IEEE SCC21 P1547.1 Working Group Meeting Minutes, 6/12/18 …grouper.ieee.org/groups/scc21/1547.1_revision/mtgMinutes... · 2018-12-07 · IEEE SCC21 P1547.1 Working Group Meeting

Minutes – P1547.1 Meeting, June 12-14, 2018 Waltham, MA Page 1

IEEE SCC21 P1547.1 Working Group Meeting Minutes, 6/12/18-6/14/18

“IEEE P1547.1 Draft Standard Conformance Test Procedures for Equipment Interconnecting Distributed Energy Resources with Electric

Power Systems and Associated Interfaces”

Chair: Anderson Hoke

Vice Chairs: Babak Enayati, Karl Schoder, Tim Zgonena

Secretary: Jeannie Amber

Treasurer: Charlie Vartanian

The seventh meeting of the P1547.1 Working Group (WG) was held in Waltham, MA June 12-14, at National Grid. The goal of the meeting was to review Draft 6 of the full revision to IEEE Std 1547.1. The P1547.1 standard is intended to be the test procedures to conform to IEEE 1547-2018, which was published in April. Summary highlights: Background and introductory material was presented by the WG chair, followed by presentations from the chairs of a subset of P1547.1 subgroups. Each subgroup reviewed its draft material and discussed present work and challenges for the subgroup. The meeting will be followed up by various electronic communications and teleconferences to continue drafting the revised standard, including a pre-ballot draft prior to the next WG meeting. The next P1547.1 WG meeting will be held October 9-11, in Los Angeles, CA, hosted by Southern California Edison. Items that require follow-up actions are shown in bold italics. Tuesday, June 12, 2018 Meeting called to order and introduction The meeting was hosted by National Grid, and organized by Babak Enayati, who gave a brief overview of the facilities and safety procedures. Chris Kelly, SVP of Electric Process & Engineering at National Grid, welcomed the group and thanked the group for their work. He stressed the importance of the standard especially now that DERs are affecting the transmission system. Anderson (Andy) Hoke, chair, verified that we have at least 34 of the 68 WG members in the room, which established quorum. Andy requested attendees state their names and affiliations. Each attendee accordingly stated his or her name and affiliation. Andy reviewed the IEEE policies and procedures, including the policy on potentially essential patents. Andy made a call for essential patents - none were raised.


Andy asked for comments on the meeting minutes from the March WG meeting. There were no comments. Brian Lydic moved to approve the minutes from the last meeting. Mamadou seconded it. No abstentions. The meeting minutes were approved. Andy reviewed the subgroups, including the new Prioritization of Responses and Results Reporting. Participants can contact Bob White and John Berdner for those groups. • Prioritization of Functions - 2pm Eastern on Mondays

The WG's goal is ballot-ready draft by October meeting, with a pre-ballot draft to be circulated prior to Oct. meeting for written comments to be addressed by the subgroups prior to the October meeting. Babak pointed out that ISO NE recently required MA (and NE) utilites to require ride through with UL1741SA. Secretary’s note: Presentation slides from the meeting are stored on iMeet under ‘Meetings’ in the June 2018 meeting’ folder, or in that of their respective subgroups. Interoperability Brian Seal and Bob Fox Meetings Wednesdays 4pm Eastern The subgroup leads discussed the approach of the standard, which is that the vendor chooses whether they're tested for more than one protocol standard. Only one at minimum is required. The listing shall identify the protocol(s) used. The working group chose at a prior meeting to reference specific versions of protocol standards. Discussion on verification of set settings. • Typically 2 values per setting required for interop testing

1. Set a setting, see effect. 2. Change setting, see effect. • Have seen examples of when set value, read value, BUT power measured (actual response) DOES

NOT MATCH the read value. o Must see the actual response of the setting change, not just 'Yes, I did it". Instead,

demonstrate the results of the new setting. Discussion on referenced protocol standards

• Not intended to replace or duplicate separate protocol standards testing or listings • The referenced protocol standards are ready (weren't in March) but are close to their

completion processes • Nachum asked whether we'd chosen to do a freeze or use the latest and greatest standards. • Jeannie and Brian recalled from the Fall meeting the working group had chosen to reference a

specific version of the standard (was not an official vote). o Nachum pointed out that the software world moves much faster… He's concerned that

the organization will not support a standard that is 3 years old, for example. • Brian Seal agrees that referencing a specific version of the standard can create other issues as

above. • Jim Daley and Howard discussed how utilities implement the standard and other

requirements. There are interconnection agreements with utilities, which reference state


tariffs, UL1741, IEEE1547 (typically but not necessarily latest version), and utility-specific requirements.

• Brian Seal and Bob: If manufacturers don't break backwards compatibility, they can test to later standards. Should probably use the words 2030.5-2018 "compliant" - means you can be using a later version, but still be compatible with that older version.

• Bob White pointed out that the base standard doesn't reference any specific versions of those protocol standards.

Discussed at the last meeting continuity of settings through power cycles, trips, etc. o Missing in base standard. o In the functional tests, we NEED to test the above

Between the last meeting and now the subgroup didn't resolve the lock/unlock of the comm interface • DNP recently had a mechanism added to support this, but it's not yet in 2030.5 or SunSpec • Mark Smith at the last meeting had commented: don't mention it in the standard - that's

contractually between the utility and the project proposer. • Brian asked the group to weigh in

o Jim Daley agreed that the interconnection agreement is the overarching document. He also pointed out that it's pretty easy for a manufacturer to lock those settings to prevent access to them.

• Brian Seal: Is there anyone that would insist on having a means to enable/disable the comm interface? o Mark Smith commented that the decision could be part of the utility's design review o Kevin Chen - if this is a feature, he'd like to see it tested. But doesn't want to say it's

required. o Jim Daley gave an example - a stated feature of the product was tested - 5 levels of

access • Tim Zgonena clarified that not all stated features of products, unless part of the

standard being tested to, are tested by UL • There was some further discussion on 'pertinent' functions to the 1547 standard

being tested… • Ben Ealey (EPRI) brought up previous discussions on the state of the equipment during

testing. o Bob Fox: Equipment must be put into a state to be tested to the standard. How that's

done is out of 1547.1 scope… o Jeannie suggested adding that the required steps to get the device into the required

test mode. o Paul Krell: there can be some value to that general statement for the rest of the

standard. There might be required general statements, including software setup, to make this operate validly with 1547. Agrees with Jeannie, and in a more general sense.

o John Berdner: Lots of this stuff can be required to be in the device user manual. • Jeannie and John Daley pointed out section 4.4 in 1547.1

o Interoperability Subgroup to work with results reporting and general requirements subgroups on this

• John Berdner is still very much concerned about excluding security from the standard • Ben Ealey pointed out that having to do one different 'unlock' sequence for each

manufacturer/etc. would create issues • Brian Seal: we're not going to specify how it's done, but you must document how it's done.

o *would specify in the next iteration of the 1547 standard


Default settings and what happens when a function is 'disabled'

• Jeannie and Babak pointed out that the base standard has default settings the device could revert back to.

• HOWEVER the interconnection agreement may have different defaults, and that's somewhat out of scope...

• Many modes are mutually exclusive - think of it as a 'selector switch' - Reigh • Brian Seal - for functions that are mutually exclusive, the act of asserting that function de-

asserts the previous function. • Hawaii wants 0.95 lagging power factor by default - Fred Horton? • Protocol has for an enable/disable on Volt/VAR controls • John: Using fixed PF is probably a bad example. If disabled, goes to fixed PF at unity PF. • Bob: When you re-enable something, you have to specify the settings to re-enable.

o John: 1: when disabled, doesn't sound good idea to decide what to do next. 2. Retaining what Volt/VAR was last set at, is another thing, BUT not covered today in the base standard.

