Mixed Hybrid Mechanical Drive Systems

Mixed or hybrid systems that integrate prime mover-driven equipment with electric motor-driven equipment are common in modern industrial operations. They provide standby for critical loads during an electric power outage and allow for operating costs to be optimized. The use of a dual-shaft drive allows either a prime mover or an electric motor to drive the same piece of equipment. The equipment can be sized for the power output of both the motor and the prime mover combined, or for either one separately. Some typical configurations are:

• Prime mover-driven units used during expensive peak electric rate periods and electric-driven units used during inexpensive off-peak electric periods. The prime mover-driven units may or may not be equipped with heat recovery.

• Prime-mover driven units sized for and operated to match thermal loads served through heat recovery. Units can be baseloaded or designed for thermal load following. In some cases, the prime-mover units will be operated in peak electric rate periods, even if potentially recoverable rejected heat exceeds the thermal load requirement and must be vented.

• Prime mover-driven units used for peak-shaving duty only. Electric units may be baseloaded and the prime mover-driven units used to meet additional peak load. For example, a plant with a critical 750 hp (560 kW)

air compressor load may install as many as four units of 250 hp (186 kW) each, including an extra unit for backup capacity. With an all-electric system, the facility may also install standby electric generation capacity to support one or more of the units in the event of an electrical outage. By installing one or more 250 hp (186 kW) prime mover-driven units, the required standby generation capacity can be eliminated, possibly offsetting some or all of the incremental capital cost of the prime mover system. Under each operating condition and rate period, the most economical combination of units can be operated. Use of the electric units would be maximized under lower cost off-peak electric rates and minimized during more costly peak rates.

Capital Cost Considerations

In relatively straightforward retrofit applications (e.g., pumps and fans), the cost of replacing a conventional induction motor will typically range from $40 to $50 per installed hp of motor capacity ($54 to $67 per kW). Power factor correction devices, starters, and other components may add as much as $10/hp ($13/kW) to the retrofit installation. In new installations, the cost may be double or triple that, depending on the cost of electrical and controls installation. Premium-efficiency induction motors will add from 20 to 30% to the installed cost and synchronous motors will add 70 to 100%. VFDs will add $100 to $180 per hp ($134 to $241 per kW), depending on electrical and controls requirements, with larger capacity motors being on the lower end of the cost range. The relatively low capital cost as compared with prime mover drives, along with installation logistics and maintenance cost advantages make VFDs the logical base case for many VSD applications, against which prime mover applications may be compared. For more complex applications (e.g., compressors), retrofit costs can be considerably higher and in some cases, will not be feasible, necessitating the purchase of an entirely new system. Additionally, for such applications, more complex controls and programming will commonly be required, adding additional costs to the overall project.

The capital cost premium for prime mover-driven mechanical systems versus the conventional electric motor base case typically ranges from $250 to $750 per hp ($335 to $1,000 per kW) of installed capacity. Back-pressure steam turbines are the least expensive prime mover alternatives, followed by moderate-speed reciprocating engines and condensing steam turbines (assuming a high-pressure steam system is already in place). At the high end of the range are gas turbines and low-speed reciprocating engines. For all systems, the cost premium per unit of capacity is less as system capacity is increased. The costs associated with gas, exhaust, and rejected heat piping for reciprocating engine- and gas turbine-driven units, or steam boiler plants and piping for steam turbine-driven units, may add to the premium. Except for very large steam turbine plants, it is generally considered cost-prohibitive to build or greatly modify a steam generation plant for the sole purpose of using steam turbines.

With cogeneration-cycle applications, heat recovery can add $50 to $200/hp ($67 to $200/kW) to the cost premium for a combustion engine drive. On the low end of this cost range are simple engine coolant heat recovery systems. On the high end are more complex systems, such as multiple-pressure HRSGs used with gas turbine drives. Significant additional costs may be incurred to interface heat recovery systems with existing thermal loads. This may involve long-pipe runs, the use of storage systems, or replacement of heat exchangers or downstream HVAC coils. It may even involve the conversion of an entire process to accommodate a lower temperature energy source.

When an existing facility does not have sufficient electric service capacity available, the cost of providing additional electric service to the facility can vary widely. Where service expansion is required, the required costs can often offset a portion of the capital cost differential between a prime mover-driven unit and an electric unit.

Another factor that sometimes comes into play is the need for standby electric generation capacity and uninterrupted power systems (UPS) to support critical equipment loads. In these cases, the combined cost of the electric service, standby generator, and UPS to support electric motor drives may be equal to, or even greater than, the cost of a prime mover-driven unit. In some cases, an electric generator may be mounted in line with mechanical equipment (e.g., air compressor or pump) on a single prime mover-driven system. This allows the prime mover to serve a dual function of providing emergency power to the facility for other loads in the event of a utility outage.

Beyond the drive technology application itself, many systems will require significant modification to enable beneficial variable speed/variable flow operation. For example, a variable speed/variable flow pumping application may require change-out of 3-way control valves to 2-way valves throughout the distribution system. In the case of boiler or chiller system, the application may require installation of additional pumps and piping to create a primary/secondary system that enables constant volume circulation through the boiler or chiller, with variable volume circulation throughout the distribution system. Hence, while the cost-premium for a VFD may be quite modest, the overall capital cost of the project can be substantial. Still, such applications may prove to be financially attractive.

After gathering the appropriate data and limiting the options and potential operating strategies down to a few, through the screening process, a detailed study may be performed. It is important to conduct such studies within the context of overall facility system optimization planning and, therefore, interactively consider other potentially cost-effective improvement options, as well as facility long-term goals and objectives. Refer to the various chapters in Section IX for detail discussions on performing integrated technical and financial project performance analyses and on project implementation.

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