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ESPThe Electrical Submersible PumpTable of contentsPart 1 What Is an Electrical submersible Pumping System and How Does It Work?Part 2 Operating Ranges and Limits of the ESP SystemPart 3 How the System is ProtectedPart 4 System DesignPart 5 Application of Electric Submersible Pumps in Hostile EnvironmentsPart 6 How the ESP Is Handled, Serviced, and InstalledPart 7 Applying Variable Frequency Drives to ESPs Part 1What Is an Electrical Submersible Pumping System And How Does It Work? This is the first part of a multipart series covering all aspects of the electrical submersible pump system. The six installments that follow this introductory article will cover the system’s operating range, the power system and its control, application in hostile well environments, sizing calculations, installation and service, and operating costs. The series of articles is designed to apply, in general, to all pumps, regardless of brand name.---The Editors The Electrical Submersible Pumping (ESP) system is an extremely viable method of artificial lift in today’s oil field. Significant advances in electrical submersible system design and manufacture have made it the most cost-effective means of lift under most pumping conditions. When compared with the beam-pumping unit, today’s electrical submersible pumping system offers greater efficiency lower cost per barrel, and a broader range of volumes from a wider range of depths. The electrical submersible pumping system operates submersed in the well fluid. It hangs from the production tubing, generally above the perforated zone. Downhole components are pump, motor, seal, and cable. A gas separator may be required, as well. Aboveground components are the motor controller or variable-speed-drive controller, transformer(s), and surface cable (Fig. 1). The system is simple and very efficient. Basically, it takes electrical power and converts it into mechanical power via the downhole motor. This mechanical power is coupled to the pump where it is converted to hydraulic power. The hydraulic power lifts the fluid to the .surface through the tubing. Let’s look at each of the components briefly.The Pump The centrifugal pump is made up of a number of pump stages . Each stage consists of an impeller connected to the drive shaft and a companion diffuser that directs the flow of the fluid from one stage to the next . The number of stages and their sizes are determined by the required lift and the desired volume. Sizes vary from less than 3l/2 in. to over 10 in. Depending on the number of stages, the length of a single Pump housing may range from 40 to 344 in. In some cases, the pump may be assembled from two, three, or even four housings connected together, so a pump may be over 75-ft long. The impeller and diffuser generally are made of Ni-Resist, a special steel alloy that resists corrosion. Synthetic materials are being developed for these components as well.The Motor Any pumping system needs a prime mover. And in the case of the submersible pump, that prime mover is a downhole motor. It is a three-phase, squirrel cage induction motor varying in power form 10 to 750 hp, at 60 Hz. Motor voltage requirements vary from 420 to 4,200 v at 60 Hz (350 to 3,500 v at 50 Hz). The motor diameter ranges from 3 3/4 to 7 1/4 in. The motor is capable of running continuously for very long periods of time, depending on well conditions and temperatures. Heat is carried away from the motor by the passing fluid that is being drawn into the pump. If this fluid velocity is less than l ft/sec, a shroud may be required around the motor. When a shroud is used, fluid velocity is being drawn into the pump. If this fluid velocity is less than 1 ft/sec, a shroud may be required around the motor. When a shroud is used , fluid is used, fluid is drawn beneath, past the motor at a higher velocity thereby establishing adequate heat transfer.The Seal Section( or Protector) For the motor to run continuously, it must also be protected from well fluids, which deteriorate motor insulation strength. The seal section performs this and other functions. It equalizes pressure between the well annulus and the motor. If external well pressure is higher than internal pressure, fluids may be forced into the motor. The seal section also allows for expansion of the high dielectric motor oil. Expansion results from heat rise in the motor. Finally, the seal section contains a thrust bearing that carries pump thrust resulting from pump discharge pressure exerted across the pump shaft diameter. If well fluid contaminates the motor oil, the motor may fail. So, the seal section is usually made of several chambers that can progressively protect the motor if a prior mechanical face seal fails In the most effective seal section design, an elastomer barrier is used in the uppermost chamber that not only seals, but also accommodates the expansion and contraction of the motor oil. In this style, a second and third chamber protects the motor if the elastomer barrier fails.The Electrical Submersible Cable Of course, electrical current must be supplied to the downhole motor to drive the pump. The electrical cable that carries this current must therefore be capable of operating submersed in fluids that may be at a high temperature and pressure, and also deliver maximum current with minimum loss. In some wells, it must be able to resist corrosive forces and gas. The cable is banded to the tubing for support. It may be spliced. Cable is available in a wide range of round and flat configurations, with a variety of conductor sizes. Several types of armor and insulation are available for protection against corrosive fluids and severe environments. Selection is based primarily on fluid conditions, bottom hole temperature, and space limitations. Cable length also influences selection. The Gas Separator Many wells produce a significant amount of gas that can cause the pump to cycle, reducing operating efficiency. The volume of free gas ingested by the centrifugal pump can be minimized by increasing the submergence pressure at the pump intake or by installing a gas separator to remove free gas prior to the pump intake.Conventional gas separators draw the well fluid in and sharply reverse its flow. Free gas is separated and the liquid goes to the pump intake. The method is only significantly effective for free gas ratios below 10% by total volume. A more effective method is available in a rotary gas separator. It can remove up to 90% of the free gas dependent on well conditions, even with high gas-oil ratios. The rotary gas separator consists of an inducer and a pump stage followed by a centrifugal separator chamber. The inducer and pump stage provide a means to overcome flow resistance through the separator and vent passages. The separator chamber is a closed rotating unit that works like a centrifuge. Heavier fluids accumulate near the outer wall and free gas collects around the shaft area. A crossover diffuser channel the heavier liquids to the first pump stage and vents the much lighter gases to the casing annulus (Fig. 2). Above ground, the ESP system requires a wellhead that accepts the cable, a motor controller or variable speed controller, transformers, and surface cable. These components are fairly conventional, except for the controller.The Motor ControllerThe motor controller serves three primary functions. First, it houses the power contactor that energizes or de-energizes the submersible motor. Second, it senses motor overload, well pump-off single phase conditions, and unbalanced voltage. Third, it provides startup and shutdown with auxiliary control devices, such as pressure switches, tank levels, and remote commands. The standard motor controller operates at 60 Hz (50 Hz, outside the U.S.). Controller selection is based on voltage, current, and horsepower ratings. Conventional electromechanical and solid-state controllers are available (Fig. 4). The solid-state controller continuously monitors the motor for dangerous over currents, unbalanced