• Brian Seal: Devices are in 'undefined state by 1547.' If you disable 'Volt/VAR' until you enable the next mode, it's NOT defined what you get. You HAVE to say "deactivate x AND activate Y with the following settings"

• Enable/disable is one variable and setting is another. • Ryan McMaster: It sounds like the interconnectors just need to know how it works to implement

it… unless it's a safety matter, etc… • Brian Lydic: CSIP - Cali smart inverter profile - has a set of reqs for 'immediate controls' -

optional • Babak: If I specify an inverter to operate in Volt/VAR - will send another command for unity PF

operation…not sure why the discussion matters. Makes the assumption that enabling one function will then allow you to enable the next function.

o John Berdner: Different folks may have different understandings of 'mutually exclusive' functions

o Bob White and John Berdner advocate for disabling a function and then enabling the next function, even if 'mutually exclusive' functions mean you can't do two functions at once. Bob states it's good control theory to turn one function off before turning the next one on.

• Brian Seal: Simplest method is only to have the functions requested be the required/expected functions. No expectation of history/record keeping….

o Brian asked: Does this meet everyone's needs? • Haile pointed out that the base standard, 1547, does require that they are mutually exclusive. • Babak: To me that implies that when you turn on a new function, it turns off one of the mutually

exclusive functions automatically. Based on this discussion, it appears important to make sure everyone agrees what mutually exclusive means. To some, it’s a selector switch that turns one off and turns on another automatically, like a physical switch. However, others may not agree.

• Mark Smith: you need to include the basics of your equipment test and we are not at present. • Brian Seal: agreed.

Interoperability Test Outline

Test Reqs


• General test reqs • Function by function

DNP3-specific SunSPec specific 2030.5 specific

• DNP3 added a table of 1547 settings into their standard

General Requirements Subgroup Andy Hoke, subgroup chair Meetings are on Mondays 4-5:30pm Eastern Andy summarized the subgroup’s progress, and noted that the most active participants have been the manufacturers. He noted some questions for the working group: • Should the general requirements briefly describe the big picture of how compliance to 1547 is

achieved for various types of DERs? o Secretary’s note: This would be prudent.

• Can quality controls be used to reduce need for production testing? o Jim/Bob: UL 1741 requires production testing for safety functions o Jim Daley: It's CRITICAL that trip settings, a safety function, are tested during production

testing. You must be clear which tests are eligible to be reduced. • Performance across temperature ranges

o Replace "manufacturer's stated accuracy" with "minimum required measurement accuracy" • Jim Daley pointed out that the original 1547.1 had MSA because there was no defined

MRA to use. • Andy agreed, and noted that it's not a 1:1 replacement in all cases and explained why.

o Keeping content largely as-is from 1547.1-2005, with minor edits • Confirmation of Time Measurement Accuracy and of Transient Measurements

o Proposal: rely on functional tests (trip, Reg, etc.) to verify measurement accuracy, and have no separate tests for these. If the DER performs correctly, it should sufficiently confirm accuracy measurements.

• Harmonics Consensus: For most tests, 3% THD upper limit. But for current distortion tests, preserve same limits as in 1547.1-2005. o Requirement applies to both simulated and actual area EPS used during testing o Babak: Is it instead more appropriate to use THD, as in the base standard, rather than TRD

which is stated here. • Here we're talking about voltage. • Reigh: should be on the base of what you're actually testing. Since you're using

voltage as the base, you'd use THD. o Potential corner case in current distortion test. Have been historical cases.

• Andy: Due to Voltage harmonics on the test source - some inverters have not passed when they actually would have otherwise passed

• Reigh: Is this with the DER connected or disconnected? Reigh suggests that this is for connected DER. If put blocking filter on, would end

up distorting the harmonics. Therefore it should be with the DER connected to the simulated/actual EPS used for testing.

Reigh states this should be done at each and every test level you're operating at.


• Q: What's the interpretation if the EPS is fine without the DER and not fine with the DER connected. Asking about invalid tests vs. fails. Andy: would be considered invalid test, and you’d need to do test again. If you

haven't met the requirements for the test setup, you have to find a better test source and re-run the test.

• Andy: another subgroup writes the current distortion test. Our goal here is to define the limits on the test source used for the current distortion tests

• Reigh: It's not just grading, it's also putting a blocking filter in there. Andy: Goal is to avoid folks intentionally using a blocking filter to pass the test

when they otherwise wouldn't/shouldn't pass. • Jesse: If you were testing with the local utility and had an on-site 5th harmonic filter.

Would you be able to use that to have a valid test? Reigh: that's fine. The base standard is written so that external sources of

distortion are excluded from test failures. Only measuring current at the DER terminals.

• John Berdner: History: Manufacturer had voltage source inverter. Were passing current harmonics test by changing voltage harmonics at the test site… Goal is not to have crazy harmonics on the test set that can mask harmonics on the device being tested.

• Jeannie asked: So are we saying that these have to be tighter than the requirements a utility has in IEEE 519 for harmonic voltage limits for their customers? John said there might be some cases past the PCC into customer systems where

it might be difficult… Secretary's note: Suggest we look at IEEE 519 for requirements on utilities

supplying to customers. May need to clearly state that in some cases with this test our goal is to have a clean test source and therefore filters might be required for some utility connections to properly do the test (with a clean source)

• Reigh: need to clarify that it applies in the initial operating conditions for the harmonic distortion (as opposed to during disturbances)

• Bob White: There may be some validity in specifying only the equipment for a given test. Andy: Yes, the current distortion test limits only have to be met for those tests,

not necessarily other test sections. Immunity level - equipment must be able to perform up to 8% harmonic

distortion according to 519. There is concern that the testing is requiring more onerous requirements.

Reigh: purpose of restriction is so that current distortion is more obviously from the DER only, not the grid. Looking for a clean source to test with.

o Subgroup is proposing upper limit of 1.5% negative sequence voltage (V2). Motivation for including: test repeatability. • Consider whether the voltage imbalance measurement should be taken with/without

the DER operating o ISO 17025 Discussion

• Jim Daley: OSHA covers NRTLs in the US. (ie not ISO 17025) - for UL1741 • Bob White: Some folks may want to use 1547.1 independently of UL 1741 • Tim: I think the intention of why this was put in: Was for one-off on-site testing

Subgroup could include a note that this is already included if you use a NRTL (Bob White)


Howard recommends … note that you have to have different levels of this ISO/IEC certification…

• Andy repeated what he heard: There are different levels and it's actually more complicated than just referencing 17025...Andy requests input from the working group on language for including this if necessary.

• Tim Z doesn't see an issue with using this (no conflict with OSHA) • Paul Krell isn't seeing much language in the base standard on requiring testing per UL

1741… Thinks the language isn't needed. • Jason Allnut doesn't believe that it's within scope • Tim Z believes that Professional Engineers or other entities (other than NRTLs) may

use this document to verify compliance for a site. Based on that discussion Mark Smith would support including in the document

• Paul: use caution based on it's use. • Jim Daley: When UL 1741 comes in to do portions of their required testing, they

certify that section of a manufacturer's test lab. You'd need a big environmental chamber you could drag to the field to do the

type testing in the field!!! • Andy: There are some divergent views within the group on this, and it doesn't seem

we'll resolve it here. We'll discuss within the subgroup and then discuss at next meeting.

• Paul Krell: We need to discuss from a more general standpoint what the qualifications of testers should be.

• Jim Daley: on the user side of the meter, NEC code rules. Under that jurisdiction you are only allowed to use listed devices (tested by a NRTL). Notes that test labs other than UL itself can certify equipment to UL and other standards.

o Type test pass-fail criteria • Can't control something more accuracy than you can measure it • Subgroup proposal:

Uncertainty tolerance = 1.5*MRA (not 100% consensus on that yet) Another proposal would be to ask the DER what it thinks the voltage is, and

then look at the output/response. Bob White has seen testing that follows the bounds Andy's given on slide 14.

• Reigh: Are all functions necessarily negative slope as assumed up there? The equations here (on slide 12) assumes negative slopes ONLY Andy: According the base standard, you could have either positive or negative

slope. Subgroup to add footnote if they assume negative slope, since the base

standard doesn't require the negative slope. Xcel Energy? Somebody brought up sum of squares

• John Berdner noted that the sum of squares will give you a slightly smaller circle rather than box around the amount of error you get. Stated they tried to reach out to somoeone for help on this but didn't get anyone.

