Can one synchronize a COGEN with utility without parallelling ? 4

[hmchi]

The utilities in the world usually do not like co-generation systems of their customers to be parallelled to the utility own system. Many simply forbid it. However, when there is a problem and the customer paid to have a 'hot standby' source from the utility, they will allow a source transfer operation.

Obviously we need to switch when the 2 sources are in sync. So is there a way to keep the COGEN in sync with the utility source without actually connect in parallel ?

 

[slavag]

Im still not sure if it's possible.
Yep. David right, we do transfer scheme too, but it's for two synchronasing systems with big AC motors.
Here trip of generator are possible from few reasons, as Bill pointed, for example from underfrequency protection or loss of execitation, or from fault on busbur....
Isn't simple issue.


Best Regards.
Slava

 

[rhatcher]

daividbeach,

You brought up a good point that led me to think of why the OP's utility is concerned about running in parallel. That being said, your actual point differs from the point I see.

I can imagine a scenario where the contributiun of fault current to the system from a cogen would be a concern beyond the point of interconnection and would involve costs not normally directly associated with construction and connection fees.

Imagine a power plant with a radial feeder system. A distribution substation at the end of a feeder has enough excess load capacity to feed a proposed new small manufacturing facility. The short circuit current from the utility at that substation is relatively low because of the radial distance, let's say 30 miles.

Let's also say that the manufacturing faciltiy is cogen with a generating capacity equal to it's power consumption (1:1) and that it is only 1 mile from the existing substation.

Theoretically, the cogen facility could supply much more contribution to a fault current at that substation than the distant utility. Unless this type of contribution was considered in the original design of the feeder substation and everything downstream of it, it can be imagined that everything in that substation and downstream of it would need to be upgraded to a higher MVA interrupting rating if parallel operation was allowed.

Of course, if this is true, then how/why would the utility allow an interconnection at that substation in the first place? They are protected from the fault current contribution of the cogen by having a contract that prevents parallel operation.

Perhaps this is how and why the OP is in this situation.

 

[rhatcher]

davidbeach, I'm not picking on you but I also have some questions about the utility-plant phase relations you describe.

I would think that a wye-wye transformer would have the utility-plant phase relationship at 0 degrees ("I'd connect that reactor through a Y-Y transformer connected to put the plant 60 degrees ahead of the utility...").

I would think that a standard delta-wye step down transformer would have a difference of +30 degrees ("We have a plant where the off-site aux power source was 30 degrees ahead of the plant...").

I would think that a wye-delta step down would have a phase difference of -30 degrees (" After reconnecting the aux transformer so that it lagged the plant by 30 degrees...").

Finally, I would think that it is possible to connect a wye-wye or a delta-delta for 180 degrees but I do not understand how you could get a phase relation of 60 degrees with a single transformer nor do I see how you could get any "odd multiples of 30 degrees" such as 90 or 150 degrees.

Of course, they may be something really obvious (dumb on my part) that I am overlooking at the moment. If so, I hope that someone points it out and, if so, I apologize for the mistake.

 

[davidbeach]

When living in the ANSI world, it is very easy to think that the standard that low side lag high side by 30 degrees is a hard and fast rule. It is useful, and for probably 99.99% of all applications it is all that is necessary. But it ain't the whole picture.

The IEC world gets a bit closer with their clock notation, but even there there can be a temptation to assume that a Dy1 transformer is always a Dy1 transformer.

First off, break all preconceived notations about phases and terminals of the transformers. The internal wiring of the transformer tells how H1, H2, H3 relate to X1, X2, X3 but doesn't necessarily say how A, B, C have to relate to a, b, c.

First set of transformer transformations - take your a, b, c leads and roll them one position either way. You now have the possibility of steps of 120 degrees.

Second set of transformer transformations - take two phases on the high side and swap them and at the same time swap the same two phases on the low side, that makes a 60 degree shift. If the low side lagged by 30 degrees, it now leads by 30 degrees and if it lead it now lags.

Between those two transformations you now have 60 degree steps. For all transformers with a delta and a wye, those 60 degree steps are all odd multiples of 30 degrees (30, 90, 150, ...) and for transformers with two wyes or two deltas, those 60 degree steps are all even multiples of 30 degrees (0, 60, 120, 180, ...).

At the plant in my previous example, we'll take the 500kV bulk power system as the reference at 0 degrees. The plant source for the motor bus is separated from the 500kV system by two delta-wye transformers and therefore is at -60 degrees. The off-site aux power was separated from the 500kV system by one delta-wye transformer and therefore was at -30 degrees. -30 degrees is 30 degrees ahead of -60 degrees. Through a swap on the high side and a swap and a roll on the low side the transformer for the off-site aux power moved forward 60 degrees (the swaps) and then back 120 degrees (the roll) and wound up at -90 degrees. -90 degrees lags -60 degrees by 30 degrees.