currents, or well pump-off conditions. Digital logic circuitry permits greater accuracy, control, and reliability, as well as reduced maintenance. The latest development in motor controllers is the variable speed controller. With the conventional motor controller the submersible pump is a fixed-speed, fixed-rate pump. The variable speed controller converts it into a variable-speed, variable-rate pump by altering the frequency anywhere from 30 to 90 Hz. As the rpm changes, the fluid volume lifted changes. At higher frequencies, the speed is higher, and volume is higher. At lower frequencies, volumes are lower. This development is particularly valuable in wells that undergo changes in volume, pressure, GORs, or water cut or in wells where productivity is not accurately known. The variable speed controller lets the operator fine tune his production to fit changing conditions. The variable speed controller also extends the operating range of the submersible pump to include lower and higher volumes than before. Plus, it provides a whole array of other features that improve submersible pump performance.The Transformer The transformer changes the voltage level from the distribution value to the level required by the submersible system and the surface voltage and current. The rated motor voltages, plus the voltage loss in the downhole cable, determine surface voltage. A bank of three single-phase transformers or one three-phase transformer is necessary to supply the required voltage. If the variable speed controller is used, an additional transformer is required between the controller and the submersible components.SERIES TO BE CONTINUED. The next installment of this series will discuss the operating range of electrical submersible pumping systems. Part 2Operating Ranges and Limits of the ESP System The electrical submersible pumping system (ESP) operates over a wide range of depths and volumes. The maximum depth is approximately 12,000 ft (3,660 m) and maximum flow rate is l,300 gpm (82 liters/sec). There are however, limiting factors that restrict the system from performing at these maximums. This article discusses each limiting factor and its effect on the ESP. The limiting factors are: free gas, temperature, viscosity, emulsion, pump depth, and sand and paraffin.Effect of Free Gas An excessive volume of gas, ingested at the pump intake, influences pump operation in several ways:  The pressure-head capacity performance curve deteriorates to a point below that calculated for the bulk density of the liquid-gas mixture. The curve deteriorates because the fluid is compressible and reduces the centrifugal pump's efficiency.  The excessive gas presence creates an area of unstable head (pressure surges) for capacities at or less than optimum design now rate for that particular stage. This characteristic is more pronounced in radial stages than in mixed-now stages.  For capacities higher than the optimum design flow rate, cavitations occur. A large decline in pressure or head, for a given flow, is evidence of cavitations. Mild or very short-term gas interference also causes fluctuations in motor load. Fluctuations are indicated by current fluctuations on the motor ammeter chart. Severe gas interference produces large fluctuations that shut down the unit. The resulting intermittent operation reduces run life and reliability of the entire 2 o pumping system. When designing the ESP it is important to know the amount of free gas the pump can tolerate and compare this to the downhole gas conditions. Viscous fluids containing small bubbles may act as a homogeneous fluid up to higher values of percent-by-volume of gas present. In general, the amount of gas ingested should be kept to a maximum of l5% by total volume to minimize gas interference. (Practical experience in each local area is the best indicator of percent-by-volume allowable) Finally consider the effect of gas on the electrical submersible cable. Excessive gas absorbed by the insulation can cause rupturing when the ESP is pulled .The proper cable can minimize this problem.Influence of Temperature Heat limits the operating range of the electrical submersible pumping system. Each component in the system has different temperature limitations that must be considered in submersible system design. The motor can be made to operate reliably in temperatures to 325F (163C). The limiting factors are:  Thrust bearing - maximum temperature is 325 F (l63 C) Epoxy - (encapsulates motor windings) maximum temperature is 400F (204C). Insulation - maximum temperature is 500F (260C). Elastomers - (used in O-rings, thrust washers, and motor connectors) maximum temperature is 400 F (204 C) The seal section also has temperature limitations. An adjustment must be made, in some cases, for the two types of seal sections available, the first degree of water cut, due to its effect on total fluid contains an elastomer bladder and mechanical seals. Current elastomers used in the bladder will withstand continuous temperatures to 275F (l35 C). The second type contains only mechanical seals and may be operated at temperatures above 325 F (163 C). The second type contains only mechanical seals and may be operated at temperatures above 324F (163 C). Electrical submersible cable is limited by temperature restrictions of the insulating material. Standard insulating, such as polynitrile or polypropylene, with stand temperature to about 200 F (93 C). Above this temperature, the polynitrile becomes brittle and the polypropylene softens. Conductors tend to migrate together and short circuit.Special cables are now available for temperature limitations are dictated by the burst pressure of the applications up to 400 F (204 C). However, in wells with housing material, the horsepower required to lift the temperatures above 300F (149C), corrosive forces and gas can combine with temperature to cause premature failure. Viscosity Must Be Considered Viscous liquids also influence design of the electrical submersible pumping system. Liquids with higher viscosity increase brake horsepower and decrease head and flow. The sample performance curve (Fig. l) demonstrates how the centrifugal pump stage performance is affected. There is no established limit to the viscosity of a pump able fluid. The limiting factors are the increasing number of stages and motor horsepower required with increasing viscosity. The well’s and amount of gas suspended in the fluid also must be considered when determining the maximum allowable viscosity for any one installation.How To Design For Emulsions Another limiting factor is the type of water-oil emulsion to be lifted. Very little is known about the topic, and its effects are usually evaluated by trial and error. An adjustment must be made, in some cases, for the degree of water cut, due to its effect cut, due to its effect on total fluid viscosity. The curve in Fig. 2 has been used in California with success. It provides a correction factor, determined by the water cut, that is applied to the fluid viscosity. For example, assume a pump stage pumps fluid with a viscosity of 200 SSU, at a 40% water cut. The viscosity correction factor would be 3.3. The performance of this stage would be evaluated for 660 SSU (3.3 x 200 SSU), so the pump would require more stages and a larger motor.Pumping From Depth There are specific depth limitations to the ESP, depending 0n the size of the equipment used. The limitations are dictated by the burst pressure of the housing material, the horsepower required to lift the fluid to the surface, and thrust bearing load. The burst pressure for the submersible components vary according to diameter: 400 series is limited to 5,023 psi or l1,586 ft; 513 series is limited to 4,073 psi or 11,471 ft; 675 series is limited to 2, 681 psi or 6, 184 ft; and 875 series is limited to 4,320 psi or 9,966 ft. The thrust bearing in the seal section also is limited to the amount 0f pressure it can withstand. The 400 series seal section has a maximum depth-pressure limitation of 9,052 ft or 3,925 psi. The 5l3 series seal section