• Secretary's note: It seems unnecessary to look up sum of squares for the above reason, because it doesn't adequately show the worst case error

• Mike: could have some requirement on linearity. • John: Something's tough to do with current measurements… • Andy: Something on relative error …


• Bob White: If it follows the curve, we should be fine… Andy: won't cover systematic error, but that's fine…

• Richard Bravo: Concerned: NERC/FERC might not want all inverters to act the same way and *have the same bugs!

Power Quality Subgroup Marcelo Algrain

There were few changes on the majority of sections, except:

Harmonize figure on GFOV test circuit • GFOV test needs some updates

o C62.92.1 (Is that IEEE/ANSI?) It's a C, because it's an ANSI standard

o Babak asked the purpose of the test. The goal of this optional test is to show whether an inverter will produce ground

fault overvoltage in excess of the ANSI standard overvoltages (effective grounding) on its own, even if the load is connected delta or otherwise ungrounded.

o Reigh: A sync gen would always fail this test, so this test wouldn't be done. Secretary’s note: An ungrounded or high-impedance grounded synchronous

generator would fail this test. A low-impedance generator would likely not need this test either, because short circuit modeling would also show that a synchronous generator grounded with sufficiently low impedance would not cause overvoltages in excess of the C62.92 standard for effective grounding.

o Last Sentence first paragraph: Remove or change the footnote "The intent is to limit the use of grounding transformers to installations where the potential for overvoltage would warrant them"

Secretary's note: Or, in the spirit of the DTT reference, we might just want to reference 1547.2 on how to evaluate the DER given this information

Secretary's note: We should also record the ground current into the fault (or from the DER) during the optional GFOV test).

5.11 needs some work on the footnotes. Marcelo: "FN" stands for 'footnote" Revise in next draft.

• Current Distortion Tests • Mike: why does this require testing against a load bank and not with the simulated area

EPS? • Andy: It's only allowed for voltage source DERs, ie sync gens…

• Secretary's note: 5.11.2.1 should be bullet/steps on procedure for each sentence. Will be fixed with technical editor/next revision.

• Jesse Leonard: his understanding from Richmond was that the load bank would be optional… For high power units may be practical to use the load bank Can we allow the test to be run without the load bank? Reigh: Not essential. Purely inductive source with f increasing, have more and

more impedance. At 30th harmonic… Load bank ends up being of smaller impedance… Does it represent closer to what the real grid is? In his opinion it's desirable but not essential.

• Jim Daley: Do you do that against a load bank w/ or w/o the utility?


Marcelo: For synchronous it's just the load bank • Jesse Leonard: could do a test setup with one inverter one converter doing a

recirculating power test. Marcelo will write up some language for those circulating current tests (for

inverters) • 5.11.2.2 Marcelo noted we have typo in table 35<=h<50 for the max limit

• The values will apply for all harmonics (odd and even). Less stringent because this is the requirements for the test setup, not the DER.

• Trying to keep the requirement the same as in 1547.1-2005. Didn't have any interharmonics, but that's a gap we should fill

• Marcelo presented John Kotula's written comment on IEEE519-2014 talking about voltage distortion limits.

• Marcelo to Include above on iMeet • Reigh: Point 1: the grid is commonly unbalanced and it's unreasonable

Point 2: Actually, negative sequence is like the 'minus 1 harmonic'. Could take that argument and say that the DER is not responsible.

Boiled down: Does the base standard require you to test with reasonable unbalance? Yes/no? • Yes, because normally expected in the field • No, bc it's a form of distortion

C57.110 - heating components with max harmonic distortion that we're allowing, doesn't expect much issues with transformer degradation

• The subgroup plans to run the test under balanced conditions based on no comments today.

Unintentional Islanding Subgroup Greg Kern, John Berdner, Sig Gonzalez

5.8.3, 5.8.4 need more content (not much to comment on yet)

• Reigh noted adding a ground connection to the neutral bus bar in this figure (5.8.1 balanced gen to load unintentional islanding test) - for the sake of including the safety grounds, as well as grounding of the neutral of the simulated EPS.

Per Jim Daley to secretary: (should have a G on the utility - solid ground there and then solid line to a G on the inverter).

• John Berdner: Should say capable of "at least" 125% active power in case the EUT needs to increase… See Table 1

• Jim Daley: For sync: The Gen is typically rated 25% over prime mover (for the sake of allowing the generator to operate at p.f. all the way down to 0.8 (won't have something > like inverters)

• Subgroup requests comments for tables 2A and 2B for testing numbers. • Andy: What quality factor are you aiming for in the tests?

• Subgroup will include discussion on quality factor in the Annex • Greg thinks the quality factor change is neutral b/c of the way the rotating machine will

be doing frequency? • Ride throughs are implied in the tables • Reigh: So are you specifying that the inductive part of the load bank will have a known X/R

ratio?


• Greg: Values in this table are +.05per unit • Reigh: do you have different Q factors in for Cat A and Cat B?

• Greg: Yes. • Reigh: How do you justify being technology specific for that?

Why would a circuit with a Cat A have a lower Q than where you might want Cat B?

He's seen utilities skeptical of the islanding tests and doesn't want to see different treatment for one device over another further increasing that skepticism.

• Jesse: Can we change PR to PL or have that be 1 or 0.97?...Combine PR and PL columns… (Pnet maybe?), or PR + PL + PC.

• Reigh: gives example of 2MW site being a large penetration level on a single feeder. Sees no reason to give different Q factors by category type, especially without a good explanation of rationale. o Jeannie agrees with Reigh.

• Marcelo and Reigh talked about load banks… o Reigh stated that it's unlikely that rotating machines will pass the islanding test on their

own anyway… o Andy: There could be Cat A inverters, which you would want to test. o The subgroup plans to re-visit this topic one more time.

• Greg: Using 0.95 < quality factor for Cat B because 1547-2005 was set to 1 + .05? • Andy: Longer trip times extend islanding trip times. Widest settings in some functions might

actually be counterintuitive (not worst case), and actually make the island easier to trip off… • Secretary's note: 5.8.1.2: Should we record both magnitude and phase angle? • Reigh: What's the purpose of using the min/max of the trip times?

• Greg: Language for 5.8.1.2 needs to be updated to accommodate the 5-second adjustable islanding clearing time.

• Also suggests taking the capacitor out of the TRD statements for R, L, C in same section • John Berdner/Others: Add Requirement for recording signal level for the distribution

planner. No pass/fail criteria associated with it. • Change S3 to Sp in the figure • 5.8.2.4 'single failure' criteria statement looks like an artifact from UL 1741 SA and is not

required (per John B and Greg Kern) • Jim Daley/Bob White: discussing full/partial compliance. Jim posits that non-conducted

permissive signal test would be 'full' compliance to that part of the requirements (not necessarily islanding, but being able to receive a trip signal) • John Berdner: IF no active islanding, need to consider the DER partially compliant.

May/may not have a permissive conducted capability, which is optional. • Reigh: For the minimum power approach… Are you sure you'd always meet the 2s islanding

with it? • Jeannie: we may need to consider changing the wording or removing the minimum

import as a means of unintentional islanding. Consider the case where a small exporter on the same utility feeder is capable of supplying the minimum import. It’s not appropriate to use in any case where you have exporters on a feeder – everyone would have to do minimum import for it to work. Since this is such a rare case, we don’t want people to confuse it as a ‘definitive’ means of islanding detection.


• Marcelo: thought the definition of 'cease to energize' is to stop providing power to the Area EPS…

• Wayne clarified that the section on islanding in says cease to energize and trip • Greg Kern: Not sure how to write a type test to capture the concern...might be an

interoperability test… • Paul Krell: Need to be careful with language… Is 5.8.5 intended to test a minimum

import feature of an EUT? He's all for testing that DER for that feature. It is absolutely NOT a universal solution for islanding, however.

• Jeannie and Paul Krell to discuss language to allow that DER to be tested for a minimum import function but not imply that it's a solution for every case.

• Jim Daley: The active load always exceeds the generator capacity • Paul Krell suggested we remove the second sentence referring to meeting islanding

requirements. • Jeannie suggested we do as we did in 1547 - refer to 1547.2 for context for what

purpose the 32 function may have, rather than stating it in the footnotes. In the base standard there was a lot of confusion with footnote 12.3 from the base 2003 standard being misapplied. 1547.2 needs to state that this function only works when other exporters on the feeder can’t carry the minimum import a facility might have...See footnote 111 in 1547-2018, which refers readers to 1547.2 for ‘other mitigation methods,’ which should give context when each mitigation method is appropriate.

