Providing Customer Voltage

Mains electricity is the term used to describe the common household electric power supply in the United States, being 120 Volts (V) at 60 Hertz (Hz).  Electric utilities are required to provide this supply base within certain tolerances per tariffs imposed by state utility commissions, which verify compliance with state regulations.  For example, the Pennsylvania Utility Commission (PUC) verifies compliance with the Pennsylvania Code for Electric Service.  Since voltages constantly fluctuate with varying electric loads on the electric system, utilities employ devices at the substation and on distribution lines, such as load tap changers, voltage regulators and capacitors, to help regulate the voltage that is provided to the customer.  When determining proper secondary voltage of distribution transformers in substations that feed these lines, it is important to understand the substation application of 120V.

Based on the PA code, the allowable variation in voltage measured at the service terminals of a residential customer may not exceed 5% above or below 120V.  Therefore, the allowable voltage range for a customer is 114-126V.  Since loading causes voltage drops along a distribution circuit, it would be ideal to set the secondary voltage of a substation distribution transformer as high as possible but still be in tariff, in that customers at the beginning of the circuit would receive 126V and customers at the end of the circuit would receive 114V.  This variation is smoothed out thru the use of voltage regulators and capacitors throughout the circuit so that all customers receive as close as possible to its nominal voltage supply.

To show what the secondary voltage of the transformer is, an auxiliary potential transformer (PT) steps the secondary voltage down to 120V.  In the example, the PT has a turns ratio of 8,400:120.  If a substation inspector observed 120V on the voltmeter, the secondary voltage of the transformer would be at 8,400V.  A reading of 115V would indicate that the voltage would be lower than 8,400V and a reading of 125V would indicate that the voltage would be higher than 8,400V.  Therefore, the use of the 120V voltmeter is a substation application that indicates nominal voltage and should not be confused with the 120V that a customer would receive.

Rated voltage is stated on the transformer nameplate.  It provides rated voltages for each setting of the de-energized tap changer (DETC), which changes the turns ratio of the transformer by either adding or subtracting turns of the primary winding.  Set while the transformer is out of service, the DETC typically has five settings and shorts out more turns as the setting number increases.  Therefore, the higher the DETC setting, the less stepping down of primary voltage to secondary voltage.  The nameplate voltage of the transformer is taken from DETC position 3.  In the example, a delta-wye distribution transformer has a nameplate voltage of 69,000V primary - 13,200Y/7,620V secondary.  Its DETC was set for 5.  Therefore, in effect, the transformer is rated for 65,600V primary - 13,200Y/7,620V secondary.  By moving from 3 to 5, less turns are left in the primary winding, resulting in less stepping down of voltage.

The next thing to consider when determining proper secondary voltage at a substation is the utility's standard for the turns ratio in all pole-top, pad-mount and underground transformers, on a particular distribution circuit, that transform the distribution line voltage down to 120V for customer use.  In the example, the distribution circuit's nominal voltage is 13,200Y/7,620V.  Customers are connected phase to ground with transformers that are rated 7,620V primary - 240/120V secondary.  Therefore, all the line transformers have a turns ratio of 7,620:120, which is different than the 8,400:120 for the PT at the substation.  Since customers close to the substation can go up to 126V, an ideal secondary voltage at the substation transformer would be 8,001V, which would indicate 114V on the PT's voltmeter.

To help regulate the secondary voltage at the substation under varying loads, load tap changers (LTC) are employed on the secondary side of the distribution transformer at the substation.  It is important that the LTC pass thru the neutral tap when loads change from peak to off-peak and from off-peak to peak, to allow for proper wiping of the contacts of the reversing switch.  Therefore, protection engineers calculate the proper secondary voltage of a transformer at what would be needed at the neutral tap.  The LTC uses the secondary of the PT to sense when it would need to make an adjustment.

The picture shows how to determine what DETC position should be used based on how a nominal 69kV subtransmission system is normally operated at and what secondary voltage would be needed for proper voltage regulation by the LTC.

Article by D Scrobe III

Phase Rotation on Delta-Delta Transformer

  A recent project of mine involved installing a 34.5/4.8kV delta-delta mobile transformer in order to remove from service a distribution transformer from service and repair the metering.  The mobile was parked directly under the 34.5kV line to tap from.  The substation crew preferred to bring the high side leads straight down to avoid any crossing of phases without taking into consideration which phase gets connected to each H terminal.  Surely phase rotation of the sub-transmission system should dictate how the three phase power is connected, I thought.  When putting the mobile into service, it would momentarily be in parallel to the distribution transformer, so it would be prudent to determine proper high side connections of the mobile.  Apparently, it does not matter how you wire the high side of delta-delta transformers.  Whatever phase conductor gets connected to a H terminal then that phase is assigned to the corresponding X terminal.  To understand why you can get away with this, you need to ask just what really is phase rotation?

