SolarPro article uses the Mfr temperature coefficient of power
for this factor. In a commissioning environment, this is the proper thing to do.
In a <EM>"homeowner wants to check his system every now and then"</EM>
environment, not so good. </FONT></SPAN><SPAN class=218551404-13102010><FONT
size=2 face=Arial>For CSi modules, I use a flat <EM>"half-percent per degree
Celsius method"</EM>. This makes the math quite simple and straightforward. To
compute the Temperature Factor, subtract 25 from the measured module temperature
to get your temperature differential. Multiply that number by 0.005. Subtract
this number from 1 and you have your Temperature Factor. In practice, it goes
like this: A temperature differential of 25 degrees equals 12.5% loss or a
Temperature Factor of 0.875. A TD of 40 degrees equals a TF of
0.80.</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>And now we're into the System Derating Factor. Which combines
Variable and Constant values. In a commissioning environment, this may
be acceptable. In the homeowner case, not so good. I recommend stripping
out the Variable factors and treating them separately. In my own practice, I
have always treated these separately and strongly urge any and all to do the
same. Perhaps we should elaborate on the various values contained in the
supposed System Derating Factor.... Yeah. Good idea. As outlined in the SolarPro
article, these include 1) Wiring Losses, 2) Module Soiling Losses, 3)
Module Mismatch, 4) Module Nameplate Tolerance, 5) Shading, 6) Inverter
Efficiency, and 7) Age. I consider Soiling, Shading, and Age to be Variable
values. Wiring, Mismatch, Tolerance, and Efficiency losses are System
Constants specific to the system being evaluated. We can argue about whether or
not inverter efficiency is a constant or variable value, but I'm calling it a
constant and think you should too. </FONT></SPAN><SPAN
class=218551404-13102010><FONT size=2 face=Arial>I think it is more than fine to
combine these under the System Derating Factor heading. In order to combine
individual factors into a single composite factor, you multiply them by one
another.</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>A) Total wiring losses need to be accounted for and converted to a
positive factor format instead of % loss. If you don't do this correctly,
you will inadvertently end up with skewed numbers. I find that the best way to
do it is to think of this as a "wiring efficiency" factor instead
of losses. If you have a DC loss of 1.5%, that's actually 98.5% efficient or a
Wiring Efficiency Factor of 0.985. You treat the AC in the same manner.
Multiply your AC efficiency by your DC efficiency to get your system efficiency
factor. <EM>eg. A DC wiring loss of 1.5% & an AC wiring loss of 0.5% equate
to a System Wiring Efficiency factor of 0.980075, which I would round to
0.98.)</EM></FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><FONT face=Arial><FONT size=2><SPAN
class=218551404-13102010>B) Module Mismatch needs to be calculated. My
methodology is to base this on the Power Tolerance Range. The Power Tolerance
Range is the sum of the absolute + and - values of the module Power
Tolerance. A +10%/-5% module has a 15% Power Tolerance Range. I multiply the PTR
by 0.25 to get a Mismatch Loss value. Subtract this number from 1 to get your
Module Mismatch Factor. <EM>eg. A +10%/-5% module would have a 3.75% Mismatch
loss, which equals a 0.9625 Module Mismatch Factor.
</EM></SPAN></FONT></FONT></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>C) Power Tolerance Factor. This is pretty easy from my standpoint.
Since we are calculating a minimum acceptable value, I say use the Minus value
of the Power Tolerance and convert that to a factor. <EM>eg. A +10%/-5% module
has a 0.95 Power Tolerance Factor.</EM></FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>D) Inverter Efficiency Factor. I will probably differ from some on
this. My methodology is to subtract 1% from the CEC Weighted Efficiency value.
<EM>eg. An inverter with a CEC weighted efficiency of 95.5% would have an
Inverter Efficiency Factor of 0.945.</EM></FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>Multiply A * B * C * D to get your System Derating
Factor.</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>Age, Shading, Shading. Hmmm. What should we call this factor?
</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2 face=Arial>I
say it shouldn't be treated as a single factor, so no, it's not the ASS factor.
