Designing medium-voltage genset systems
Good working knowledge of medium-voltage applications is essential in making a smooth transition from low-voltage system experience to successful medium-voltage system design.
On-site generators have become commonplace in the market for both code-required and optional-standby applications. Although many consulting engineers, contractors, and suppliers participate in these generator projects, the majority of the collective experience is in the low-voltage class. There are fewer participants in the medium-voltage world. And even then, a good general knowledge of medium-voltage generator systems tends to be incomplete. The goal of this article is to help build a common level of understanding about components and system design considerations that market participants can build on when working on medium-voltage projects.
Depending on your perspective and what standards are being referenced, the definitions of low, medium, and high voltage can vary significantly. National Electrical Code definitions and perspectives are different from ANSI/IEEE. From a practical standpoint of power distribution, low voltage is considered ≤ 600 Vac, placing medium voltage greater than 600 V. A common electric machine voltage tends to be 4,160 V. This voltage becomes very prevalent in industrial environments as motor horsepower exceeds 500. It is common to find medium-voltage motors ranging from 2,400 to 6,900 V. Some of the classical definitions of medium voltage extend to 35 kV, or even 69 kV. This operational range makes sense from a utility/transformer perspective, but not necessarily from an on-site generator perspective. It is common for alternator manufacturers to reference alternators in the 5 kV class (2,400, 4,160, and 6,900 V) as medium voltage and alternators in the 15 kV (12.47, 13.2, and 13.8 kV) class as high voltage-though from the broader sense, both classes are in the medium-voltage category.
The transition from low-voltage to medium-voltage on-site generation is influenced by a mix of economic and system design considerations: cabling distance, genset, and switchgear costs; and bus capacity, fault-current capacity, and utility interconnection/integration configurations.
As applications have loads that are physically located farther apart, the installation costs of low-voltage cabling becomes a significant constraint. For campus-environment projects with an incoming medium-voltage utility service, it is often desirable to consider moving to a medium-voltage central plant configuration. In this configuration, the entire campus can be backed up with a medium-voltage transfer pair (two circuit breakers). With this approach, a medium-voltage power plant can provide redundant parallel generation capacity to all of the step-down transformers on the campus. This central plant approach must be compared and contrasted with tying in multiple generators around the campus on the low-voltage sides of the transformers. Historically, this approach was more common when the low-voltage loads didn't require the reliability of redundant generation. This distributed approach also provided more choice in which loads would receive backup power and which would be excluded. With various manufacturers offering integrated paralleling generator options, the low-voltage tie-in approach is being considered on more mission critical applications. Pods of low-voltage, paralleled generators also offer the advantage of providing protection from utility step-down transformer failures (see Figure 1).
Generator cost is another limiting factor in the decision to transition to medium voltage. Within the market, transitioning a 480-V, 2-MW generator into a 15 kV unit tends to be a $100,000 adder, while the added cost of making the same transition to 4,160 V is typically around $40,000. These genset cost adders must be compared to the cost of installing a pad-mounted transformer at each generator. At 4,160 V, the alternator configuration is fairly common because the costs are similar. At 15 kV, many system designers consider implementing a step-up transformer configuration to achieve cost savings. Also, when implementing medium-voltage solutions, some utility services are 23 kV. This voltage requires on-site generators to be transformed-the highest nominal alternator voltage is typically 13.8 kV. When exploring transformer-based solutions, considering 600 V generators may offer some cost savings by reducing ampacity on the low-voltage side.
Another area of significant cost is medium-voltage metal-clad switchgear (ANSI/IEEE C37.20.2) necessary for paralleling medium-voltage generators or creating transfer pairs with the serving utility. This equipment, with its associated vacuum breakers, protective relays, and instrument transformers, typically costs $50,000 to $60,000 per section, while a typical section contains only a single breaker. When comparing to low-voltage solutions, transfer and paralleling equipment is generally twice the cost.