can be assembled with either a fixed or pivot type shoe bearing. J The fixed shoe bearing has a depth-pressure limitation of 9,993 ft or 4,326 psi. The pivot shoe limitation is l5,989 ft or 6,930 psi- The 675 series seal section is limited by the motor horsepower, rather than any thrust bearing limitations. NOTE: The above depth limitations are expressed in dynamic head, based 0n a specific gravity of 1.0. The amount of fluid maintained above the pump intake must therefore be considered when calculating the maximum pump setting depth.Sand and Paraffin Sand and paraffin, suspended in the fluid, also can limit the operating range of the ESP but there is no dependable way to measure their effects on performance. The flow rate and size of both sand and paraffin must be considered when determining the handling capability of the particular pumping system. The smaller pump sizes, with pancake-type passages, tend to plug easier than larger sizes. To minimize the effects in very sandy wells, bring the flow rate up slowly by choking off the pump during startup. The best indicator is experience in the particular area of installation.What It Means It is important to evaluate the impact of each of these factors in designing the electrical submersible pumping system- Developments, like the new variable speed controllers, new cable materials, and gas separators, can help handle some of these limiting factors more easily. As these developments are used more, and further pumping advancements are achieved, the operating range of the electrical submersible pumping system will extend to virtually any artificial lift situation. Part 3How the System is protected The basic protection for the electrical submersible pump motor is the motor controller assembly (or switchboard). The standard motor controller is an operating, controller, and protective device. It consists of a motor starter, overload and underload protection circuitry, a manual disconnect switch, time delay, and a recording ammeter. Bottom hole pressure and temperature monitoring equipment also may be installed within the motor controller cabinet. Fuses are provided for short circuit protection. The short accelerating time for a slim, two-pole submersible motor when installed in a well is typically less than 1/2 sec. The fuse and overload relay protection must be fast enough to provide protection to the downhole equipment. Fuses are either installed internally or on the feeder circuit board. Generally, the fuses should be of the lowest rating that will allow the motor to start. External control devices should be interfaced with the controller as recommended or approved by the pump manufacturer to give the best and most trouble- free operation. All external control devices are connected to a time-delay, which activates or deactivates the controller after a predetermined interval. Usual external control devices are tank Hi-Lo level controls or line pressure switches. These external control de- vices are generally classified as two- or three-wire inputs.Solid State Controllers The solid-state controller is a significant advancement over conventional electromechanical relay controllers. The solid-state controller continuously monitors all three phases and detects overcurrent and undercurrent line conditions. It detects line problems more accurately and reacts to them more swiftly than conventional relays. If an overcurrent condition occurs, the controller decides whether to let the system continue operating or to shut it down. It distinguishes between temporary and catastrophic overcurrent conditions. Should the temporary overcurrent continue, the solid-state controller would shut the unit down after a predetermined period of time. If an undercurrent condition is detected, the solid-state controller will turn the unit off for a predetermined interval, after which it will attempt to automatically restart the pumping system. However, should the undercurrent condition remain, the unit will recycle until the amperage returns to normal. The solid-state controller also protects against single phasing or voltage imbalance- It is free of maintenance problems associated with sand and dust, and helps to reduce the number of field service calls due to environmental conditions. The recording ammeter is an important instrument because it provides a continuous recording of the amperage being drawn by the motor. The graph provided by the recording ammeter can be used to determine pumping conditions. Although the exact power conditions may not be determined from the recorder chart, the readings give immediate indications of problems or abnormal operation. Valuable reservoir and pump performance data are available with the use of downhole pressure monitors. By correlating the reservoir pressure with the production rate, the operator can determine the need to change pump size, change injection rate, or consider well work-over. Variable Speed Controller An alternative to the use of the standard motor controller is the variable speed controller (Fig. 4), which functions not only as a motor controller, but as a speed changer. To understand how the variable speed controller (VSC) operates, we should first discuss the basics of how the VSC supplies variable voltage and frequency for speed control. A VSC is connected to a 480 or 690-V, three-phase power source. This voltage is fed through a breaker, through three input fuses that provide protection to the silicone control rectifier (SCR), to the converter section. This section converts the incoming three-phase AC voltage into DC voltage. The converter is essentially a three-phase, full wave rectifier with SCRs in the bridge. The SCR is the same type of device used in light dimmers in homes. It has the ability to block all current in one direction (as a diode) but it can be triggered or short circuited in the opposite direction by applying a signal to its gate leads. Therefore, if we apply a signal to the gate lead just as the forward AC voltage cycle is beginning, we will develop full voltage on the DC bus. If the gate signal is applied halfway through the incoming voltage wave, we will have half voltage in the DC bus. It is by this control of these gating signals that we can control the DC bus voltage from zero to full value. The incoming three-phase has now been converted to DC. This DC voltage then is smoothed by a large L-C filter. This is a series inductor used in conjunction with parallel capacitors. The inductor inhibits current surges while the capacitors inhibit voltage surges. The final part of a VSC consists of three inverter sections for converting the DC voltage back to AC voltage. Each inverter section represents an output phase that contains two SCRs (here used as electronic switches)- The SCRs are connected in series across the DC bus. The output phase is derived from the center point between these two SCRs. We can control when the SCR is turned on by applying a signal to its gate. Simply turn on and of f the SCR at the appropriate time to apply plus or minus voltage to the phase approximating a sine wave. We now have frequency control by controlling the rate at which we turn on and off the SCRs. The control circuits of a VSC must be able to respond very quickly. At an output frequency of 800 Hz, an output SCR must turn on and of f approximately every two-thousandths of a second (2 milliseconds). The system is controlled by a microprocessor capable of executing an instruction every 2 microseconds (two-millionths of a second). To affect this control the computer monitors all three input and output current phases. the DC bus, and all operator inputs.Motor Control Functions The VSC and the standard motor controller both utilize an input disconnect circuit breaker and fuses - These devices are used for protection of the VSC and the motor. As mentioned earlier, a VSC monitors the input voltage. The VSC's computer is looking for low voltage, single phase, and phase reversal so the controller can supply the correct AC voltage to the ~; motor- A VSC will shut down if the correct