   There are many analogies to explaining phase rotation on three phase power systems but my favorite is the playground, merry-go-round.  Imagine placing three kids on, evenly spaced apart around the edge or 120 degrees apart.  Pretend each kid is a particular phase of a three phase transmission line.  As you are facing the center of the merry-go-round, if a kid is directly in front of your view, then that phase is at zero potential.  If a kid is to your left, then that phase is at negative potential.  If a kid is to your right, then that phase is at positive potential.  When you go to spin the merry-go-round, you are going to experience a certain sequence of kids passing you.  This is called phase sequence and can only be one of two possibilities, A-B-C or A-C-B, depending on whether you spun the merry-go-round in clockwise or counter-clockwise direction.

   This is not to be confused with the actual spin direction of generators, which drives three phase power on the transmission grid.  Obviously, a generator wouldn't stop and spin in the other direction for the sake of obtaining a different phase sequence.  Phase sequence depends on how phases are marked.  For example, Hosensack Substation in PA is an interface between two different transmission owners, Met-Ed and PP&L.  What is phase marked on one side of the interface is not necessarily phase marked the same on the other.  The conductor that is marked A on one side is marked A on the other.  However, the conductor that is marked B on one side is marked C on the other.  Also, the conductor that is marked C on one side is marked B on the other.  The actual physical conductors and equipment that run through the interface are the same but the labeling of them is what is different.

   Now imagine the merry-go-round again and use to picture how the vector groups of transformers rotate.  Met-Ed assigns phase labels so that an A-B-C phase sequence is always experienced.  Therefore, according to the picture, rotation of the vector groups of the H terminals on a transformer is dictated by the phase sequence of the system that the transformer is connected to.  The picture shows what would happen if A and C phase got rolled.  Although the rotation of the vector group would change, the sine waves are identical.  Therefore, phase would work when comparing the low side voltages of both transformers and customer load would receive the correct phase sequence to ensure that three-phase loads such as motor would spin in the proper direction.  X terminals are not shown because in this example, the secondary voltages of this particular delta-delta transformer are in phase with the primary voltages.

   Article by D Scrobe III

SF6 Emissions in Electric Power Industry

     On November 29, 2011, the Environmental Protection Agency (EPA) issued Federal Regulations, 40 CFR Part 98, Mandatory Reporting of Greenhouse Gases, making it mandatory for all electrical transmission and distribution owners, with combined facilities that have a nameplate capacity of sulfur hexafluoride (SF6) gas exceeding 17,820 pounds, to submit an annual accounting report on its SF6 usage.  EPA compares this report to the last submitted annual report and determines the amount of SF6 that was lost to the atmosphere, resulting in fines and fees to the partner corporation responsible.

     SF6 is an effective electrical insulator in high voltage equipment, such as gas insulated substation (GIS) structures, circuit breakers and circuit switchers, however, it is the most potent greenhouse gas.  SF6 emissions to the atmosphere from electrical equipment are due to gas leakage from failed gaskets, manufacturing defects and improper bushing installations.  A short term solution to gas leakage is to use SF6 bottle inventory to refill the equipment, thereby, avoiding a long term, equipment outage.  This use of SF6 inventory would be captured in the annual accounting report to demonstrate the amount of SF6 that was lost to the atmosphere.  A long term solution would involve taking an outage of the equipment and have the manufacturer work with the partner to find and repair the gas leak.

     SF6 tracking is done by weighing SF6 bottles, before and after its use, with scales that are capable of a +/- 2 lbs. of true weight tolerance.  When a SF6 bottle is shipped by a supplier such as Airgas or Concorde, the product is highly compressed and the bulk of it is in liquid form.  At the top of the bottle though, SF6 is in a vapor form, at a pressure of 312 pounds per square inch (PSI).  Since gas has negligible weight, when a bottle is weighed, the measurement in lbs. is mostly due to the liquid product.  When a SF6 bottle is used to fill equipment, the gas naturally flows from the bottle to the equipment because of the difference in pressure, as gas will always flow from a high pressure atmosphere to a low pressure one.  As SF6 flows from bottle to equipment, the liquid volume would diminish, however, the vapor at the top of the bottle would remain at 312 PSI up to a certain threshold point when the SF6 liquid volume becomes very small and the vapor pressure begins to drop. Eventually, the vapor pressure in the bottle approaches the same pressure inside the equipment. When pressure is equalized between the bottle and the equipment, SF6 can no longer flow from the bottle to the equipment, making the bottle practically empty.  The remaining weight of the SF6 product left over in the bottle is referred to as a "heel" and the weight of just the bottle alone is referred to as a "tare."

     SF6 in equipment is considered an ideal insulator when its pressure is generally around 90 PSI on a 68F degree day.  As various equipment have different volumes of tank enclosures to hold the gas, manufacturers specify on its nameplate the required amount of SF6 gas in lbs. that is required to fill the tank enclosure, based on a 68F degree day.  According to the Ideal Gas Law, if you maintain constant temperature and constant volume for an enclosure of gas, then the pressure will vary proportionally to the amount of molecules in the enclosure.  Therefore, if you inspected equipment on a 68F degree day and found the pressure gauge reading 70 pounds per square inch on the gauge (PSIG), you can determine that a 20 PSIG drop relates to a particular amount of SF6 product lost, based off of information from the nameplate. And if the temperature of the day is different than 68F degrees, manufacturers provide charts to show how nominal SF6 pressure varies proportionally to ambient temperature. Knowing how much SF6 was lost is important when determining how much bottle inventory should be dispatched to the site for refilling.