• Jesse pointed out that this is also a site evaluation test… • WG needs to consider what alternative text is needed or section the 32 function test

should go in to avoid confusion amongst users Hardware in the Loop Karl Schoder and Jesse Leonard

• On possibly using CHIL within ICP: could be used as a study/tool in evaluating installations.

Mark Siira: as we look toward ICP, table shows technical requirements. What tests would be done?

o Jesse: Tests that can only be done with DER evaluation would be good candidates for HIL testing. Any test that needs to change voltage or frequency at the terminals (PCC which is infeasible onsite and can’t be a commissioning test since you can’t do this onsite) needs to be performed at the design evaluation. Annex will be a guide to provide terminology, what to ask for and what to expect from a CHIL study on some aspect of the DER design.

• Babak: some microgrids have the condition where you trip everything o Jesse and Karl: the turning off UI on the DER is to check the balanced condition for the

islanding circuit, not to test microgrids. This is to duplicate what Greg Kern is doing with his verification of balanced load by producing an island that runs on when the DER has UI turned off.

• Discussion on unintentional and intentional islanding: CHIL and PHIL were discussed as a possible means to verify whether a DER could trip for unintentional islands that may be more difficult to physically set up.

o Nevertheless, other test conditions (different from the RLC load bank) were never agreed to. In principle, other test conditions (models) could be simulated.

• Bob: When you say once per facility - do you mean you never have to re-calibrate or re-check it?


o Jesse Leonard: There's nobody presently to certify the PHIL setup, process to be determined.

• On evaluating simulated load bank model o Andy: at each point, what are we evaluating? o Jesse: in general we’re trying to verify the simulated RLC parameters by changing the

DER setpoints. By changing P we should see a change in voltage, a change in Q should cause a change in frequency. These verification tests will show this including some tolerance.

• On evaluating dynamic, control bandwidth of PHIL setup o Reigh: if the inverter is using harmonic injection near the switching frequency this is

problematic for running with a simulated system. Manufacturer may have to expose what their scheme is to be properly tested.

o Karl: yes, this test is supposed to understand limits of the PHIL setup and catch EUT-derived conditions that don’t allow PHIL

o Jesse: There's no test for inverter current control bandwidth and we are trying to find another approach to avoid requiring this information.

• On a possible option to evaluate full PHIL setup o Karl: impedance measurement of the test is feasible but process isn’t standardized yet

• Next steps (with D7 deadline end-August) o Will poll for best timeslot for HIL-calls (targeting Tuesday as Mondays have become busy

with 1547-calls) o Will keep revising UI-PHIL requirements o Will refine annex on PHIL o Will add an annex on CHIL (ICP related testing) with short paragraph on CHIL as option

within ICP clause(s)

Day 2 of 3 - Wednesday June 13th Voltage Regulation Subgroup Jon Ehlmann • Marcelo wondered if we should be including tests above and beyond those required by the 1547

text. o Jim Daley and Babak Enayati agree that the testing shouldn't be burdened with extra

testing outside the scope of 1547. o Andy gave an example. What if a facility can go to 0.44 per unit. Will we test to that

range? What if a utility wants to use it?

• Bob White suggested adding to general requirements - if you want to test to the MRA in the standard, you can do that.

• Jon: There are two methods of setting VAR. If it's not completely defined, there might be confusion on the inverter settings.

• John Berdner asked about the Q expected, and was concerned that there might be an additional requirement based on this text. Implies closed loop implementation and that might not be the


case. (referenced in the Volt-VAR test section). Related to MSA vs. MRA - John discussed not being able to assume they're the same.

• Babak: When we say 'go beyond 1547' are we saying new capabilities, or

• Jon: goal is to extend capabilities rather than test new functions…

• Roger, SCE: Supports that manufactrers should be able to extend over 1547 capabilities. 1547 is

the minimum requirements for interconnection. The minimum requirements might not be sufficient for interconnections that Roger expects utilities to need.

• Marcelo: Perhaps this could be covered with simple language. Submit results for DER evaluation.

• Jeannie: Agrees with Marcelo/Bob that we should add General Requirements text to allow and record tests outside the required capabilities. We also need to include in that text the requirements for safety/reliability testing to show those functions still work with those capabilities. (Jeannie covered Jim Daley's comment).

• John Berdner: Bob covered it well. .1 shouldn't preclude you from going above and beyond the

standard. Standard should allow you to exceed the reqs and have the NRTL record that information (for manufacturer's product advertising, for example).

• Bob White: Comment on MRA vs. MSA.

• Andy: Yes, GR section seemed to have consensus that it should use the MRA.

• Tim Zgonena: UL has seen cases where adding additional functionality in the testing is necessary.

• Paul Krell: OK with proposal, but the devil will be in the details. Some of the testing/definitions might be based on certain limits of capability… Thinking fault response, for example… Those modes/functions may affect other tests.

• Jon: Jeannie's comment reminded us before that these functions affect a lot of other areas such as islanding, and we need to be careful with this topic.

• Marcelo: Even if you have excess reactive capability, they'll have default ramps. Unless the utility is giving you this new set point, how do you use this?

• Babak pointed out that the curve we're using is only a sample curve. If going beyond that, it still aligns with what's in the standard.

• John Berdner: his concern is that he could interpret (Jon's Table 2 Char. 2) if his DER can produce more than 44%, in order to be compliant, it has to meet the reqs for Q1, Q4. We may a need footnote that if it has that capability, not mandated to provide that...You're required to put the reactive capability on the nameplate.

• Roger Salas: Need to see that they were tested to verify it's safe to turn on the added functionality.


• Patrick Dalton: if the value is on the nameplate and some functions such as Volt/VAR, how will we

know the functions work if they're not tested to the full range?

• Marcelo thinks you should be able to test to the minimum capability or the full ability as optional.

• Bob White: mention in the gen. reqs. That way we don't repeat over and over again. In the General Requirements, include statement that capabilities that are tested in excess of 1547 reqs are not required to be implemented except thru contractual agreements.

• Andy noted he saw heads nodding in the room on this sentiment.

• Next topic • Marcelo: for synchronous machines, they handle the voltage with a single excitation for all the

phases. The RMS voltage is the average on all three phases. •

Reigh: RMS doesn't mean average. A lot of inverters would probably be similar to sync gens only responding to positive sequence voltage, but there are other single-phase units that will control independently within one 3-ph box. The standard needs to accommodate unbalance.

• Marcelo expects we'll get the same response no matter how we measure it and advocates for being less prescriptive.

• Jon: he doesn't mind leaving this out, as long as it's discussed.

• Reigh: the base standard allows different methods. Do you need to verify they're doing one of the things allowed, or do we want to say it doesn't matter much and don't test it.

• Andy: seeing more heads nod than having an unbalanced test for volt/VAR or Volt-Watt.

• Reigh: what if something regulates 1 phase, or regulates the max of the phases?

• Andy: If you don't test with unbalance at all, it might not comply in the unbalanced case…

• Reigh says the real risk is probably a device that only does it on one phase.

• John Berdner: See section 4.3 lines 6-9 on D7 of the base standard. This requires individual phase measurements OR average RMS...

• Ben Ealey (EPRI): Reading in test for const. PF mode instead of writing a whole additional test… See 5.12.1.2 in D6 of 1547.1 tests l and m… • Jon: we have to think about the criteria for the unbalanced case. Also recalls sync gens don't

fully supply balanced.

• Richard Bravo advocates for seeing the unbalance. He's seen folks only using 1 PT to see the voltage

• Marcelo, other folks in the room are not sure how someone could meet the 1547 voltage measurement/ride through requirements without 3ph sensing.


• Line 33 for 5.12.1.3 - Psquared plus Q squared

• Reigh: Just because 3-ph voltage is brought to protective relays, doesn't mean it's brought to the

voltage regulation. Need to define pos. sequence P and Q, or average?...