output voltage cannot be maintained because of poor input voltage. It should be pointed out that problems with the input voltage such as voltage imbalance do not appear on the output side because of the intermediate. Conversion to and from DC incorrect phase rotation is electronically eliminated by the VSC. Variable speed controllers monitor DC 'amps and volts and detect overloads, underloads, and voltage transients. The Protection from voltage transients is not a function of a conventional controller. As pointed out earlier, the DC bus is isolated from the incoming AC line by a large L-C circuit. This makes passage of a voltage transient to the motor highly unlikely. However, the DC bus voltage is monitored, and should an abnormally high voltage begin to appear, the converter would be turned off Overload and underload conditions are determined by comparing the DC amperage level with operators adjusted level. Using the DC amperage to determine these levels has a distinct advantage over using AC amperage. The DC current is proportional to the real component of the AC current. That is, the reactive amps of the motor are not represented in the DC amperage signal- Since the vectorial sum of these currents is not used, underload or overload conditions are usually much easier to detect. If an overload condition were detected, a VSC would respond by lowering the frequency and therefore reducing the pumping rate. In reality, such a condition is never allowed to occur. A VSC simply reduces the unit's speed to compensate for a potential overload. If a VSC reduces the speed by more than l5% -for 60 sec or more, it will shut down and indicate an overload. Since this is not an emergency condition (amps and volts are under control, the shutdown will be controlled. Controlled shutdown will be discussed later. Should an underload be detected, a VSC's computer will shut the motor down after the time on the under- load's bypass timer has expired. This adjustable timer allows the well to f recover from an underload condition. one-half of the pr determined by pass timer setting must elapse before the VSC's computer will attempt to restart the unit- Should the underload condition persist through the bypass timer's interval, the VSC will shut down on underload and once again begin the sequence. Finally, a VSC monitors output volts and amps in all three phases. The output voltage is compared to the DC bus to verify proper inverter operation. The current is monitored for an instantaneous over-current trip (IOT) condition. An IOT would occur in situations such as a fault-to-ground or a line-to-line fault. In these conditions a VSC will be turned off immediately. VSC has the ability to soft Start the submersible pumping unit at approximately l0 Hz and a proportionally low voltage. The voltage actually begins from o v, so should a fault exist, no more than full load amperage would be fed to the motor before shutdown. This, type of soft start generally has the ability to produce full torque at reduced current (l50% nameplate or less). The controlled stop works in just the reverse. It slows the motor to 10 Hz speed before turning off The soft start and controlled stop reduce electrical and mechanical stress on the downhole equipment. In addition to handling all standard control features, a VSC's primary feature is its ability to vary the speed at which the pump operates. By changing the pump speed, the operator can adjust the amount of fluid being produced from the well. The production rates can be increased or decreased to track the well's production rate through its changing life cycle. This ability to trackThe well's performance capabilities allow the producer to operate the well at its maximum efficiency rate.Bibliography"An Automatic Pump Off Controller for the VSSP, paper SPE 9215."A Variable Speed Submersible Pumping System, paper SPE 8241. Part 4System DesignWhen choosing an ESP system, as with any artificial lifting system, reliable information about the well’s productivity an physical characteristics is vital to design a system which provides the maximum lifting potential possible. Designing an efficient electrical submersible pumping system is not a complicated procedure. The first step is to gather all the basic data needed to assure efficient operation. This includes physical characteristics of the well, its potential productivity, fluid characteristics, available electrical power, and any potential problems. Gather or accurately estimate the following information: Well data: Casing size and weight; tubing size, type, and thread; perforated interval or open-hole interval; and pump setting depth. Production data: Wellhead discharge pressure, present producing rate, producing fluid level or pump intake pressure, static fluid level or static bottomhole pressure, bottomhole temperature, gas-oil ratio, and water cut. Well fluid conditions: Specific gravity of fluid, bubble point pressure of gas, if any, viscosity of oil, and gravity of gas. I Power sources: Available primary voltage, frequency and power source capabilities Possible problems: Sand, deposition, corrosion, paraffin, emulsion, gas, and temperature.To clarify, a step-by-step designing procedure using a hypothetical well situation is Presented in this article. Design Procedure The information in Table 1 will be used for the example problem. The second step in the procedure is to determine the potential productivity of the well at the required pump intake pressure. For this procedure the IRP technique, first used by W.E. Gibert 1 and further developed by J.W. Vogel2, will be used. Maximum production is determined using the following relationship:Substituting data from Table 1, we get,TABLE 1, Assumed data or example problemQo (present producing rate Pwf (present producing pressure) Pr (Static reservoir pressure)Sitting depth Tubing size Casing size and weightWellhead pressure Water cutWater specific gravity0i1 APIRequired pump intake pressure Primary voltageTemperature Perforated interval Specific gravity of liquid 773 b/d1,200 psi2,000 psi5,000 ft23/8 in5 1/2, in., 17 lb/ft75 psi70%1 .0227˙200 psi7,200 to 12,470150 F5,050-5,00 0ft0.982Calculating the production with a required pump intake pressure of 200 psi, According to the inflow performance relationship (IPR) calculations, the maximum production for this well is 1,305 b/d if the well bore pressure were reduced to zero psi. It also shows that maintaining a pump intake pressure of 200 psi results in a production rate of 1,268 b/d. Since 200 psi intake pressure will supply adequate submergence for efficient pump operation, this will be the production rate used for our design.Total dynamic head required The next step in designing an ESP system is the determination of total dynamic head (TDH) required by the pump. Using the information obtained above, the TDH calculations are as follows: H = Hd + Ft + Pd Where H= total dynamic head required Hd =vertical lift from operating fluid level to surfaceFt =friction loss in tubingPd =discharge pressure, ft Before we can determine Hd , we must first convert the 200-psi pump intake pressure into a fluid column, as This is the fluid column above the pump intake. If we subtract this fluid column for the pump setting depth, 5,000 ft, the remainder of 4,530 ft is the vertical lift required by the pump. Friction loss in tubing can be determined from avail- able charts- The chart in Fig. 1 shows a loss of 40 ft of head per 1,000 ft of tubing. Our unit will be at 5,000 ft, so the friction loss is 40 ft ×5 or 200 ft Discharge pressure is the pressure required to overcome head loss due to friction in the surface pipe valves and fitting, and any elevation changes. Using the wellhead pressure from Table 1, and converting to feet of head, as before, we get75×2.31/0.982=176 ft then total dynamic head = 4,530 + 200 + l76 = 4,906 ft. After determining the well's productivity and the total dynamic head required by the pump, the selection process for the ESP system could begin.Selecting the Pump Select the pump with the highest efficiency for