Exporting VARS to utility from Synchronous motors 1

[rockman7892]

I was in a papermill recently which had several large synchronous motors (7000HP each) connected to 13.8kV switchgear located directly downstream of the incoming main transformers. It was mentioned during the visit that these motors were capable of exporting VARS back to the utility and therefore there were certain utility requirements in terms of protection and control at the plants main substation.

In facilities such as this with large synchronous motors is it typical that the facility exports VARS back to the utility? Is this done intentionally in any cases such as for VAR support to the utility, or is this just sometimes a result of how the motors are operated/controlled in relation to plant conditions?

Do utilities have certain protection and control requirements that need to be met for plants that can export VARS similar to those requirements for plants that can export power (32, 67, 27, etc....)

I also noticed that on the ties between the main 13.8kV buses where the motors are located there are 3000A X=11.3% reactors. What is the purpose of these reactors? Are they to somehow control VARS sharing between the buses in a Bus-Tie configuration?

 

[Skogsgurra]

Synchronous machines are almost always used to produce capacitive vars to compensate for inductive vars consumed by the machinery in the paper mill. Same thing in most other plants.

As soon as the excitation is taken up above what is needed to run at cos(phi)=1, you will produce capacitive vars.

The reactors were probably there to reduce prospective Isc or starting currents.

Gunnar Englund

http://www.gke.org

--------------------------------------
Half full - Half empty? I don't mind. It's what in it that counts.

 

[cuky2000]

1) Export VAR: Synchronous motor operated as synchronous condenser could absolve or delivery VARS to the grid depending upon the field excitation (brush or brushless exciter) of the motor (See the V curve in the enclosed file).
It operates at a leading power factor and puts VARS onto the network as required to support a system's voltage or to maintain the system power factor (PF) at a specified level. Should be noted that whenever PF correction is required must be specified previously to order the synchronous motor.
2) Typ. Utilities Requirement:
• PF Surcharge: Utilities apply penalty when power factor drops below a certain level, usually under 90%. Service revenue metering capable of recording at every 15 min interval the demand of kilowatt, kilowatt-hours (kWh) and reactive kilovolt-amp hours (rkVAh).
• Relay Protection: I am not aware of any special utility requirement for a 13.2 kV plant service entrance associated with large synchronous motor. The usual protection of motor in the switchgear is: Phase overcurrent (50/51P), Neutral overcurrent (50N). Motor differential overcurrent (87M). Load jam (JAMTRIP). Power factor (55). • Current unbalance (46 and 50Q). • Phase reversal (47T). Overvoltage and undervoltage (27/59). Overfrequency and underfrequency (81).

3) Reactor: Probably the reactor is series-connected with a motor to help limiting the inrush current during the motor starting operation. A common application after start-up, the reactor is by-passed to limit losses in continuous operation. Less common application is use the reactor connected continuously to limit excessive short-circuit.

 

[stevenal]

Utilities I know would not want to depend on a mill outside their control for var support. What happens when the mill shuts down? Best to set controls to offset the mill's own usage.
The utility would likely need to model the motors and protection, since big motors will contribute to fault current on the system. Fault studies may dictate requirements.

 

[LionelHutz]

There should me no special service requirements for a site with synchronous motors. They are still motors and still require line power to operate.

The reactors are likely there to limit the Isc when the buses are tied.

Just to note, you can only export VAR's up to the capacity of the motor. Synchronous motors are typically rated at a 1.0 power factor or a 0.8 leading power factor. A 1.0 PF motor would not be capable of exporting any VAR's when operating at full load.

 

[waross]

A common application of synchronous motors is to use motors somewhat oversized for the load. The motor is then over excited to produce VARs to improve the plant power factor.
Much less common would be to produce enough VARs to push the plant power factor leading.
Historically power factor penalties in North America Kicked in when the monthly average PF dropped below 90%.
However some countries penalize any departure from unity power factor starting at 1% under lagging or leading, on a running basis.
I would expect that in the event that the utility accepted exported VARs it would be under the similar terms and conditions as would be required for co-generation.
Further to cuky2000's comment in regards to exported VARS supporting the system voltage;
I spent some years in a city in a small country where our system voltage was supported in this manner.
Many years ago, the city was supplied by diesel generation. In the mid 1980's a large hydro-electric installation was commissioned and transmission lines were built to distribute power across the country.
By 2000 the transmission line was becoming overloaded and low voltage during peak usage times was common.
Eventually the National Electrical Energy Company recommissioned the old diesel plant. The engines were in need of overhaul as maintenance had been neglected for a number of years in anticipation of cheap hydro power.
The diesel plant now produce only a minimum of real power, but supplied leading VARs to support the voltage in the city and to offset the voltage drop on the transmission line. Note that often a transmission line of any appreciable length is often capacity limited by voltage drop rather than be the ampacity of the line conductors.

Bill
--------------------
"Why not the best?"
Jimmy Carter

 

[GroovyGuy]

These 7000hp motors are driving TMP refiners, correct? They are likely too large for grinders. I have designed several TMP mills with up to seven x 16,000hp synch refiner motors. In all of these mills the power contact only required that the mill maintain 90% (or better pf). I have never heard of a mill be contractually obligated to supplying VARS back to a Utility. Having said that a one mill the first refiner motor was the hardest start (due to voltage-drop during motor acceleration). Subsequent motor starts were aided by the already running motors supplying VARS to the accelerating motor.