 

[rhatcher]

Good explanation of your answer. If I follow you correctly, you start out of phase 120 degrees, reverse phase rotation 180 degrees, and the result is a net 60. I get that, although I will sleep on it tonight to make sure...That is clever.

You are right, although I have looked at zig-zag connections before, for the most part I was stuck in the conventional thinking of transformer phase relationships between delta and wye and had not considered the possibilities of phase roll and reversal. Thanks for the clear and detailed answer and for not making me sound like a dummy.

 

[rmw]

David,

Thanks from me too.

rmw

 

[davidbeach]

I missed the rhatcher (Electrical) 26 Oct 09 18:15 post in my previous response. In the world I live in, we can't say no to an interconnection request, and that is probably true for most utilities in the US. But what we can do, and do do, is study all of the impacts of the proposed interconnection and tell them the cost of mitigating all of their impacts. That can range from nearly nothing to extensive rebuilds, sometimes well away from the proposed point of interconnection; but there are no insurmountable technical obstacles. Money can cure anything, but the need for too much money can kill most any project.

So, I'll stand behind my statement that there are no technical reasons to prohibit interconnection, only economic realities. Maybe the co-gen in question would have required more system upgrades than the cost of the plant; possible, and a good reason not to design for parallel operation, but not a technical obstacle.

Connection through reactors would reduce the reduce the fault impact but allow a phase relationship to be maintained. There would be some load flow back and forth through the reactors as the plant load changes due to load-generation mismatches that presently show up as frequency changes.

 

[rhatcher]

For anyone else who is still thinking about the transformer phase shifts that davidbeach described but who are still not fully understanding it, this paper explains it and makes the explanation clear with phasor diagrams and connection diagrams. The phase shifts are not the point of the paper, differential relay protection is. However, in order to explain his point, the writer gives us all we need to know about the possibilities of reconnection of transformers to get non-standard phase shifts as davidbeach describes. It definitely helped me.

http://www.basler.com/downloads/3phXfmrs.pdf

for davidbeach: Any time I see someone say; "I'll stand behind my statement" in response to one of my posts, I get the impression that they think that I have disagreed with what they said. That is not the case here.

A few days ago, I was stuck on the question of why would a utility that is capable of supplying load current to a plant not want to allow parallel operation with the same plant having a 1:1 cogen capability. Your post of 25 Oct 23:45 gave me the idea that answered my question; the fault current contribution of the cogen to the utility system beyond the point of interconnect.

In the scenario that I offered, there is no technical reason not to parallel if you can afford to pay the economic cost of upgrading the utility's distribution substation(s) to a higher MVA interrupting rating. It's just a matter of cost. We agree on that point.

That being said, the OP has stated several times that his utility does not allow parallel operation and he has stated that he is in Asia, not the US. I'll bet he wishes that he had a utility that was from 'your world' where this would not be a question or a problem. However, 'his world' is obviously different. I was offering an idea of why that may be true.

Moving on...You have offered a good, cost effective, solution for the OP to eliminate the utility's concern about the cogen's contribution to utlity system fault current. The use of a significant, high impedance, reactor when operating in parallel with the utility would definitely allow sychronized operation when there is no power flow while protecting against increased fault current contribution to the utility from the plant (or visa versa).

However, it seems to me that the reactor would have to be dropped out of the circuit once there was power flow through the interconnect point or else there would be a significant voltage drop across the reactor proportional to the plant load. A simple way to do this would be a breaker in parallel with the reactor that closes and shorts the reactor when the cogen generator breaker opens.

Does this agree with your knowledge and experience or am I missing something (again)?

 

[rbulsara]

I also know of at least one utility co in New England that would not allow paralleling with them in certain parts of their network, especially those in downtown area with a lot of spot networks, without giving a reason. Too much liability perhaps.

Rafiq Bulsara

http://www.srengineersct.com

 

[rhatcher]

I hate to be long-winded in my answers, I am working on that. Also, perhaps I am too concerned about upsetting other forum members.

I should have simply replied that I believe that my response was appropriate to the OP's situation and then pointed to this post from the OP on 25 OCT 09 16:58 where he said:

" Our problem would not have existed had the utility would allow us to parallel. davidbeach says not all utilities are alike. True indeed, except in Asia most utilities are government owned and operated .. enough said .. talk about arrogance and dictatorial ... They claim [somewhat justified] they are concerned about fault current contribution to line faults .. You said you guys are OK, are you not concerned about that ? (I added the underline)

I think my answer to the OP of why this may be true was a good possibility.

 

[davidbeach]

rhatcher - Yep, I was thinking reactor only in when generator is paralleled; standby connection through a different path that doesn't have the reactor.

rbulsara - Secondary network systems were never designed to be anything other than radial. Any generation introduces complications that are difficult to overcome. IEEE P1547.6 will address these issues and has been rather contentious over the 4 plus years we have been working on it.