the calculated production rate, which in the example is 1,268 b/d or 37 gpm. From Table 2, typical for 4-in. Pumps, the closest is for 34 gpm where the peak efficiency point is located at 1,200 b/d. Fig. 2 shows the single-stage pump performance curve for a typical 34-gpm pump. The pump's efficiency is plotted along with the head per stage and horse- power per stage- Recommended operating range also is shown. As can be seen) the head per stage at 1,268 b/d is l8.5 ft. The horsepower requirement is 0.26 bhp/stage, with an efficiency of 68%. To determine the total number of stages required, amp = motor amperage divide the head per stage into the total dynamic head, or 4,906 / 18.5 ≈ 265. Therefore, a 265-stage, 34-gpm pump is required to produce 1,268 b/d is against a total dynamic head of 4,9o6 ft. TABLE 2. Typical example of available tables to aid pump selection – this table is for 4-in. Pumps, in 5 1/- in or larger casingPUMP CAPACITY, GPM 11 18 27 34 48 61 69 80 100Peak efficiency60 Hz b/d 360 600 880 1,200 1,600 1,900 2,150 2,700 3,350m3/d 57 95 140 191 254 302 342 429 53350 Hz b/d 300 500 733 1,000 1,333 1,583 1,792 2,250 2,792m3/d 48 79 117 159 212 252 285 358 444Optimum range60 Hz b/d 182 to 492 440 to 730 660 to1,080 840 to1,400 1,125 to2,050 1,250 to2.350 1,500 to2,650 1,750 to3,500 2,200 to4.350m3/d 30 to78 70 to116 105 to172 134 to223 179 to326 199 to374 238 to421 278 to556 350 to69250 Hz b/d 152 to410 373 to608 550 to900 700 to1,167 937 to1,708 1,042 to1,958 1,250 to2,208 1,458 to2,917 1,833 to3,625m3/d 25 to65 59 to97 87 to143 111 to185 149 to272 165 to312 199 to351 232 to464 291 to576Maximum range60 Hz b/d 180 to 497 400 to 800 650 to1,100 840 to1,500 1,050 to2,150 1,200 to2.600 1,250 to2,800 1,600 to3,650 2,000 to4.500m3/d 29 to 79 64 to 127 103 to 175 134 to 238 167 to 342 191 to 413 199 to 445 254 to 580 318 to 71550 Hz b/d 150 to 414 333 to 666 542 to 917 700 to 1,250 875 to 1,792 1,000 to 2,167 1,042to 2,333 1,333 to 3,042 1,667 to 3,750m3/d 24 to 86 53 to 106 86 to 145 112 to 199 139 to 285 159 to 344 165 to 371 212 to 484 265 to 596TABLE 3. Motor specifications for 5 1/2—in., 20-lb/ft and larger casing sizesSize , hp Volts /amps Length Weight60 Hz 50 Hz 60 Hz 50 Hz In. M Lb Kg15202525 12.5172121 440/22420/31430/38750/22 366/22350/31358/38625/22 66818787 1.682.062.212.21 269332396396 1221501791793030 2525 430/46740/27 358/46616/27 112112 2.842.84 459459 208208353535 292929 430/53740/31960/24 358/53617/31800/24 127127127 3.233.233.23 523523523 237237237404040 333333 420/62725/36965/27 350/62604/36804/27 142142142 3.613.613.61 586586586 265265265505050 424242 785/41900/361200/27 654/41750/361000/27 172172172 4.374.374.37 713713713 32332332360606060 50505050 735/51840/44945/401270/30 612/51700/44787/401058/30 202202202202 5.135.135.135.13 840840840840 381381381381757575 62.562.562.5 645/77925/521130/43 537/77770/52941/43 248248248 6.306.306.30 103110311031 4674674678585 7171 1290/432080/27 1075/431733/27 278278 7.067.06 11581158 525525100100 8383 1150/562080/31 958/561733/31 323323 8.208.20 13501350 612612120120120 100100100 1000/771200/642080/37 833/771000/641733/37 384384384 9.759.759.75 160516051605 728728728Selecting the MotorTo calculate total horsepower, multiply brake horsepower per stage by the number of stages and by the specific gravity of the fluid being produced, or 0.26 X 265 X 0.982 = 67.6 hp Review the listings showing motors available, as shown in Table 3, and make the best selection. In the example given the selection is a 75-hp, 1,130-v, 43-amp, motor. Select a seal section that will adapt to the motor selected and one which can handle the lift designed. Then, select a motor controller on the basis of voltage, amperage, and horsepower ratings. Control circuitry also should be considered, such as electromechanical, relays versus solid-state design. The power cable selection should be based on fluid characteristics, temperature, voltage drop, and physical size. Finally, the transformer selection is based on the required power WhereVs= required surface voltage (motor voltage =lossAmp = motor amperage Final selection depends primarily on available primary voltage, required surface voltage, and kVA requirement. Part 5Application of Electric Submersible Pumps in Hostile Environments In the past the electric submersible pumping system (ESPS) was considered useful in the production of medium- to high-volume, low-temperature, and sweet wells. Today, the ESPS has evolved into one of the most versatile means of recovering fluid from practically any depth, including hostile conditions, and has been applied successfully in producing volumes as low as 100 b/d. One of the major challenges the ESPS had to meet was overcoming high bottomhole temperatures. The problem was temperature limitations of the elastomer materials used in the power cable, O-ring, and seals.Modern power cable technology has improved to the point that reliable elastomers are available for use in the production of cables capable of withstanding bottom hole temperatures of 250 F. Materials once used for O-rings, when exposed to high temperatures, had a tendency to shrink and harden, resulting in a loss of sealing ability. Today, there are many materials to choose from all capable of withstanding high bottom hole temperatures and corrosive well fluids. Research in developing improved insulation has produced materials which are capable of long life in temperatures that far exceed 250 F. One of the modern encapsulating materials used in today's ESPS is epoxy .The integrity of motors using epoxy varnish as an encapsulating material resulted in substantial improvements. Epoxy, during its curing process, does not give of f bubble-forming gases thus stator winding can be completely filled. Epoxy also possesses an excellent heat conductive capability which results in the improved transfer of heat from the motor windings, reducing burns in the lamination slots (Fig. 1). For example, in earlier years the standard encapsulating material used was varnish. The problem with varnishes is they are t0o thin, and in the curing process the solvents evaporated, resulting in voids within the motor windings. The effect was a poor transfer of heat from the motor windings, so burns in the lamination slots were commonplace. A few years ago it would have been considered poor practice to apply an ESPS in 250 F, but with today’s advancements, it is now an everyday occurrence. Another problem which once was considered extremely detrimental in ESPS application was corrosive environments that affected the housing materials, cable armor, and internal electric motor windings due to inadequate sealing. Corrosive damage to housing material has been successfully combated with two approaches. The first is to apply a non-corrosive metallizing material over the carbon steel housing, and the second meth0d is to use housing and bar stock material that is not affected by corrosion. The choice of which approach to take depends on the corrosive medium. In most cases, in wells which contain low concentrations of H2S, the metallizing technique would be adequate in protecting the housing material. If the well has a high concentration of H2S or if CO2 enhanced recovery techniques are used, it is necessary to use corrosion-resistant metallurgy. Special metallurgical materials, such as stainless steel, mean an increase in investment, although the greater cost is more than compensated for by a substantial increase in product life. Corrosion of cable armor has always been a problem, and Monel armored cable has been considered the only solution. For low-temperature corrosive applications polypropylene jacketing has been used for years, but until recently, in environments with medium to high temperatures, there has not been an economical corrosion resistant jacketing material. Today, less expensive jacketing materials are available which are virtually unaffected by corrosive fluids and which provide additional protection for the electrical conductors. These materials are used in perforated jacketing for gassy