• Jon: Was the l/m lines - were they appropriate? Issue 2 would be Volt/VAR thing…

• Reigh's suggestion: One test where step up one phase by the unbalance and the other by half unbalance… Just to make sure folks aren't using just one phase for the measurement…. Would be a quick check for that… Would be one point of the Volt/VAR test. (Verify quantities with Reigh later)

• Marcelo: IF that's the concern, how about having the manufacturer state why they do it, and avoid the test?

• Jon: Requiring people to state would be in addition to base standard…

• Andy: Reigh's proposed method seems pretty simple to implement • Jon: If using average RMS, will stay constant. Marcelo agrees. Doesn't give any information

on the DER, but not defined, so could be good compromise. • Marcelo believes the above is overkill.

• An attendee: doesn't think it's onerous to insert those into one of the tests and gives some reassurance.

• Marcelo: What level of unbalance will we look for?

• Reigh: With his proposed method you shouldn't get a change… Maybe we need to do a bigger change.

• Roger Salas: Are we talking about voltage unbalance on the D feeder and how it affects the DER? If so, our circuits ALWAYS have unbalance. The DER has to be able to be certified expecting that there is voltage unbalance. If that's what we're talking about here, it needs to be tested.

• Marcelo believes we're testing for something that's not a problem.

• Roger: IF you're saying that we should ignore things because we haven't look at them in the past, we have too much DER on our system to ignore what we may have before.

• Andy: Those that have a strong opinion, please call into Jon's calls on this.

• Paul Krell: Voltage regulation question: Is it everyone's understanding that V-reg is independent on each phase? (Response is No in the room).

• Many folks in the room nod heads that we need a spot check for verifying from the base standard from section 4 page 30 of published doc: "For voltage-reactive power(volt-var) mode requirements in 5.3.3 and voltage-active (real) power mode requirements in 5.4.2 where DER do not respond to individual phase voltages, the applicable voltages are quantified as the average of


the three-phase effective (RMS) values or alternatively positive sequence component of voltages over one fundamental frequency period." Signal Transients:

• John Berdner: Need to look at response time for f-watt. Don't think it'll make difference. The Open loop response time makes it a moot point (see standard). If you look in the base standard and look on measurement accuracy, the terminology might not be consistent.

• Jon: A large signal makes sense for certain DER.

• Andy: IF a DER is not limited in its timing… Might be good for a utility to know, though it might not be within scope

• Meetings Tuesdays 12-1 Eastern. [email protected] VF Subgroup – Abnormal Conditions John Berdner and Reigh Walling

Meet every Thursday 9-10:30 PST

Status: • UV ride thru 98% complete • OV Ride thru test 95% complete

o Capable of independent operation (into resistive load) • Need to resolve momentary cessation regions

o Not capable of independent operation • Under/Overfrequency ride thru 98% complete

o Units capable and not capable of independent operation • ROCOF

o Compliance using frequency trip or ride thru data o Specific ROCOF test to be developed o Phase Jump testing under discussion

Discussion: • Jesse: looking to prevent an inverter from gaming the test by causing an overvoltage themselves

• Reigh: similar ...with sync gen, will have reverse reactive flow. Initial will have 1pu or so reverse

flow… Generator might have loss of field relay… Need to make sure you won't trip the loss of field relay inadvertently… Reigh: From the PLL's response standpoint, wouldn't the end of the UV test be sufficient for that? Step from 1pu to .5pu… Reigh: Could say 'this test is not valid for Cat III'

• Subgroup would like to harmonize test setups amongst islanding, V/F ride thru, etc.

• See Slides - #8 for a graphical analysis of constraints with phase jumps.

• Marcelo asked whether you could disable some settings to make the test easier.


• Based on the base standard, not all settings, for example, the 120% voltage trip point can't be changed wider than 120%.

• Jesse: Are we going to do a test for DER...something about zero sequence… o 3-wire might be able to do the tests during ride thru? o The subgroup will consider this comment for single phase.

• 3-phase 3-wire will only be measuring LL voltages.

• Mark Smith: Wouldn't you want to do phase-phase anyway because you'll have a phase-phase

fault?

• Reigh: 60-degree value might be over-spec'ed a bit… • John Berdner: Might have been overly aggressive b/c creating headaches in how to set up the test

now.

• Paul Krell: Hopefully the challenges are only in how to set up the tests, and not in meeting the requirements…

• John Berdner: One other question we should discuss is at what power levels this must be run? Reigh: Full power.

• John: You might need a 10MW source to run one test, you might not need it to run other tests.

• Mike Ropp: Have we looked at what programmable sources are capable of performing the test? The sources that we know of probably can't do it that way.

• Reigh: If your test set has 3 single phase bridges you can do a test like this...

• Reigh: his opinion is that the single-phase jump represents a single-phase fault in the system, so the duration should be something in the ride thru per unit… Other option is a step in phase that remains for a long time - steady state to steady state with a balanced phase jump.

• In answer to Jeannie's question of what NERC/FERC wanted DERs to ride through, o Reigh: Transmission phase-ground fault that looks like a phase jump on two phases …

Caused mis-trips on frequency… o Reigh: The positive sequence jump should be a steady state kind of thing.

• Marcelo: Does the standard allow us to say 'that's unrealistic and we have to do it this way' • John Berdner: We'd have to go back and do a revision to the base standard. It's not trivial for us to

go back and fix mistakes if we made any - we'd have to ballot 1547 again.

• Reigh believes that the single-phase jump is a bit aggressive, but not impossible.

• Base standard says momentary cessation is OK for single phase jumps, should be mandatory operation for pos. sequence jumps. P and Q oscillations are allowed.

• Reigh wouldn't object to secondary injection for rotating machines, as they have models for them validated over years…


• Steve Wurmlinger: Need to look at the technical issues of being at full power, and what we're

trying to look for.

• Karl Schoder: We did these kind of tests… Owner requested test of all phases not just one.

• Andy: Steve, when you test, do you test a smaller version of each DER type? Maybe that's a way to get more out of what you have.

• Reigh: If everything scales up… • Andy: It's definitely doable in the 100's of kWs. • Tim: One of their test labs at full power 100kW. Lab in Germany can go a little higher than that.

• Jesse: Comment on Italian standard and some off the shelf devices. Ametek - transformer w/ it.

Italian standard wants an 80 or 90 degree jump… saturating transformer between the grid simulator and the grid basically...

• Jesse: Basically need a transformerless setup (to avoid the saturation issue during the test)

• John: Should be covering this in the next few meetings if you have strong feelings. Let John, Reigh, or Marcelo know you want to join the subgroup calls.

Open Phase Detection at the PCC: • Paul Krell potentially sees a challenge in section 4.2 with a circular reference w/ 6.2.

o Bob White: That tells me you have to determine the RPA in the DER evaluation.

• John Berdner: His feeling is that you have a zero-sequence breaking transformer, you need to run the test on the other side of the transformer.

• Mark Smith: 3-ph customer, they've been telling the DG connections… Separate from your DG, if there's a delta anywhere in your facility, you need to put your relays at the point of common coupling to sense the loss of phase. It has nothing to do with the DG. He suggests you write this in a way that ignores the presence of the dg. It has everything to do with the customer with the delta and the EPS w/wo the DG. They require ALL (DG or not) customers to have negative sequence sensing to trip for open phase conditions.

• John believes the word 'appropriate' is the break in the circular reference Paul is concerned about.

• Paul Krell: You can't necessarily test in the type test if the transformer isn't included.

• ICP subgroup has to write the (potentially harder) test for open phase detection, and the DER Evaluation has to include the location that's 'appropriate' to detect the open phase condition.

• Jens: To what extent does the zero sequence continuity matter with regard to the open phase conditions?

• Paul: Brian's comment (on 3-legged core transformers) is starting to touch on the importance of the DER facility analysis/test: The transformer itself could be the source of the backfeed, it could


be parts of the DER interconnection (supplemental equipment, not just the DER unit). He's concerned about a hole in the standard if it doesn't specify the transformer itself needs to be tripped off.

• Jens: The standard is crystal clear that 'cease to energize' is the DER unit? And trip may involve disconnection… We verified the standard says cease to energize and trip.

• John B's interpretation: If there's an intervening transformer that breaks zero seq continuity, the test needs to be performed on the utility side of the intervening transformer.