I suspect that the reactors you observed are there purely for limiting fault currents (ie when the tie CBs are closed between two or more buses.) In the case above (with the seven x 16,000hp motors) the incoming Utility was at 230kV and the plant was equipped with three x 45MVA transformers. Each transformer supplied a lineup of 13.8kV swgr c/w tie CBs. The swgr was rated 1000MVA. Without the reactors, the available fault level at any bus, with the ties closed, would be > 1000MVA.
Hope this helps.

 

[rockman7892]

GroovyGuy

Yes the more I think about it you are probably correct that the reactors on the tie's between buses are to limit fault currents when the incoming transformers are paralleled by closing the 13.8kV Switchgear bus tie's. With two or three of the buses tied together a given bus will receive full fault contribution from its respective transformer that its directly to, and a reduced fault current contribution the other transformers resulting from the reactors on the bus ties.

Because of the way the reactors are arranged on the bus ties there will be two reactors (3000A X=11.3%)in series when any two of the buses are tied together. Does this mean that there is a total of X=22.6% when two buses are tied together? Does this 22.6% represent an impedance on a P.U. basis of the overall system? Does this impedance lead to any issues with steady state conditions (voltage drop, etc..) when buses are tied together?

Regarding the VARS exportation - The existing 161kV substation consists of a ring bus with two incoming lines and three transformer feeds. The plant currently owns all this equipment in the substation but is now re-configuring the substation in order to provide the utility with ownership of the 161kV ring bus and associated equipment while the plant will only keep ownership of the transformers. In order to keep ownership of the transformer protection they are adding circuit switchers between the ring bus and transformers with associated protection and control that the plant will own.

Although I did not follow all of the details the plant personnel mentioned that the reason for the re-configuration was because of the fact that since they had the potential to export VARS they were considered a "Power Provider" and therefore needed to meet certain requirements dictated by the Bulk Electrical System (BES Conveyance). I'm not exactly sure what these requirements were but because they did not have the capability to meet them or provide documentation for them they are now selling the ring bus portion of the substation back to the utility.

I know this is limited information but I was hoping someone more familiar with the utility side of things what be able to chime in on the need for the reconfiguration as mentioned.

 

[waross]

To bad they won't accept a Reverse Reactive Power Relay

Bill
--------------------
"Why not the best?"
Jimmy Carter

 

[GroovyGuy]

rockman7892
I suspect that there will be only one reactor between any two buses. So yes the voltage drop could be significant if the reactor was passing 3000A, although I doubt that it would be as high as 11%. This is assuming that the bulk of the power was real, and not reactive. A quick load-flow model could prove this out.
I also expect that the transformers will be equipped with OLTCs, which can push power where required and help with voltage-drop issues on the secondaries.

 

[bacon4life]

I am confused as to how exporting MVAR would have any impact on their power provider status and as to how transferring the ownership of the ring bus would change the MVAR export possibility. I suspect that they more likely sold the ring bus because it was included into the NERC definition of BES. The BES definition excludes radial equipment, so by owning only the transformers, the mill would not be subject to NERC standards.

The paper mill we used to serve use their synchronous motors to maintain exactly 0.95 pf as that was where our power factor penalty kicked in. Providing reactive power by overexciting a motor increases losses, so I would not expect a mill to export MVARS unless mandated or incentivized to by the utility.

 

[rockman7892]

bacon4life

Why does the fact that the Mill owns the ring bus make them Subject to NERC standards? If they do not export VARS like you said then why would they be subjected to NERC requirements just because they own the ring bus portion of the substation?

I believe what you said is true and they are selling the Ring Bus to utility because they cannot meet NERC requirements but I guess I don't follow why this is a problem in the first place. Can you briefly explain the issue with NERC and the BES that you alluded to.

Thanks

 

[bacon4life]

Prior to 2003, the model for the transmission industry was voluntary compliance with best practices. Although most utilities followed many best operating practices, a number of entities had very poor practices. The east coast blackout in 2003 highlighted the need for a better enforcement mechanism to ensure all entities across an interconnection were doing their fair share to ensure reliability. Among the alternatives, the Federal Energy Regulatory Commission choose to implement mandatory minimum standards across the industry. FERC's mandate from congress is limited to transmission, so the definition of Bulk Electric System was highly contentious. The current result is that anything determined to be part of the BES is subject to mandatory federal compliance while non-BES equipment is either unregulated or regulated by state regulators.

The BES definition includes equipment operating at more than 100 kV unless the equipment is radial. The link has more detailed info on the nuances of the definition.

NERC is the commercial entity that develops and enforces standards on behalf of FERC. The main issue with NERC requirements is that there is a very significant amount of documentation required to prove compliance with the standards. Even if the mill was already following best practices and did not have compliance costs for improving actual operations, it wouldn't surprise me if the mill needed to add another Full Time Equivalent to handle all of the paperwork.

 

[rockman7892]

bacon4life

I was finally able to speak to the utility representative involved in this project, and you are exactly right the Mill is selling the ring bus back to the Utility to meet the NERC/BES requirements that you discussed above.

Apparently the 161kV ring bus is between two different 161kV transmission lines that come into the Mill's substation so the ring bus itself is considered part of the transmission system and therefore subject to NERC requirements. Is sounds like the Mill does not have the capability to meet those requirements as you suggested.

Thanks for the BES link. I will give it a read to gain a better understanding of the BES.