environments. It allows the gas to escape from inside the cable thus preventing ballooning that occurs as a result of decompression when the cable is removed from the well. The new jacketing material serves both as a replacement for the metallic armor and as a protective material used around the conductors to prevent mechanical damage (Fig. 2).Fig. 2. Improvements in jacket materials used to protect electrical cables have virtually eliminated corrosion and high- temperature problems- This perforated jacket for gassy environments allows gas to escape from inside the cable preventing ballooning that occurs as a result of decompression when the cable is removed from the well. To prevent high pressure differential across the mechanical seals, all electrical submersible manufacturers permit well bore pressures to be equalized through a seal section which also allows for the expansion and contraction of the motor oil due to heating and cooling. The problem arises when the well bore fluids are allowed to enter the seal section and motor, because should any detrimental ingredient (such as hydrogen sulfide) come in contact with the motor oil, it will become contaminated. To combat this problem, new elastomers have been developed which make it possible to produce a barrier between the well fluid and the motor oil. This resulted in improved run life of electric submersible motors. A problem that plagued practically all-pumping systems over the years was free gas in the production fluid. Until recently, all gas separators, whether for rod or submersible pumps, even cup-type separators.Fig. 3- A Problem that once plagued practically all-pumping systems has been free gas in the production fluid. This rotary gas separator, which employs centrifugal force to separate the fluids from free gas, forces the heavier fluids to the outside portion of the chamber while lighter free gas is diverted back into the casing annulus. Which use retention cups to allow gas to escape, were an adaptation of the "poor boy" principle. Laboratory tests show the performance of separators of this type suffers greatly when the volume of free gas exceeds 10%. Recently, a rotary gas separator was developed for the ESPS industry that employs centrifugal force to separate the fluids from the free gas. This type of gas separator makes no attempt to separate any production mixture before entering the pumping system. Instead, the separator ingests the mixture and directs it into a centrifuge chamber. The mixture then is subjected to centrifugal forces up to 6 g, which forces the heavier fluid to the outside portion of the chamber while the lighter free gas remains near the center. The liquid then is directed to the eye of the first impeller while the gas is diverted through a splitter cylinder back into the casing annulus (Fig. 3). By incorporating the rotary gas separator in the pumping system, an operator now can reduce fluid levels and thereby increase the amount of production from a well. In fact, the rotary gas separator is so effective it has actually been used to dewater gas wells. Part 6How the ESP Is Handled, Service, an InstalledThe electric submersible pumping unit is precision equipment. If it is not handled, serviced, and installed with care, long run life cannot be expected, even in wells with optimum conditions and a good power system. A crane, gin truck, or forklift of adequate size and capacity must be used for unloading and positioning equipment at the well site. Never allow the equipment to be winched off the end of a truck bed or trailer. The boxes should be positioned to allow the equipment to be brought straight to the well when picked up for assembly not around the tubing string standing in the derrick or over and around other equipment on location. If this is not possible, a crane, gin truck, or forklift should be used to bring up each piece of equipment as needed for assembly The cable reel should be positioned 75 to 100 ft from the well if possible. For safety reasons and to protect the cable it must be positioned where the well service rig operator can see the cable and reel at all times. The cable should come off the reel toward the rig and up to the guide wheel without going over or around other equipment on location. Use of a cable reeling machine (Fig. l) has many advantages. It can speed up the installation process without rushing. It allows the cable to be reeled in and out of the well with a minimum of stress to the cable, thus adding considerably to its life. After the cable is set in place for installation, and before the unit assembly begins, the cable should be electrically tested. All phases should be tested - phase- to-phase and phase-to-ground at 5 kV DC. Installing any cable that has a reading of less than 100 megohms is not economically justifiable. The phase rotation with pothead terminal pins should be marked at the top end of the cable string. When shipping cases are open, special lifting clamp and chain slings are installed on the downhole equipment. A pickup sub 3 to 6 ft long should be installed in the discharge of the pump. The thread torque should be checked with tubing tongs a short time before lowering the assembly into the well. Do not leave the equipment with one end blocked up for an extended period of time.Fig.1. The cable reeling machine should be placed where the rig operator can see the cable and reel at all times, and the cable should come off the reel toward the rig without going over or around other equipment. Handling the Motor The motor is the first piece of equipment to be picked up. A rod hook of adequate size latched in the elevators or a large clevis of adequate size run through the bales with the elevators removed is the best way of attaching to the chain on the lifting clamps for picking up the electric submersible equipment. Do not latch the tubing elevators through the lifting clamp chain. Tubing elevators are not designed to be used in this way and often the door will come unlatched and equipment will be dropped. After the motor is picked up vertically a check should be made to assure the plugs and cap screws in the bottom of the motor are tight before lowering it into the well. While servicing the downhole equipment the pump company service representative will assure the following: 1. All shafts rotate smoothly with no tight spots.2. All air bubbles are worked out of the oil in the motor and seal section.3. All lead washers (seals) are removed from the vent holes and vent plugs, then replaced with new ones. 4. All O-rings are replaced with new ones. 5. Motor phase rotation is checked with motor rotation indicator6. Motor electrical resistance between all phases is balanced. 7. Motor electrical insulation dielectric strength phase-to-ground is a minimum of 100 megohms. 8. Motor lead flat cable pothead is properly installed in the motor. 9. That all strain is kept off the motor lead flat cable pothead after it is installed in the motor.10. Motor and cable (connected) electrical resistance between all phases is balanced. 11. Motor and cable (connected) electrical insulation dielectric strength phase-to-ground is a minimum of 100 megohms. 12. All socket head cap screw vent plugs and hex head cap screws are in place and tight. 13. Motor lead fiat cable extension guards are bonded in place properly making sure they run straight up the unit. 14. The unit is hanging free in the well and not touching the casing. 15. Cable bands are being put on the proper tension and the buckle (seal) is positioned so it will not snag while going into the well. 16. Check valve is installed (where applicable) in the tubing string. This is normally 4 joints of tubing above the pump. If the well is gaseous it should be installed 6 to 10 joints above the pump. This allows for a column of fluid to break a gas lock in the pump, should the unit shut down due to gas locking. 17. Drain valve break off pin is in place and tight. 