As a result of this increased cost to parallel at medium voltage, some designs might benefit from a combination low-voltage/high-voltage strategy. Instead of using medium-voltage alternators and paralleling with medium-voltage gear, it is possible to configure a system in which the paralleling occurs on the low-voltage side of step-up transformers. This configuration could be implemented with single- or multiple-transformer configurations. An effective alternative choice for medium-voltage applications less than 2 MW is to implement on-generator low-voltage paralleling functionality, terminating at the low-voltage side of a step-up transformer. For medium-voltage applications less than 6 to 8 MW, using multiple step-up transformers with the medium-voltage sides terminated together at the switchgear also creates an effective alternative. In this second configuration, the generators see generator-to-bus voltage on the low-voltage side of the transformer, allowing for on-generator low-voltage paralleling. Although these options create cost-effective alternatives, they do not provide redundancy for a failed transformer. Consequently, these approaches require greater system-level scrutiny when mission criticality is valued above the offsetting cost advantages.
System design considerations
Bus capacity and fault current tend to be major determinants in the transition from low-voltage to medium-voltage systems. Standard bus configurations typically extend to 6,000 A. Larger busses can be specially engineered, although the costs tend to spiral. Fortunately, on-site generation can extend this bus capacity by double ending: bringing generator capacity in from each end and placing the distribution feeder breakers in the middle. This functionally increases this bus limit to 12,000 A. The other limit that tends to appear around the same point is the fault current rating of the paralleling and distribution gear. When the system fault current exceeds 100 kA, the costs to move to 150- or 200-kA breakers and gear may be economically limiting. Assuming an alternator subtransient reactance of 12%, the 100 kA limit occurs at the same 12,000 A as the bus limit. For 480-V equipment, these limits are converging at 8,000 kW. This tends to be the strong transition point to move to medium voltage or split the low-voltage generator bus into two separate systems.
Medium-voltage systems often use medium-voltage alternators. Medium-voltage alternators are conceptually the same as low-voltage alternators. They have a main rotating field (main rotor), exciter, and permanent magnet generator that are basically identical to their low-voltage siblings. They differ in the construction relative to the alternator's armature (main stator). In low-voltage alternators, the main stator is typically a random-wound machine. This construction uses standard electrical machine insulated copper windings. The construction is called "random wound" because the wires within the stator slots and on the end turns can randomly lay next to another wire that is many turns farther down in the phase coil. This isn't an issue because the insulation is easily rated for the maximum voltage potential.
In medium-voltage alternators, many more coil turns are used in the main stator, which increases the voltage with each turn. The resulting voltage potential would be greater than an individual wire's insulation could withstand if randomly wound. For this reason, the construction is converted to form coil (see Figure 2). The round wire is replaced with square wire and the wire is precision wrapped to allow the wire to touch only the coil turns above and below it. This controls the voltage potential between turns. The coil is then wrapped with special varnish-compatible insulating tape to insulate the high-potential coil winding from the ground-potential of the stator core. As a rule of thumb, one wrap of tape is needed for each 1,000 V. That is part of the reason why the 15-kV class alternators cost so much more than 5-kV models. The entire stator assembly is varnished using a vacuum pressure impregnation process, which removes the air entrained in the insulating tape and then pressurizes the varnish into the tape. This varnish process is a must for form coil construction but offers little to no advantage when applied to low-voltage random-wound alternators that don't use insulating tape.
Medium-voltage (5 and 15-kV class) alternators are typically available in certain power ranges. Alternators in the 5-kV class are available as small as 500 kW but are typically implemented at ≥ 1,000 kW. Alternators in the 15-kV class typically aren't available below 1,000 kW with the usual implementation at ≥ 2,000 kW. Both classes typically come standard with winding resistive temperature detectors (RTDs). RTDs provide a means of monitoring temperature within the alternator and protecting it from heating effects due to restricted airflow, phase imbalance, or harmonics. RTDs operate too slowly to be used to provide short-circuit protection. Bearing RTDs are also typically implemented on 15-kV class machines to allow preemptive shutdown. Due to the target market and physical size of the insulation, 15-kV alternators are typically implemented in large frames (1,000-mm stator laminations). This larger frame causes the alternator's rotor weight to become too heavy for the engine's rear bearing. As a result, many 15-kV alternators are implemented in a two-bearing closed-coupled configuration. The second bearing carries the rotor weight and the closed coupling creates easy alignment to the engine flywheel housing.
