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

In-Service Load Checks

photo: www.energy-parts.com

     Before new substation circuit breakers are released for normal service to transmission operators, it is imperative to ensure that its current transformers are providing the proper secondary current inputs to protective relaying and metering, as called for by protection engineers.  This is done by performing in-service load checks when the breaker is carrying load for the first time.  A technician will measure secondary currents and voltages, and the phase angle shift between the two of them, that go to relaying and metering.  The secondary voltages are taken from line/bus potential transformers and are used as a reference to measure the phase angle.  The engineer will calculate the primary and secondary currents, along with the phase angle, based off of what is happening on equipment that is already in service.  Once the technician and engineer agree with their findings, they will verify that these secondary values are properly telemetered to transmission control centers.

     In this example, Cat-Trac has a 115kV bus with two transmission lines connected to it.  Each line breaker has bushing current transformers (CT) and the bus has a potential three phase transformer (PT), both of which provide secondary inputs to relaying and metering.  Breaker 98712 was replaced, therefore, breaker 97112 was used as the reference, for purpose of calculating current magnitudes and phase angle for breaker 98712.  Work was scheduled in accordance with PJM.  This system utilizes A-B-C rotation.  A balanced three phase system was assumed.  Voltage and current magnitudes are in RMS.  

     The phase angle is the angular difference between voltage and current and it is based off of the real and reactive power flows.  Since breaker 97112 showed .7 megawatts (MW) and 8.3 megavars (MX) flowing into the bus, breaker 98712 should have the same readings but both flowing away from the bus.  Using basic power formulas, the phase angle was shown to be 85 degrees.  The angle is considered lagging because the MW's and MX's are in the same direction.  On a distribution and transmission system, it is accepted that inductive reactive power will flow in the same direction as real power.  Capactive reactive power would flow opposite to real power.

     Using basic power formulas and a reference line-to-line voltage reading, taken from a voltage meter from the bus potential transformer, primary amps was calculated to be 41.5 line amps (A).  CT secondary current was calculated to be .17A, using the CT's ratio of 240, which is a ratio number of primary amps to secondary amps.
     It helps to draw current vectors on a power quadrant graph. You simply pick the quadrant you need to be in, based on what the real and reactive power flows are. Because current vectors rotate counter clockwise, it is important to draw the graph so that negative MX's are on the positive vertical axis and positive MX's are on the negative vertical axis.  First Energy standard is that power that flows away from the substation is considered positive and vice versa for flows that come into a substation.  Therefore, since both real and reactive power flowed away from the substation in this example, the first current vector is drawn in quadrant two with an angular difference from the horizontal axis.  If positive real power and negative reactive power flow was observed, then the current vector would have been drawn in quadrant one.  Negative real and positive reactive would have been quadrant three.  Negative real and negative reactive would have been quadrant four.
     Because a three phase potential transformer was used for the voltage readings, A phase is considered the reference.  A reference vector is typically drawn at zero degrees.  Therefore, you can imagine this voltage reference located at zero degrees on the power quadrant graph.  The first vector drawn in quadrant two in the picture shown means that A phase current vector lags A phase voltage vector by 85 degrees.  Once this first current vector is drawn, then it easy to draw the other vectors to show 120 degree displacement and A-B-C counter-clockwise rotation.
     When the breaker was put into service, current vectors were read from a SEL-411 relay and drawn on a graph.  A phase current was shown as 86 degrees lagging, which is very close to the calculation. You will also notice an imbalance in the current magnitudes.  There will always be some imbalance but it is very important to verify the correct phase angle and phase rotation, so that when readings are telemetered to transmission control centers, the operators there know the correct direction that real and reactive power is flowing.
     Article by Dan Scrobe III

What Is An Arc Fault Circuit Interrupter?

     For homeowners of new home construction, you might find some unusual looking yellow circuit breakers in your circuit breaker panel.  According to an online journal report from Lansing, Michigan, that was put out last October, more than 50 percent of the electrical fires that occur every year in the US could have been prevented with the installation of arc fault circuit interrupters or AFCI's, which immediately shut off power when a fire hazard - or an arc fault - is recognized.  Typical household fuses and circuit breakers do not respond to early arcing and sparking conditions in home wiring.  By the time a fuse or circuit breaker opens a circuit to defuse these conditions, a fire may already have begun. AFCI's defend against damaged electrical cords and sparking wires, is currently a residential code requirement in 49 states (Indiana being the exception) and runs about $40 for each device.  As a result, families should be better protected from the threat of electrical fires in the home. So, how does an AFCI work?

     Unlike a standard circuit breaker, which detects overloads and short circuits, an AFCI is a breaker that utilizes advanced electronics to sense certain current waveform characteristics and logic to determine if tripping is necessary, which all sounds very similar to a relay.  Op-amps and transistors perform analog signal processing and a microcontroller performs logic. The end goal of an AFCI is definitive detection of a hazardous arc condition of two types, parallel and series, resulting in breaker tripping.  In the parallel type, an arc will travel from line to line, line to neutral or line to ground and the amount of current available is dependent upon the power source.  In a series type, the arc occurs within the conductor itself and the amount of current available is limited to the load on the circuit.  An example would be a conductor that has pulled apart or a loose connection at a receptacle.  Parallel is the more serious of the two arc types.