18. Drain valve is installed one joint of tubing above the check valve' This allows scale or debris, which might be knocked loose by the bar dropped to break off the pin, to settle below the drain valve and not plug off the drain hole. While going into the well, the pump company service representative Will continuously check to assure the unit is hanging free in the well and the bands are being put on correctly with proper tension and the buckles (seals) are properly crimped. Pneumatic banding is highly recommended (Fig. 2). The tension at which a band is put on can be adjusted at the tool. Thus, the proper tension can be achieved for new or old cable, flat or round configuration. By putting each band at the same tension, the possibility of human error is eliminated. This has a direct effect on the operating life of a cable string. The slips being used must have a notched door to allow room for the cable to be out of the way when the slips are being set. Often it is necessary to use the slips with the door removed. It is necessary to have the bolt and nut in place to assure the bowl does not spring open when the weight increases as tubing is added. Electrical Checks The pump company service representative will also make electrical checks on the motor. and cable while the unit is being installed into the well. Approximately every 1o stands he will check the phase-to-phase and phase-to-ground resistance. Normally, the oil company representative will have made arrangements to have the transformer and pump control panel tied into the electrical system and the junction box mounted before the unit reaches setting depth. The pump company representative will check out the incoming power and recommend any changes required in transformer tap settings to derive the correct surface voltage. After proper surface voltage is derived the pump company representative will make required adjustments in the pump control panel to obtain the correct control circuit voltage and current transformer ratios. He then will make adjustments to obtain the proper overcurrent (overload) and undercurrent (underload) protection. He also will cycle the board to assure all systems are functioning properly. After everything is set up and operating properly in the pump control panel, the pump company representative will check and mark the phase sequence of the electrical power at the junction vent box. When the unit is landed at setting depth the company representative will make a phase-to-phase and phase- to-ground electrical resistance test. With everything checking out electrically he will work with the well servicing rig crew to properly pack off the cable to assure oxygen will not leak into the well when the annulus is pumped down or that gas or fluid will leak when the annulus is under pressure.While the flow line is being connected to the tubing, the pump company representative will check and mark the phase sequence of the electrical power at the junction went box. When the unit is landed at setting depth the company representative will make a phase- to-phase and phase-to-ground electrical resistance test. With everything checking out electrically, he will work with the well servicing rig crew to properly pack off the cable to assure oxygen will not leak into the well when the annulus is pumped down or that gas or fluid will leak when the annulus is under pressure. While the flow line is being connected to the tubing, the pump company representative will make a final electrical resistance test of the cable and motor phase-to-phase and phase-to-ground. Then he will connect the power cable into the junction vent box. After all wellhead connections are completed and a check is made to assure all valves are open, the pump company representative will start the unit, monitoring the starting current and voltage. He also will check the amount of time it takes the unit to pump fluid to the surface. After fluid reaches the surface, the pump company representative will monitor operation for at least 1 hr to assure everything is operating correctly assuring the unit has the correct operating voltage, He also will recheck the overload and under load settings and will assure the recording ammeter is correctly calibrated and operating properly If at all possible the production volume rates should be monitored during this first hour of operation, with calculation made against the producing fluid level to assure the pump is operating in the ballpark of the design. When possible the pump company representative will check back personally 12 to 18 hr after the unit is started to assure everything is operating correctly. Part 7Applying Variable Frequency Drives to ESPsTo keep pace with technology, the oil industry has begun using variable frequency drives on electrical submersible pumps. Applying variable frequency drives on ESPs began seriously in l977. In March 1983, there were approximately 350 variable frequency drives successfully operating on electrical submersible pumps throughout the world. Three types of variable frequency drives available. Low efficiency today are the current source inverter, the pulse width modulation, and the variable voltage source inverter. As all three types have good points and bad, a short discussion of each type is essential to understand why the variable voltage inverter is used most often in oil field applications and why it has been a success. A current source inverter typically uses a phase-controlled rectifier to generate variable DC current. The phase-controlled rectifier produces the required current which is subsequently filtered by a DC link reactor. The inverter then produces the desired varies with load. Positive aspects of the current source inverter are: It is cost effective if applications do not require high starting torque Low-cost phase-controlled SCRs can be used in the inverter. The negative points for the current source inverter are: An oversized unit 1s required for high starting torques. The motor is part of commutation circuit, thereby making it difficult to run different size motors on the current source inverter. Low efficiency Complex control loop.These problems make the current source inverter undesirable for ESP applications.The pulse width modulation typically uses a diode rectifier to produce DC current. The frequency and voltage are created in the inverter by switching on and off several times a cycle.The positives for the pulse width modulations are: Good power factor through the speed range. Efficient. Cost effective.Negative aspects for the pulse width modulation are: Higher stress on motors due to more commutations per cycle and at a higher power level. High starting torques required over sizing pulse width modulation. Unable to increase in voltage above 60 cycles thereby having to oversize motors.A variable voltage inverter typically uses a phase- controlled rectifier to produce the required voltage. The inverter then produces a six-step quasi sine wave. The main advantages of the variable voltage inverter are:  Adjustable but constant voltage per cycle output at any frequency. Variable voltage per hertz ratio produced is that which is required by the motor at every frequency This eliminates having to oversize motors. High starting torque capability Because electrical submersible pumps often produce foreign material through the pumps they are often hard to start. The ability to deliver high starting torque is essential. The negative aspect of the variable voltage is poor power factor at low output voltages. The MotorThe electric motor on an ESP has gone through many changes and improvements over the last 50 years, but it is still subject to failure. The four main reasons for motor failure are transients, voltage unbalance, severity of startups, and harsh environments. Transients are defined as any disturbance in the power system caused by problems ranging from switching spikes to lightning. A small transient may not burn a motor immediately but will weaken the insulation, making the motor more susceptible to failure during next transient. One function of a variable frequency drive is to prevent transients from reaching the motor This ability can lengthen the run life of the