• Abnormal Group to write PoC Test (John Berdner, Reigh, Marcelo's group)

• ICP Subgroup (Mark Siira and Wayne Stec) to write the test for PCC

• Tom Key: When the relay's required, the developer installs it and they buy the relays, so there

may still be a test to prove it operates.

• Mark Smith: All it is a test that says 'show us this will work.'

• Babak, through a question, helped the group clarify that the DER Supplemental devices (including relays at the PCC) can be used to trip (and are part of the DER) the DER (which includes DER units and supplemental equipment)

Synchronization Subgroup: Marcelo Algrain • Proposal is to remove synchronization from the production testing, as it's demonstrated in the

type tests (It was in the 2005 version of 1547.1). • John Berdner is a little bit worried about relying on the ISO Certification. Right now they do the

production testing for the tripping, and he's not sure saying ISO certification will be sufficient. • Bob White: Agrees w/ John: Suggests to Change the wording to "certified by the NRTL" (methods

certified by the NRTL) • Jim Daley: NRTLs do not qualify testing facilities by manufacturers, but UL1741 requires that it'll

get some level of testing…? Each unit would be listed with its settings as shipped. Jim's point is that you can't just do sampling - you'd miss the units you probably wanted to check.

• Jim Daley: There is some kind of control system that performs synchronization • Mike Ropp: Type test is appropriate for conceptual/design, not for testing settings. • Jim Daley: you need the results of a calibration test when the device leaves the factory. • John Berdner: There's still ongoing discussion on test results for functions other than just

synchronization, for production, type testing, etc., as appropriate. • Wayne: Just use caution that we don't eliminate the possibility of testing a system that's being

type tested. • Bob White: The documentation section needs to be updated. The information can be retrieved by

serial number, for example. • Bob White agrees with removing synchronization from the production testing. • Jim Daley: believes you can remove. • Follks in the room that voted agreed that synchronization can be removed from production

testing.


Jim Daley: UL1741 requires that each unit that carries a listing (Paragraph 63.3) requires that you do a production test on each of the units. • Bob White - that can be changed after this standard, though. It says 'according to 1547.1' • Tim Z: The manufacturer is required to do calibration, • John Berdner: The notion that inverters are shipped with 1547 settings is simply not

realistic. Increasingly they ship without a profile bc they're shipped all over the world. You want to force the installer to properly configure the unit (or it won't work) so they're forced to choose the correct profile.

• Bob White: ABB ships them with a 1547-2003 default at present to US customers… • Marcelo's summary: Sync section is out of production tests. Need further discussion on

something. • Babak feels each of the voltage/f trip tests needs to be done on each DER. • Jim Daley: Unless you tell the manufacturer you want a specific set of settings when it leaves the

factory

Fault Current Characterization Mike Ropp • Figure was updated - switches labeled individually • Bob White: for an EUT that doesn't have a neutral connection, should that be a neutral or a safety

ground. ABB's big inverters don't have a neutral connection. • Mike Ropp: wasn't intended to require 4-wire inverters only.

• Reigh: What are the requirements on the Area EPS for zero sequence impedances/etc.

• Mike Ropp: Subgroup had concerns that if you pull the voltage down to 5% nominal voltage, then you're in a region that puts an inverter in momentary cessation and you might not see much fault current output as intended.

• Vi is where the inverter limits the current, but is also greater than • Reigh: couldn't you specify that inflection point as (1/(current limit))? You might not get to that

point anyhow… • John Berdner: Concern that we're creating an implicit requirement that might not be able to

meet…. Now, if we see a quick dv/dt event, we (basically won't have a Vi…) Note that Vi assumes a certain control methodology. What do you do if you don't have a Vi?

• Subgroup to consider specifying, at request of manufacturers, the inflection point/current limit in terms of the current limit itself (in case an inverter doesn't work in the same way).

• Mike to talk to Tim about Ul1741 section 47.3 for testing that's already done? Bob White asked whether we can combine the tests? • Tim does a short ckt test and records the output, but does not specify how to record/show

the data • Also, the two tests have different purposes

• Paul Krell: The purpose of this testing is to gain some information for the inverter evaluation? Concerned that we're relying on inverter manufacturer statements for the fault current to start this test…

• Reigh: You can't define impedance for a current limited inverter, though. • Paul Krell's worried about another circular reference. Give me the max current so I can see the

max current…


• George Bernstein: sounds like Paul's looking for a test that defines Vi. • Reigh is concerned that the big impedance (Zlimit) will make whatever the EPS is moot.

o Will Zlimit be bigger than 1pu? o If the impedance has to be too big, then the inverter might lose its control something…

• Tim Zgonena: In the past we've put a resistive load bank in between like in the islanding test. Are you able to disable the islanding, temporarily open the grid, short, and then there you go… o Mike: In the subgroup meetings we were concerned that the frequency will change in the

faulted island test… o Tim: Could also replace Zlimit with fuses… o Reigh: Now your zero seq impedance from the load bank will not be realistic… Whatever you

have there will affect the circuit, so you need to fairly tightly confine that Zlimit. o Prasad/Reigh: Equivalent would be adding a grounding transformer on the DG side of

Zlimit… o Reigh: You need a strong enough grid and properly selected impedances. Could also use a

short circuit generator. o Marcelo: VDEW 4110 German standard??? Not positive on name of that standard..

• Change Fig 2 so it's fixed from 'grid simulator' to programmable AC Power Supply. And the

dotted neutral/ground? Connection?

• Reigh: balanced faults concept works. But it's likely to be a dq0 reference limit or on a bridge current limit basis, which is more complicated for an unbalanced fault. o Reigh: Positive sequence voltage decreases (2/3) o Mike still believes you'll reach the inflection point current as long as it's not >1.5.

• System operator wants to see an example of the actual fault current response of the inverter so they can model for short circuit protection, etc.

• Reigh: option 1 you'll see filter outrush. You don’t consider cap discharge current for fault simulation. o Mike: Some inverters will run on longer than others… o Paul is most interested in what's the run-on characteristic going to be? Not interested in

when it takes itself out. • Nick Wrathall (Kinectrics): question on programmable AC power supply: You're not actually

introducing a supply in between the supply and the … Now you're having the supply match the magnitude and phase angle of two …. *IS there anything in here about how fast the test device has to do the changes for the fault?

• Fred Horton: You'll have a lot of work you need get do to get to Vi. Not specified so you can play around with it, and it might be affected by power factor settings and other things…

• Paul: Do both the short circuit test and this test! • Bob white: Requirement for 1,3,5 cycle data… • Reigh: The source test and the switched impedance test are not the same because you'll have a

different zero sequence impedance … You might have to specify 'with an impedance...etc' • Mike Ropp: When you have a certain set of vectors at the inverter terminals… That's the only

requirement, correct? • Reigh Walling: Zlimit is too much … defines the interconnection/source characteristics more than

intended. Need to design the circuit so the short circuit ratio is better than 5.

• Last sentence on DC source probably needs to go into general requirements.


• No specification at present on what the unfaulted phases do during the test.

• Trade-off between longest duration and largest magnitude

• All tests done at nominal rated output power prior to the fault.

• Reigh: If you make that short circuit ratio like 5, you won't have a voltage issue

• Reigh: Working out the phase… The voltage you see will depend on whether it's ph-ph or ph-ph-ground depending on whether your system has a neutral? Ground? Or not. o Mike Ropp has simulation/lab results showing that the LL and LLG fault responses are the

same. If the inverter doesn't know where zero is, how does it make a difference? • Paul Krell: That kind of fault on the system will result in ph-ph voltage changes…?

• Nick Wrathall: In the test procedure portion still not seeing how fast you have to get to the fault

condition. 1ms. "The voltage change shall occur in no more than 1ms."

• Brian Lydic: last sentence in data requirements - is NRTL the proper wording to use in there in 1547.1. Is that within the authority of 1547.1 to require? o Maybe that should be a general requirement.

