OEM engineers who devise equipment that saves energy have it pretty good these days. They have the satisfaction of knowing that their work both saves their customers money and, on some level, helps the planet.
This is particularly true for engineers working on industrial projects that feature energy efficiency. Some utilities will give industrial customers financial incentives paying up to 70% of costs for efficiency projects (based on annual kilowatt-hour savings). Items covered under such policies typically include variable-speed drives (VSDs), controls, premium efficiency motors, and most other measures that can save electricity.
However, there is a catch. The utility expects to see verification of energy savings. Like all well-managed businesses, they (utilities) want to see the energy reductions before they cut checks. The end users, on the other hand, are looking at the bottom line (show me the money). While the concern is primarily energy savings, management looks at the big picture beyond energy savings. Upper managers typically want to make investments that increase productivity, reduce the costs of environmental compliance, lower production and waste-disposal costs, boost product quality and reliability, improve capacity, and make workers safer.
There is a benefit to this big picture methodology. In many cases, energy savings alone may be insufficient to justify a project. Though it should be understood that the primary objective is energy savings, management must look at what they are getting for the money. There are numerous cases where company management denied projects because the “energy specialist” failed to look beyond energy savings. And it is sometimes the case that the cost of downtime far outweighs the energy savings.
Centrifugal pumps are prime candidates for major energy savings, because their power use varies as the cube of the speed ratio (i.e., cut the speed in half and you reduce the power to one-eighth of the original value). They are the second most widely used type of mechanical equipment in the world, outnumbered only by the electric motor. The use of VSDs with centrifugal pumps, when properly applied, has a tremendous potential for cost and energy savings by reducing friction in the system.
In relative terms, pumps are efficient machines. Most typically operate near 75% efficiency (best efficiency point, or BEP). Because of this relatively high efficiency, it is easy to dismiss the potential energy savings available by optimizing pumping systems. But a pump is sensitive to how it is operated and it is the pumping system that has the greatest influence on pump energy use. Energy can account for as much as 75% of a pump’s total cost of ownership. A pump can be efficiently designed yet can be operated in an inefficient manner. As a result, many pumping systems operate at efficiencies far below their BEPs.
Centrifugal pumps should be selected and normally operated at or near the manufacturer’s design-rated conditions of head and flow. This is usually at the BEP. Pump-impeller vane angles and the size and shape of the internal liquid-flow passages are fixed and can only be designed for one point of optimum operation. For any other flow conditions, these angles and liquid channels are either too large or too small.
Any pump operated at excess capacity — that is, at a flow significantly greater than BEP and at a lower head — will surge and vibrate, creating potential bearing and shaft-seal problems while requiring excessive power. When pumps operate at reduced capacity, i.e., at a flow significantly less than BEP and at a higher head, the fixed vane angles will cause eddy flows within the impeller, casing, and between the wear rings. The radial thrust on the rotor will rise, causing higher shaft stresses, more shaft deflection, and potential bearing and mechanical-seal problems. There will also be more radial vibration and shaft axial movement. Continued operation in this mode will accelerate the deterioration of the mechanical and hydraulic performance and may ultimately make the pump fail.
Efficiency and reliability are complementary; the closer the pump operates to BEP the more reliable the unit. As the pump operating point moves away (to the right or left) from BEP, the efficiency and reliability drop off. While this sounds like a no-brainer approach, it is often bypassed when making a simple energy-savings analysis. The typical rationale for not using the more-detailed analysis: Poor historical documentation, lack of expertise/manpower, and lack of monitoring equipment or funds to incorporate these details.
Now consider the most common reasons for management denying funding for energy projects: Energy assessment lacks sufficient detail inaccurate estimates of potential cost savings and a failure to evaluate the entire system. The Catch 22 is that before one can apply for incentives/funding from the utility, state and/or local government, one must obtain management approval by developing a solid business case.
A real example
The following case study is an excellent example in which the big-picture methodology helped justify an energy project. The original well-water system was installed in May 1975 and comprised two separate installations. Both were critical to the plant operation. The loss of one pump diminished plant operations, and loss of both forced a production shutdown. The units in question were vertical six-stage turbine-style pumps coupled to 250-hp hollow-shaft motors. An eddy-current drive controlled pump speed.
The pumps developed a 310-ft head at about 1,700 gallons/min when operating at a base speed of 1,717 rpm. The system generally operated in the 1,200 to 1,700-rpm range. However, the pumps could run at a higher rpm under extreme conditions. The well pumps fed water into several areas of the plant.
The plant piping and instrumentation diagram showed that the well pumps sent water into a treatment facility. Upon entering the facility, the pressure was dropped to 25 psi via a pressure-reducing valve. Water then flowed to the clear-well, flush-water, and chlorination systems. Engineers verified the treatment plant only require a maximum of 25 psi through the 8-in. line feeding the plant.
The maintenance history on both well systems showed the pumping systems were considered “bad actors.” The pumps, along with the eddy-current drive and motor, experienced high vibration and frequent failures. Meantime-between-repair for the drive was just one year; for the pump, 2.5 years; and for the motor, 2.5 years.
The accompanying pump and system head versus flow curve displays calculated operating conditions at the three speed ranges defined by customer. The accompanying spreadsheet display breaks down the energy consumption and savings. Vertical columns indicate savings based on reduced friction, drive efficiency, and motor efficiency, respectively. All savings calculations were based on operating at specified points 33% of the time at 10 cents/kW/hr. Shown here are calculations for the 1,717-rpm case. There were similar spreadsheet calculations for the 1,500 and 1,200-rpm speeds. A point to note is that head loss across the pressure-reducing valve was deduced using an analog gage upstream and downstream of the valve.
The customer chose not to share the cost of downtime when the pump system was out of service. But the company did indicate the downtime substantially affected its bottom line and was the primary reason for evaluating the system. When looking at the total cost of maintenance for one pump system from installation (1975) to date, the company spent approximately $295,040. This is a staggering number considering that the pump should operate reliably for 15+ years between repair cycles.
The solution that addressed these problems was the replacement of the existing hollow motor with a solid-shaft premium-efficient design. Designers modified the pump shaft to accept a solid-shaft motor/coupling and provided detailed instructions for implementation. They also leveled the sole plate to insure the pump was plumb and level, and to eliminate pipe stress on the pump discharge per Hydraulic Institute Standards. A low-coefficient-of-friction polymer material replaced the existing cutlass rubber pump line shaft bearings. A PWM variable-frequency drive (VFD) replaced the old eddy-current drive, and designers installed feedback control to automatically modulate the system on demand (to reduce friction and improve process control).
All in all, the energy-assessment team identified not just energy savings. They also identified and documented additional benefits from reduced maintenance and downtime, improved reliability, and better productivity, to name a few.
On this particular project, a VFD modulated the pump flow. It is generally taken for granted that a VFD will provide energy savings. But there is no standard way to document the savings or prove you are getting the savings you expected. Ditto for the time it will take to see results of corrective action, and whether or not the system saves money in areas besides energy.
Industry is beginning to address the need for such proof with software tools. The Energy Dashboard is one such tool that provides this information. It also brings built-in knowledge, skills, and techniques for tracking and controlling energy consumption while improving, monitoring, and validating system reliability.
The Energy Dashboard gets its data from the Baldor SP Drive. It works with three transducers that monitor suction pressure, discharge pressure, and flow. It processes the necessary data and delivers it to a PC, laptop, DCS, or PLC via Ethernet. The information it supplies includes the pump-performance curve, system curve, pump efficiency, flow, head, calculated BHP, real-time voltage and current, energy-usage trends over months and years, and the cost per kilowatt/hour.