Medium-voltage alternators are configured for busbar cabling with the switching and protection located within the metal clad switchgear. Gensets usually include potential transformers (PTs) that step down the main output voltage to typically 120 V for instrumentation and control. The genset requires this PT input for the voltage regulator to control the alternator voltage and the over/under voltage protection within the genset controller. The generator also includes medium-voltage current transformers (CTs) for monitoring and for overcurrent protection. The CTs are also used to calculate kW, KVAR, and kVA. This information is used for monitoring, protection, and control to accommodate on-generator synchronizing and load sharing functionality.
Current transformers are also often used on the neutral side of the alternator phase coils to provide a zone of protection, which is implemented by a protective relay located in the switchgear. Because the vacuum breakers don't use integrated overcurrent trip units, this function is implemented by a multifunction protective relay. One of the functions typically implemented is differential protection (ANSI device 87, from ANSI /IEEE Standard C37.2 Standard for Electrical Power System Device Function Numbers, Acronyms, and Contact Designations). This function monitors the current flow between two CTs located at different points within a current path. If the current isn't the same, the path has faulted. This is typically implemented from the high side of the vacuum breaker in the switchgear to the low side of the alternator, resulting in an extremely high level of protection for all equipment between the two CTs.
Medium-voltage systems are configured for 3-wire operation (no line-to-neutral loads). As a result, it is common to use low-resistance grounding and then monitor for ground faults with a CT at the resistive bond. This grounding method is typical for 15-kV systems and also used on some 5-kV systems. The grounding resistor is typically sized to limit ground fault current in the 100- to 400-A range. The resistor is sized by dividing the line-to-neutral voltage by the desired maximum ground-fault current. The protective relaying is commonly set at 10% of the maximum ground-fault current. This is done to protect the grounding resistor from the maximum continuous nontripped ground fault. It is common to set the protective relaying to trip in 10 to 30 sec.
For 5 kV systems, it is possible to use high-resistance grounding when the ground fault current is limited to 8 A (see Figure 3). Above this level, it is likely that the fault will escalate into a line-to-line fault. Systems operating in the 15-kV class typically have considerably higher capacitive charging currents that cause the ground fault currents to easily exceed 8 A. For this reason, high-resistance grounding is not recommended.
Protective relaying is a significant part of medium-voltage systems. Given the capabilities of today's multifunction protective relays, it makes sense to incorporate various functions: differential (ANSI device 87), synch check (ANSI device 25), overcurrent (ANSI devices 50/51), over/under voltage (ANSI devices 27/47), over/under frequency (ANSI device 81OU), and ground fault (ANSI device 51N). For applications that use a low-voltage generator coupled to a step-up transformer, it may be desirable to incorporate transformer differential protection (ANSI device 87T) to protect the entire zone between the high side of the vacuum breaker and the low side of the low-voltage generator. This function tends to be fairly specialized and may require an additional protective relay. For detailed design information on grounding and protection, consult the IEEE color book series.
All medium-voltage systems require medium-voltage metal-clad switchgear to tie everything together. A typical medium-voltage metal-clad switchgear lineup will use medium-voltage vacuum breakers along with the associated protective relaying (see Figure 4). It will also contain PTs for stepping down the medium voltage to typically 120 Vac for monitoring and protection. It will also usually contain control potential transformers (CPTs) for powering the closing of the vacuum breakers. Together the PTs and CPTs consume the entire upper section above the vacuum breaker. One strategy to compress the switchgear lineup and reduce cost is to switch the generator's breakers to dc close-and-charge functionality and use the PTs located on the generators for sensing. This will free up the upper section for another generator breaker. This approach functionally combines two side-by-side sections into a single dual-breaker stacked configuration. Finally, it is fairly common for metal clad switchgear lineups to incorporate lightning arrestors and surge capacitors for large generator systems, especially when incorporating 15-kV alternators. The use of these items on the utility source depends on the system topology. These items may have already been included with the utility service disconnect equipment.
As our country's dependency on electricity continues to grow, so does our need to design larger backup generation systems. Quite often, these larger systems are constrained by the physical limitations of low voltage, resulting in more engineers, contractors, and suppliers engaging in medium-voltage, parallel power generation projects. A good working knowledge of medium-voltage implementation is essential in making a smooth transition from your low-voltage experience to successful medium-voltage designs.
Michael Kirchner is technical support manager for Generac Power Systems, Waukesha, Wis., where he supports and trains on all industrial products. He has a BSEE and an MBA from the University of Wisconsin. He has been with Generac Power Systems since 1999.