• Paul Krell: intent was likely to have someone reputable recording the data. • Bob believes we should remove the sentence. • Nick Wrathall: The NRTLs don't apply the same way outside the US. "Accredited certifying body" is

for Canada…

• Jim Daley: When we do UL testing, the NRTL doesn't necessarily measure the data, they might say they have reviewed/verified the data. It's covered in the general requirements

• Question: How is this different than the ride thru test and why can't you combine them? o Mike Ropp: We really wanted to do that, but there are a number of incompatibilities

between the two sets of tests

• Doubly fed has the rotor converter out of the way, so it basically looks just like one of the other rotating machine devices.

Prioritization of Responses Working Group Bob White • Brian Lydic: Wouldn't it be from the receive time, not the sent time?

• Karl Schoder noted enter service test appears to be missing?

• Ed Morrow: His interpretation is that you can configure the trip times to be set within the ride

through times. Secretary’s note: That’s correct.

• Reigh: Ride through test already covers this. If it trips on islanding during the V or frequency ride thru testing, it's a fail.


• Brian Lydic: Could only follow volt-watt, and

• Andy: Depends on relative values of voltage and frequency to make sure you're doing it right.

• First bullet - could do this at 80% rated power or something, so you have room to go up. Richard

Bravo: 50% might be better so you have more leeway to increase.

• You're welcome to join the group to help! Reporting of Results John Berdner • Finding info in a sea of results from NRTL test, which contains proprietary info…

• Need a means for automation and a standardized way of reporting.

• Goal is something human readable by someone who's familiar with the concepts.

• Reviewed names used in 1547 section 10

o Conclusion new names needed for certification. o Need names for min value of adjustment o Need names for max value of adjustment

• Started to collaborate with 1547.2 and EPRI folks on this section for results reporting.

o Inverter manufacturers don't need the explanatory language regulators/AHJs have in long docs. They just need a standard settings table.

o Secretary's thought: Could give this to a programmer and the utility can automatically verify using some code

o Lots of stuff out of scope, but also lots of benefit to be gained for multiple stakeholders

• Will need files of how the settings/etc are when the devices are ready to interconnect

• Scope: o Type testing (Sec 6.4), Production testing (Sec 6.4) o Commissioning testing (sec 7.1) o Periodic interconnection testing (sec 8) (not all, perhaps)

• Want a secure way to store the data so the NRTL can provide data perhaps on a central repository.

o Could say the NRTL has to host the data for the devices they have certified… • May be more than one version of the file, too

• Tim Z: The AHJs, regulators, utilities, etc. need to know about the functions in the devices. Differentiating what's covered and what's not is important.

• 1: filename, checkdata(checksum?), provide link on the certificate of compliance. To get a copy of the csv file get the file/fliename/checksum from the manufacturer.

• 2: mandate NRTLs source on their websites


• Problem, if manufacturer goes out of business, you can't get the data anymore!

• Unanimous vote by the group to REQUIRE that the certifying body will host the data on their website for devices they have certified/tested.

• Paul Krell: It's not obvious to me that 1547.1 can require anything directly of the NRTL. May need to phrase "the manufacturer of the device shall ensure that the NRTL has the information available on their website"

• 3 types of ranges: o Ranges of technical settings o Ranges of evaluated settings o Ranges of allowable settings

• Work in progress - need names for the ranges, and we believe they're all within scope.

• Bob asked a question on how to certify a device designed for Cat A, I, for III, B...This is an example

of why profiles are helpful and these things need to be

• In Hawaii, Enphase maintains 16 profiles for Hawaii ALONE. Need to standardize...

UL after-presentation Tim Zgonena

• Some AHJs have asked when they'll list an entire assembly • AHJs are in a very difficult position as they're required to review and access these installations

without the benefit of a traditional US certification to an accepted US safety standard… • Existing IEC 61400 is being revised to fill in gaps in the electrical requirements, but that will take

years • UL6141 for large wind turbines (2012) - LARGE = a person enters to service the wind turbine • UL6142? For small wind turbines (2016) SMALL = service takes place from outside the products • UL6142 - small wind turbines - UL1741 is a requirement. You must comply with UL1741 to meet

UL6142. • UL6141 has NO reference to UL1741… It was vehemently opposed.

Day 3 of 3 (2.5 day meeting) Thursday June 14, 2018 ICP Subgroup Wayne Stec and Mark Siira • Note that commissioning testing and witness testing may be different

• Tom Key asked for several utilities in the room to discuss their witness and commissioning testing

requirements.

• Jeannie discussed National Grid’s typical requirements. The Customer, once the one line is complete and settings are finalized/accepted by the utility, will produce a witness test procedure (see NGrid website for template). The witness test procedure is commented on by the utility.


National Grid will then (for sites requiring a utility grade relay (ie typically 500kw or greater or non-certified equipment)) witness the customer’s relay testing and functional testing on-site, as well as the inverter 2-second trip time and 5-minute reconnection time.

• Paul Krell: smaller tests - they may only pull the meter and verify the device doesn't continue to show voltage after that. Might also look at the auxiliary power if they see it to verify ride through. Site verification - checking the equipment is as proposed is important to them, too.

• Roger Salas: We have 4500 interconnection requests a month. Some things have to be in the agreement saying 'if you don't meet we'll take action.”

• Jim Daley: You have to have the signoff by the local wiring inspector with statements that it meets NEC code.

• Roger Salas: SCE has a list of all the contractors doing business in their territory. They've found that many installers don't know how to set the devices up! They try to go to the first few installations of their smart inverters to verify the installers are doing it correctly. Corrections have been made and he says it's a good thing they've done it.

• Richard Bravo has a partnership with PGE. Roger added that one of the reasons why we need the communications is so that we can verify the settings remotely.

• Gent from Georgia Power: 2 evaluations. One at application submittal. Do the study and make requirements from the study. Their threshold is 250kW to perform a study. For larger sites they'll do a 3 single phase site. Protection engineers on both sides might exchange settings to verify coordination amongst protective devices. They're looking at TOV. The second design evaluation is critical - between the time of the first and second the customer's application might have changed (transformer configuration, size, etc.)

• Jim Daley asked and Andy/Wayne confirmed that there is a lot of shall/may language because the utilities have jurisdiction over interconnection requirements testing, for example. The final word is the utility company's, and we don't want to mess with that in this standard.

• Gent from Florida Power & Light: smaller projects pass through expedited with minimal/no extra review by the utility.

• Wayne: There are some shalls in the section, but every utility has, with good reason, multiple ways of doing things. There are some things that we might want to include in the annex or in 1547.2.

• Reigh: What's the difference between the basic DER evaluation and the detailed DER evaluation. o Wayne: In 1547 you'll see that the requirement are more stringent on the PCC than the PoC

case

• X = requirement in 1547 • Gray cell = no evaluation required.


• Jim Daley: Using the words "requirements". Be careful with wording, especially in this table of 'requirements' because it's up to the interconnection agreement with the utility whether the standard is required in whole or in part.

• Babak: If a utility is able to partially adopt 1547, they should adopt 1547.1 partially, as well. Otherwise I think we're just listing "what's required according to the base 1547 standard."

• Reigh: the goal of the standard is to set a standard set of interconnection requirements…. The idea is that the standard is supposed to be presenting at least a model of interconnection.

• Secretary's note: Would recommend folks with examples available, take some examples through the standard and review with key folks what you find.

• Reigh asked why voltage-active power was called out in the example. A: because it's called out in the base standard (in sec 11 tables)

• Tom Key: mentioned there is an EPRI meeting DOE office of Electricity - Public Input on Protection with industry… Oak Ridge.. . You can be invited… July 18-19th - Peer review of research related to protection of utility systems...R&D framework…

• Marcelo: would you need to list steps of what and not the how. We might not have the expertise for the how. o Wayne considers this to be at the guideline level. o Jeannie: You have to be careful to prove that each function "works" AND "Doesn't not

work." For example, not only show me that the facility waits 5min of healthy utility to return, but also show me that it DOES NOT return when a voltage or frequency is low, for example. Try to make it fail and see that it doesn't. BUT you cannot get prescriptive as to how to do the tests, because we might not have the time/expertise to do so. To some degree that's up to the project proposer (at least for a utility).

• Reigh: 7.3 and DE4 might need to be an x. Also stated in some cases that analysis would be better than measurements.

• Andy: we don’t want to make any decisions on what's decided for everyone on comm testing

• Roger Salas: For those facilities where the utility does have communication, we have procedures in place to test for that comm to verify that the comm is good. Roger agreed to submit RCE’s procedures to the group.