     The key to detection of these two arc types is the ability to tell the difference between a normal and a dangerous arc condition.  A normal arc condition would be that of a motor in an electric drill. Arcing that takes place in a drill is established and extinguished at a rate relevant to the revolutions per minute of the drill.  The internal arcing does not have a direct correlation to the AC source, since the arc breaks at each gap in the stator. The electronics of the AFCI detects this normal condition when it compares the periodic function of the current waveform to the voltage waveform.  In a dangerous arc condition, severe broadband noise is generated that can range between tens of kilohertz to 1 gigahertz and exists only during the conduction of current.  The AFCI looks for certain waveform characteristics, such as DC offset and zero crossing behavior, that typically exist whenever noise is being generated to the atmosphere.

     AFCI's resemble Ground Fault Circuit Interrupters (GFCI) in that they both have a test button, but they differ in functionality.  GFCI's protect against electric shock, whereas AFCI's protect against the threat of structure fires, caused by electric hazard. A GFCI detects leakage current, whereas an AFCI detects an abnormal current waveform, by looking for certain characteristics that are indicative of an arc hazard.  AFCI's are of similar shape and construction to a normal circuit breaker and can easily be installed in the home circuit breaker panel, but will have a yellow "AFCI" label and a test button next to the switch.

     Currently, AFCI protection of branch circuit wiring in dwelling unit bedrooms is required on new installation per NEC Code 210.12.  The NEC Code panel wants the industry to gain experience with these devices in bedroom circuits so that in the future their usage might be expanded to other rooms and facilities that could benefit by the added protection they provide.

     Article by Dan Scrobe III

What is Commissioning?

    "Apollo 13 Flight Controllers.  Listen up!  Give me a go / no-go for launch..."  Gene Kranz, Apollo Flight Director, Space Center Houston.  When watching Ed Harris play this role in Ron Howard's 1995 movie, you get a clear sense that commissioning substation equipment into service for the first time is strikingly similar to the many verification steps that Kranz had to make on all systems and to the green light he gave to launch control at the Kennedy Space Center on April 11, 1970.  Dr. Allen Morinec, who teaches electrical engineering at Cleveland State, used this analogy to rally a group of engineers at First Energy's MonPower center in Fairmont WV, to appreciate the importance of the commissioning process, which uses methodical and calculated steps to catch and correct any mistakes before releasing for normal service all new substation equipment on the electric grid, such as circuit breakers, capacitors and transformers.

     "Go!" Booster Systems Engineer.  This person was responsible for all propulsion matters during prelaunch and ascent.  The power to make something move could be compared to the DC power in substations, that is required for conversion to the immediate, on-demand, mechanical energy that is necessary to move the large contacts of circuit breakers to an open or close position.  All substations have rows of wet cell batteries that provide the high DC currents required for these breaker operations.

     "Go!" Network Officer.  This person was responsible for supervising the network of ground stations that relayed telemetry and communications from the spacecraft to Space Center Houston's flight officers.  This can easily be compared to a substation's RTU (Remote Terminal Unit), which is an onsite computer that sends information back to transmission control centers in Ohio and West Virginia in order for operators there to analyze what the grid voltage is and the power that is flowing thru there.  This is necessary to help maintain system reliability.  Just as Houston had to communicate to flight commanders, James Lovell, John Swigert and Fred Haise, transmission operators sometimes have to communicate to substation equipment and command a breaker to open or close, for the purpose of redirecting power flow, isolating faulted equipment or protecting human life/equipment from harm/damage.

     "We're go, Flight!" Electrical, Environmental and Consumables Manager.  This person was responsible for support systems in the spacecraft such as cabin cooling, vehicle lighting and cryogenic monitoring for the fuel cells.  These support systems are easily compared to a substation's station service, which provides low voltage power to heating and cooling systems, relaying and control mechanisms.

     "3, 2, 1...ignition!" Kennedy Space Center.  You will notice in the movie that at any time before ignition, Kranz had the ability to abort the launch.  It was his job that all checks were verified leading up to that beginning moment of the mission and to stop the mission if there was anything that was wrong.

     "We have liftoff!" Kennedy Space Center.  As Apollo 13 ascends in the movie clip we are shown, Dr. Morinec so enthusiastically boasts, "I commissioning engineer release this equipment for normal service!"  The analogy is successfully made to demonstrate all that goes into the steps leading up to the beginning of a mission.  It is also a time of documentation to provide a snapshot of history to show to future technicians, operators and engineers how a piece of equipment was put into service with perfection.  For Apollo 13, its mission was very short indeed, but for substation equipment, its mission will hopefully last 20-30 years of providing electrical service to customers.

     Article by Dan Scrobe III