 

[rhatcher]

Can you guys explain what the terms 'spot network' and 'secondary network system' refer to? Thse are terms are new to me.

 

[davidbeach]

Network systems - the short story.

General - A system in which multiple primary circuits (generally 3-4, can be as few as 2) feed transformers paralleled on the secondary side. Transformer protection in the form of a network protector; little to no protection against forward faults, very sensitive to reverse current to the point of interrupting transformer excitation current. Main purpose of the network protector is to remove back feeds to faulted primary circuits. Secondary faults, particularly on area networks, allowed/expected to burn open.

Area Network - aka grid network, aka street network; generally 208V. Many transformers all paralled over a large area (10's to 100's of blocks) in city centers. Loads tapped at many locations. Very high to extremely high available fault currents (well over 200kA in portions of Manhatten).

Spot Networks - Generally 480V. All transformers and network protectors in a single vault (spot) to serve a single building or portion of a single building; could have multiple spots at different levels of a high rise building.

 

[rbulsara]

rhatcher:

Also look up NEC 450.6 and read the commentary in the NEC handbook for it. Pretty self explanatory. NEC refers them as just transformer networks with secondary ties.




Rafiq Bulsara

http://www.srengineersct.com

 

[rbulsara]

davidbeach:
Spot network are issues only if someone wants to export to the utility. Not all paralleling are for exporting. In fact many are used merely for soft transferring the loads between the utility and the gen plant. Even the intertie breaker has reverse power protection.



Rafiq Bulsara

http://www.srengineersct.com

 

[davidbeach]

Inverters on spot networks are probably not going to be too difficult, but synchronous machines are quite another issue. The problem isn't steady state operation, but the response of the network protectors to high side faults. Without the generator, only the network protector on the faulted circuit will trip. With the generator, and all of the primary circuits tied at the source as is the usual case, the fault current can flow out through all of the network protectors, causing all of them to trip. That is a significant problem.

 

[rbulsara]

david:
That is a separate discussion..there is a trade off of risk/benefit depending upon how long a gen remain in parallel and how much fault current a customer gen can provide.

Directional over currents on inter-ite breakers can easily be coordinated with network protectors, for non-exporting paralleling.

In fact loss of all NP (IF that happens) will not affect the user ( and should not to the utility). The user has the gens already running.

Many of the issues are created by utility co. themselves, (I know of one case), where two MV feeders are arranged as spot network at the customer end, to help utility feed the heavily loaded feeder from both ends..! This though is very beneficial to the user as they have the increased reliability.

Much of this depends on who you are dealing with and somewhat on the design, I have had a flat denial, even to discuss, for a 3MW, 480V gen plant for a few seconds, a very elaborate exchange of information, impact studies and meetings to get a 4-6MW,13.8kV plant approved and absolutely no real push back for a 20MW and 7.5MW gen plant paralleling.

Not all issues or their solutions are technical, political will and relations also affect many decisions.

The explosion in wind turbines is one example. The most notorious and problematic interconnection from a stability point of view is a WT farm, yet they are more easily accepted compared to some roadblocks thrown at proven interconnection for conventional DGs. This is because of the political environment for green and renewable resource initiatives.

You can make anything happen if you have the will, especially the political will!




Rafiq Bulsara

http://www.srengineersct.com

 

[hmchi]

rbulsara said --- The explosion in wind turbines is one example. The most notorious and problematic interconnection from a stability point of view is a WT farm, yet they are more easily accepted compared to some roadblocks thrown at proven interconnection for conventional DGs. This is because of the political environment for green and renewable resource initiatives.

Absolutely true ! WTGs are induction machines, no var compensations at all [except GE machines]. reactive compensation and utility line fault decoupling and voltage support even bigger issue .. but they are allowed to connect and parallel [sure, they export almost 100% and COGEN may not ..]

Just think if utilities in the West can be so dictatorial, how bad can the Asian government owned and operated utilities could be ..

That is why I came to think that there must be a lot of COGEN before our facility who had the same problem and may have already solved the problem ... and it appears that they do not read this website and come to enlighten us ..

 

[rbulsara]

hmchi:

How big is your Cogen? and what type of loads?

I do not believe in fast transfers for magnetic loads. I would rather look in to rotary UPSs (of the right kind) with good flywheels, as suggested before.

I presume, you are not talking about transferring when the co-gen fails under a fault. If so consider Static transfer switches (STS) for those loads that can take it. They have their own challenges, though.

You also can segregate loads that can take momentary outage and those who can't and devise a solution accordingly.








Rafiq Bulsara

http://www.srengineersct.com

 

[rbulsara]

Also I would look to build redundancy in the co-gen plant itself for critical loads and not depend on the utility.

Rafiq Bulsara

http://www.srengineersct.com