• Jeannie envisions the ICP subgroup providing a set of suggested test steps that summarize Roger's procedures. This also depends on whether the utility is using the comm.

• Bob Fox: the definitive testing is whatever entity wants to communicate with the DER, they verify they can communicate w/ the DER. What systems and process that involves will vary.

• Babak gave an example of National Grid's Phase II Solar, where we sent a signal to two inverters in the morning and only one responded in the morning, then the other responded in the afternoon…


• By July 15th, Wayne, Babak, and Mark will re-draft this section with tables. o IT will have intro, table, and then test procedures referenced by the tables. o Less repetition

• Shazreen, via Andy: Different types of design evaluation are grouped together. Would it make

more sense to group all the PoC partial compliance together and the PCC … all together…

• Wayne: Either organization could be used…

• Utilities mentioned that most (by quantity of applications) will be PoC, but by MW it will be PCC. For perspective, California typically has a lot of rooftop installations. SCE for example has 3.5GW interconnected DER. National Grid has mostly MW-scale interconnections (for example several 1MW systems on a single 13kV distribution feeder), with >1.2GW connected system-wide (NY, MA, RI) as of the end of 2017.

• Requested homework assignment: Please review the tables and provide comment on the tables (leave comments on content for later when it’s more developed).

Wrap-Up and Next Steps Looking to have WG vote in October. Pre-meeting written comments/vote before the meeting. Please aim to provide 'and here's how you can fix this comment' with specific text. Next meeting SCE near Los Angeles, CA, Oct 9-11. 1547.2 discussion: This is the 2nd official meeting of .2 revision. 1547 took over a year from when WG 'final' draft to publishing. Tim: How long do manufacturers think it'll take once .1 is published to bring their products into compliance? • Steve Wurmlinger: some manufacturers are still integrating that into their firmware (1547).

Testing will probably take a few months. Some companies will take at least a few months from the start of testing. Some could go 6 months to a year. A lot of these functions are already there for global products, but will need to re-write some firmware because 1547 reqs are a little different. • Tim: 6 weeks w/o automation, 4 weeks w/ automation.

• Bob White has been suggesting folks wait at least 6 months after publication of .1 to expect these new functions to be ready to use and fully tested.

• Tim Z: we already have short circuit test sets. Depends on the product we're testing - they do short circuits on the outputs.

• Manufacturers/UL express that larger equipment will have challenges testing, but smaller will be just fine with testing (have short circuit simulators already, etc). >500kW sounds like may be an issue…

Implementing 1547 and 1547.1: • Bob White suggests that regulators with undated references to 1547 change it to 1547a or 1547-

2003…


• Brian Lydic is trying to work with regulators and suggesting they wait longer to implement… • Paul Krell expects MA will be implementing piece-by-piece • Jeremiah Miller: • Steve Wurmlinger: One thing to add to the importance of the test standard… You never really

know how to write/finish the design until you know how it'll be tested. • Tim: When you test, it often results in changes in the firmware… • Andy: One manufacturer had to train his NRTL on how to test to Ul1741SA because they hadn't

been trained on it yet… • Jason Bobruk: Yeah, there will be a learning curve at the NRTLs. Maybe we could do some

outreach ahead of time to train folks… • Tim Z: Is one year enough to implement, having learned from CA and HI with SA… • Paul Krell: Based on where we stand in MA… It's mostly the ISO NE with requirements for

implementing 1547-2018. • George Bernstein experience in NY was that they'd accept SA, new 1547, whatever as long as it

had some ride thru. • Andy pointed out that you can refer to HECO requirements to meet TOV requirements in 1547-

2018. • Kevin Whitener pointed out that some functions will take time to pay for in tariffs and such -

tariffs take time to update… Example is Volt/VAR • Roger Salas: you'll have some folks that believe that they should be paid for some grid services… In

CA they have passed that portion already… Discussion on iMeet and the base standard... Should start organizing material, process, for 1547 documentation (Charlie's action item) Wrap up and schedule: • June/Aug goal 100% complete draft.

Bob White: PR is 2pm EST Mondays - Jeannie/Andy to update slides Bob white moved to adjourn, Brian Lydic seconded. The WG voted to and adjourned the meeting.

Respectfully submitted,

Jeannie Amber, P1547.1 Secretary, for

P1547.1 Chair, Anderson Hoke

Attachment A – Attendees

Attachment B – Meeting Slides (separate document)


Attachment A – Attendees: P1547.1 Working Group Meeting, June 2018

First Name Last Name Affiliation 1. Marcelo Algrain Caterpillar 2. Anas AlRifai National Grid 3. Jeannie Amber National Grid 4. George Berntsen FuelCell Energy, Inc. 5. David Bianco National Grid 6. Rolf Bienert OpenADR Alliance 7. Jens Boemer Electric Power Research Institute (EPRI) 8. Richard Bravo Southern California Edison 9. Ken Brunkenhoefer Oncor Electric Delivery

10. Jeffrey Cahill National Grid 11. Ke (Kevin) Chen Duke Energy 12. Nancy Connelly Duke Energy 13. James M Daley, PE Facilities Electrical Consulting Services 14. Patrick Dalton Xcel Energy 15. Ratan Das icaPower LLC 16. Kevin Denman UL 17. Mamadou Diong Dominion Energy 18. Ben Ealey EPRI 19. Christian Eder Fronius USA LLC 20. Jonathan Ehlmann SunPower 21. Bob Fox SunSpec Alliance 22. Sergio Freeman National Grid 23. Haile (Gabriel) Gashaw Georgia Power Company 24. Thomas Gwinn NRECA 25. Anderson Hoke NREL 26. Fred Horton Apparent Inc 27. Ruben Inzunza TMEIC 28. Robert Jordan Alabama Power Company 29. Gregory Kern SunPower 30. Thomas Key EPRI 31. Paul Krell Unitil Service Corp. 32. Jesse Leonard Clemson University 33. Haiwen (Howard) Liu Intertek ETL 34. Brian Lydic Interstate Renewable Energy Council 35. James Mater QualityLogic, Inc 36. Ryan McMaster POWER Engineers, Inc. 37. Jonathan Meyer Idaho Power Company 38. Jeremiah Miller EERE - Solar Energy Technologies Office 39. Edward Morrow Rockwell Automation 40. Raja Mosam Caterpillar, Inc

41. Cuong Nguyen National Institute of Standards and Technology


42. Prasad PMSVVSV Bloom Energy 43. John Rinck 44. Michael Ropp Sandia National Laboratories 45. John Ruddock Deep Sea Electronics PLC 46. Miles Russell Yaskawa Solectria Solar 47. Nachum Sadan Gridedge Networks 48. Roger Salas Southern California Edison 49. Joseph Schaefer Florida Power & Light 50. Karl Schoder Florida State University 51. Ron Shipman Oncor 52. Mark Siira ComRent International 53. Mark Smith American Electric Power 54. Gary Smullin Smullin Engineering, Inc. 55. Suzanne Smullin 56. Josh Snodgrass POWER Engineers 57. Lincoln Sprague Dynapower 58. Wayne Stec Distregen, LLC 59. Sylvester Toe Georgia Power Company 60. Charles Vartanian Mitsubishi Electric 61. Reigh Walling Sandia National Lab 62. Robert White ABB Solar 63. Kevin Whitener Portland General Electric 64. Anthony Williams Duke Energy 65. Nicolas Wrathall Kinectrics 66. Stephen Wurmlinger SMA 67. Mehran Zamani Schneider Electric 68. Timothy Zgonena Underwriters Laboratories 69. Jason Bobruk SolarEdge 70. Arash Nezam Somadi National Grid 71. Jason Allnutt IEEE-SA 72. Denisse Rivera Power Engineers 73. John Berdner Enphase 74. Michael Kipness IEEE-SA

Appendix B: Meeting Slides

<Attached as a separate document.>

Documents

IEEE SCC21 P1547.1 Working Group Meeting Minutes, 6/12/18 …grouper.ieee.org/groups/scc21/1547.1_revision/mtgMinutes... · 2018-12-07 · IEEE SCC21 P1547.1 Working Group Meeting