These are distinct and discrete variables that need to be treated that way. As
such, my recommended formula gets longer than the one mentioned earlier on. It
looks like this:</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2 face=Arial>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>Minimum Expected Power Output = Total STC Watts * Irradiance
Factor * Temperature Factor * System Derating Factor * Age Factor * Shading
Factor * Soiling Factor.</FONT></SPAN></DIV></FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>Age is pretty straightforward, as discussed above. Figure out your
Age Factor and plug it in to the formula.</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>If you follow my methodology, the Shade Factor would be 1.0 since no
testing can be done if there is any shade at all on the
array.</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>Soiling is a dirty beast. For instantaneous measurements, you do need
to come up with a Soiling Factor. And that's hard to describe to somebody. I
generally tell people to think of it this way: <EM>"Really, really dirty glass
is gonna max out at about 10 percent loss. This is very uncommon.
</EM></FONT></SPAN><EM><SPAN class=218551404-13102010><FONT size=2
face=Arial>Stuff like caked mud, lots of bird doo-doo, restaurant grease covered
in dirt. If you can't clearly see all the individual cells, you have really,
really dirty glass. Kinda</FONT></SPAN><SPAN class=218551404-13102010><FONT
size=2 face=Arial>-dusty but mostly-clean is gonna ding ya about one or two
percent. If you can blow on it and all the dust blows clear, that's kinda-dusty.
</FONT></SPAN></EM><SPAN class=218551404-13102010><FONT size=2
face=Arial><EM>Really-dusty is gonna be something like five or six percent.
Really-dusty won't just blow off. You need to brush it or wash it off, but you
can still clearly see the individual cells everywhere. If you never wash your
modules and just let the rain do it, in most cases the very worst you'll see is
about eight percent loss during part of the year. Washing modules with hard
water is one of the worst things you can do. So don't do it."</EM> And I leave
it at that. It truly is a judgement guess and it will vary by site and season.
Unless the array was just cleaned, I use a factor of 0.99 or
lower.</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>The way to provide this to your customer is in a spreadsheet. Have
the constant values for their system filled in and fields for them to enter
environmental data and observed inverter output power. You can have the sheet
automatically calculate the expected output power and compare that to the
observed value. </FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2 face=Arial>I
suspect that, once you think all this thru, the CSI Field Verification Form
methodology will be more than sufficient. ;) Remember to tell your customer that
they have to at least by a handheld pyranometer if they want to do instantaneous
output verification.</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>$0.02001</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial>Solar Janitor</FONT></SPAN></DIV>
<DIV dir=ltr align=left><SPAN class=218551404-13102010><FONT size=2
face=Arial></FONT></SPAN> </DIV></FONT></SPAN></DIV>
<DIV dir=ltr lang=en-us class=OutlookMessageHeader align=left>
<HR tabIndex=-1>
<FONT size=2 face=Tahoma><B>From:</B> re-wrenches-bounces@lists.re-wrenches.org
[mailto:re-wrenches-bounces@lists.re-wrenches.org] <B>On Behalf Of </B>Marco
Mangelsdorf<BR><B>Sent:</B> Tuesday, October 12, 2010 6:17 PM<BR><B>To:</B>
'RE-wrenches'<BR><B>Subject:</B> [RE-wrenches] insolation v. actual
output<BR></FONT><BR></DIV>
<DIV></DIV>
<DIV class=Section1>
<P class=MsoNormal>Could someone please provide me with that generally accepted
equation when it comes to estimating AC output from a PV array versus the STC
rating?<o:p></o:p></P>
<P class=MsoNormal><o:p> </o:p></P>
<P class=MsoNormal>That is, I’m looking for that equation which estimates the
losses due to mod mismatch, soiling, wire losses, etc., etc. I’ve got
someone who mistakenly expects their PV array to put out 90 or more percent of
the STC rating.<o:p></o:p></P>
<P class=MsoNormal><o:p> </o:p></P>
<P class=MsoNormal>Thanks,<o:p></o:p></P>
<P class=MsoNormal>marco<o:p></o:p></P>
<P class=MsoNormal><o:p> </o:p></P></DIV></BODY></HTML>