motor. Next to lightning transients, voltage unbalance may have the most detrimental effect on a motor Voltage unbalance can be caused by a number of problems, such as overloaded distribution lines, large amounts of single phase loads on the system, open delta transformers, power line configuration, etc. Unbalanced voltage produces negative sequence currents which create extra heating in the motor. An electrical submersible pump motor has a rotating stator field that operates at 3,600 rpm with the rotor revolving at approximately 3,500 rpm. This differential induces currents into the rotor conductors which is normal. Unbalanced voltage produces a backward rotating component in the stator field - the component speed, relative to the rotor, is 3,600 + 3,500, or 7,100 rpm. At this speed differential only a small voltage unbalance is required to create large currents in the rotor. Two main problems result: (1) an opposing torque is generated which counters the desired torque, and (2) because the two fields are passing at 7,200 rpm they create a pulsating torque component at 130 times per second, which can cause vibrations in the motor and pump. As a rule, the increased motor losses and heating effect due to unbalanced voltages are approximately two times the square of the percentage unbalance. For example, a 5% unbalance will cause an approximate 50% increase in motor losses and heating. A variable frequency drive takes the three incoming phases and converts the AC power to a common DC bus. All three output Phases are created from the same DC bus, thereby making all phases balanced and eliminating unbalanced voltages.Pump Startup Starting an electrical submersible pump can be very detrimental to the entire installation. On startup the motor can produce a great amount of torque. On normal across-the-line starts the motor will usually draw between four to eight times the rated amperage. This type of startup has led to twisted shafts, burned motors, and cable. A variable frequency drive reduces the impact of starting by starting at 10 Hz instead of 50 Hz 0r 60 Hz, thereby reducing the inrush 0f current. Except in wells with stuck pumps it is seldom necessary to increase the starting amps above l50% of rated current. As a result, the VFD allows the operator to restart the equipment many times without harmful effects. Although a variable frequency drive starts at a reduced speed, it can still deliver up to 200% of running torque on startups. The variable frequency drive does not twist shafts because of the speed at which it starts. If the pump is stuck or spinning backwards the variablefrequency drive will shut down on torque limit before causing damage t0 the equipment.Application When applying a variable frequency drive to the electrical submersible pump the entire system needs to be examined. Due to the increased operational range of a centrifugal pump at high speeds, it is often advantageous to run at higher hertz. Slower speeds should be considered when producing viscous fluids 0r abrasives. Before determining the best-suited drive for a particular application, an engineer must understand some basic pump affinity lawsRate ≈ RPM (1)Head ≈RPM2 (2)andBrake horsepower ≈ RPM3 (3) From pump performance curves, the pump brake horsepower at 6O Hz can be determined. In turn, pump brake horsepower at the maximum frequency is proportional to pump horsepower at 60 Hz, and can be calculated by rewriting Eq. 3:pump hp @ maximum frequency/ (maximum frequency)3= pump hp @ 60 Hz/(60Hz)3pump hp @ maximum frequency=(maximum frequency/60Hz) 3 Available motor horsepower is directly proportional tothe frequency: Finally required surface kVA can be calculated as follows:kVA = (motor voltage x maximum frequency + cable voltage drop) x moor mp x 1.732 x 0.001 (6)When selecting a variable frequency drive, the choice is usually between a pulse width modulated and a variable voltage inverter. The following example will demonstrate why the variable voltage inverter is the variable frequency drive best suited to run with a submersible pump data include:Total dynamic head = 7,500 ftPump rate = 1,650 to 3,600 b/d of fluidFrequency range = 60 to 72 HzCable voltage drop = 150 vCasing = 7 in.Fig. 1 is the appropriate pump performance curve.First determine the brake horsepower at 60 Hz. From the pump performance curve (Fig. 1), the maximum horsepower at 60 Hz is 0.94 hp/stage. Using Eq- 4, the required pump horsepower at the maximum frequency of 72 Hz then can be determined:for hp @ vz Hz = (g)' x 0.02 hp/stages= 1.62 hp/stageNext, calculate the head capacity per pump stage and the total number of pump stages. Assuming a maximum pump rate of 3,600 b/d at 72 Hz, use Eq 1 to determine the pump rate at 60 Hz:Rate @ 6O Hz = 3,600 b/d x ($= 3,00O b/dFrom Fig. 1, the required head capacity for a 3,000-b/d pump rate at 60 Hz is 30-5 ft/stage (Point A). To determine the required head capacity for a 3,000-b/d pump rate at 72 Hz, use Eq. 2:Head capacity @ 72 Hz = 30)5 ft/Stage x(H )'-44 rt/stageCalculate the number of required pump stages as follows:No. of pump stages =total dynamic head = 7,5O0 ft = 17O stagesMaximum total required pump horsepower at 72 Hz is No. of pump stages x hp/stage = 170 stages x 1.62hp/stage = 276 hpThe required m0tor size, calculated from Eq. 5, is6O HzMotor hp @ 60 Hz = 72 Hz'72 Hz'The most appropriate motor available has a horsepower of 225 hp. From industry catalogues, a 225-hp motor requires 2,l00 v at 63 amp. Using Eq- 6, the required surface kVA can be determined:f 72 Hz \kva =(2,100 v xax+ l5O 4If a variable voltage inverter were used it would require a 170-stage, 70-gal/min pump, a 225-hp motor a 291 kVA variable voltage inverter) and a No. 4 cable. This equipment should then be compared to equipment using a Pulse width modulated inverter.As most PWM inverters have limited motor starting capabilities, they must be oversized at least 30% to allow for hard starting pumps. For a motor to increase its horsepower capabilities proportionally with rpm, the voltage must vary proportionally Because pulse width modulation does not maintain a constant volts-per-hertz ratio above 60 Hz, the motor must be over sized to compensate. If the voltage remains constant above 60 Hz, then the torque produced by the motordecreases by the square of the decreased voltage. More slippage occurs between the rotor and stator due to the weakened magnetic field. This slippage increases the motor loss and generates excess heat- Therefore, the motor must be oversized to compensate for this extra heating.A 10% derating of the motor is necessary to compensate for the heating caused by the pulsating voltage at low frequencies.From the above example, for the two variable frequency drives to be comparable, the required pump brake horsepower must be 276 hp. The required motor horsepower when using a PWM inverter can be calculated asMotor hp @ 60 Hz = ap x 276 hp = 331 hpThe closest available motor with the required horsepower is 350 hp. From industry catalogues, a 350-hp motor requires l,950 v at 105 amps- Using Eq. 6, the surface kVA isfkvx = (,,,,, v .ap + 150 v )IThe PWM must be oversized 30% for motor starting, so the total required surface kVA is Required surface kVA = 1.3 x 381 kVA = 495 kVAIf a PWM inverter were used it would require a 170-stage, 70-gal/min pump, a 35O-hp motor, a 495-kVA pulse width modulated inverter and a No. 1 cable. As the previous example demonstrates, the pulse width modulator requires a significant increase in the size of equipment. This results in higher equipment costs and larger equipment downhole. This is undesirable and can be eliminated by using a variable voltage inverter designed to operate with submersible pumps.BibliographyCentrillft Hnghes Submersible Pump Handbook (1975).Divine, D. L.: "Variable Speed Submersible Pumps Find WderApplication," Oil & Gas J (June 11, 1979). Mingshirin, E. A. and Jordan, H. E.: "P0lyphase Induction Motor Performance and Losses on Non-Sinusoidal Vo1tage Sources" paper presented at IEEE (March l968).NEM Standards, MGI l2-45a and 14, 34c