     SF6 tracking is basically verifying the annual replenishment necessary to maintain nominal SF6 pressure for all equipment that uses SF6.  If your system has a total nameplate capacity of 17,820 lbs. of SF6 product and 1,782 lbs. of SF6 product from bottle inventory was used to re-gas equipment that had leaks, then 10% of your total nameplate capacity was lost to the atmosphere and the EPA would fine for that loss.

     Article by Dan Scrobe III

How To Use an Arbiter 928A Power System Multimeter

    The Arbiter 928A power system multimeter, mentioned in the blog post In-Service Load Checks, is an excellent device for measuring electrical power during commissioning checks.  It is a 2-channel device that measures and compares two AC signals coming from the secondary side of instrument transformers.  It is important though to set it up properly to meet your personal preference and to use it successfully for the first time.

    In this example, the 928A was set up as follows in the phase preference settings.  Channel A was chosen as the reference.  Voltage was applied to Channel A and current was applied to Channel B.  The polarity was set for positive.  The degree range was set for 0-360.  The 928A was used to measure the electrical power flowing at one end of a 69kV sub-transmission line.  The instrument transformers used was a bus, potential transformer (PT) and a line breaker, bus-side current transformer (CT).  The secondary voltage of the A phase PT was applied to Channel A and the secondary current of the A phase CT was applied to channel B.  The amp probe arrow was facing away from the CT polarity mark and looking towards the relaying and metering.  The 928A readings of 65.222V, .506A and 197.48 angular difference in Picture 1 revealed that the current lagged the voltage by 197.48 degrees and that 13.6 megawatts and 4.3 megavars were both flowing into the bus from the line.  By comparing this power flow to the power flow at the other end of the line, this proved to be an accurate reading.

    The 928A is able to make this analysis by looking for similar zero crossings of the two AC signals and determining the angular difference between the two crossings.  In picture 2, the voltage and current for this example is graphed on an amplitude vs. time graph.  Because voltage was selected as the reference, the voltage sine wave rises and crosses zero amplitude at time = 0 seconds.  About ten milliseconds later, the current rises and crosses its zero amplitude.  The 928A determines from this time difference that the current lags the voltage by 197.48 degrees.

    Two common mistakes made when using the 928A is incorrect placement of the amp probe arrow and incorrect interpretation of the angular difference reading, not to be confused with phase angle.  Regardless of which way power is flowing, the amp probe arrow should always be placed so that the arrow faces away from the CT polarity mark and towards the relaying and metering, which is connected in the CT circuit. This is done because it is standard for the direction of CT current flowing away from its polarity mark and into the relaying and metering to be compared to the phase to ground voltage signal.  Picture 2 shows how secondary CT current flows in relation to primary current flow.

    When you want to draw current and voltage vectors on a power graph, the 928A set-up dictates how you should interpret the angular difference angle that is given.  In this example, because the voltage is the reference, its vector is drawn on the zero degree mark on far right.  Because the polarity in the phase preference settings of the 928A is positive, the current vector is drawn 197.48 degrees clockwise from the reference to show that the current is lagging the voltage by 197.48 degrees.  Technicians might want the angle shown to direct the current vector to be drawn counter-clockwise from reference.  In this case, if the polarity in the 928A set-up was changed to negative, the 928A would give an angle of 360 minus the angular difference reading, being 162.52.  Now, by drawing the current vector 162.52 degrees counter-clockwise from the reference, it would put you in the same spot.  It is important to note that the Arbiter always looks for a lagging value of the non-reference channel to the reference channel.  If current was selected as the reference, then the 928A would look to see how the voltage lags the current.  It is also important to notice that CT secondary current is flowing opposite to the direction of the amp probe arrow.  If the megawatts would have been flowing in the other direction, flowing from bus out on the line, the angular difference would have been 17.48 degrees, which is the phase angle.  Opposite current direction in this example causes a 180 degree phase shift and is what indicates to the technician that megawatts is actually flowing into the station, rather than out of the station.

    Article by Dan Scrobe III

How To Prove CT Connections Using Vectors

     On a Delta - Wye transformer, CT's on the Delta side are wired in Wye and CT's on the Wye side are wired in Delta in order to correct a phase rotation and to filter out zero sequence current. However, how would a commissioning engineer go about proving that the delta CT is wired correctly on the Wye side?  In other words, would polarity of the CT on A phase connect to non-polarity of B or C?  A Linked In forum member shared with me that it is typical that the CT wiring configuration on the Wye side of the transformer should mirror the Delta side winding connections of the transformer.  For taking it an extra step, this could be proven using vectors.

     Dan Scrobe III