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Downhole PC pump selection and sizing
The key technical considerations and decisions involved in selecting a progressing cavity pump(PCP) for a particular application include pump displacement, pressure capability, geometric design, elastomer type, and rotor coating characteristics. Other factors, such as local vendor choice and economics can also affect pump selection. Fig. 1 provides a flow chart of the key decisions.
- 1 Pump displacement and pressure capability
- 2 Torque requirements
- 3 Pump geometric design
- 4 Pump elastomer type and rotor coating
- 5 Progressive cavity pump (PCP) sizing practices
- 6 Elevated temperature applications of progressive cavity pumps (PCP)
- 7 References
- 8 Noteworthy papers in OnePetro
- 9 External links
- 10 See also
- 11 Page champions
- 12 Category
Pump displacement and pressure capability
When selecting a PC pump, the two most critical requirements are adequate displacement capacity and pressure capability to ensure that the pump can deliver the required fluid rate and net lift for the intended application.
It is typical to select pumps with a design (i.e., theoretical) flow rate that is somewhat higher than the expected fluid rate to reflect pump inefficiencies during production operations. Fluid slippage, inflow problems, and gas interference all contribute to reduced pump volumetric efficiency. Together, the design fluid rate and prescribed pump rotational speed define the minimum required pump displacement as
smin = minimum required pump displacement (m3/d/rpm [B/D/rpm])
qa = required fluid rate (m3/d [B/D])
ω = pump rotational speed (rpm)
E = volumetric pumping efficiency in service.
Initially, an optimal pump speed should be assumed on the basis of the intended application conditions, with the primary considerations being the viscosity of the produced fluids and tubing-wear potential. Table 1 lists typical pump speeds recommended for the production of fluids in different viscosity ranges. Higher speeds may be considered if these suggested values do not deliver the required production rates or if a pump with the preferred displacement cannot be sourced. In most cases, it is preferable to pump at the lowest speed practical to increase the life of the pump, rod string, tubing, and surface equipment. However, consideration should also be given to the impact that the selection of larger-displacement pumps will have on the sizing of the rod string and surface drive.
In general, there has been a trend recently toward higher speeds because new pump models and better sizing practices have been developed that have led to improved pump lives. For example, pump speeds of 300 to 400 rpm remain typical for high-water-cut applications, but some operators now routinely pump at 500 rpm and higher in such applications. Higher speeds may also be practical in some high-viscosity applications in which sand production and tubing-wear problems are not an issue and reasonable pump efficiencies can be maintained. For example, the new large-capacity PC pumps used to produce the prolific heavy oil wells in several eastern Venezuela fields are being run successfully at speeds of 400 to 500 rpm.
The net pump lift requirement determines the minimum required pressure capability of the pump. In determining the net lift value for pump selection, the full service life conditions should be considered. Net lift is defined as the difference between discharge and intake pressures of the PC pump under the expected operating conditions and is estimated as follows:
Plift = net lift required (kPa [psi]),
Pd = pump discharge pressure (kPa [psi]),
Pi = pump intake pressure (kPa [psi]).
Pump intake pressure is normally a function of the casing-head pressure plus the pressure caused by the gas and liquid column above the pump intake in the casing/tubing annulus. However, in systems in which tail joints or gas separators are used, the pressure drop that results from flow through these components must also be subtracted from the intake pressure. An estimate of the pump intake pressure can be calculated as follows:
Pi = pump intake pressure (kPa [psi]),
Pch = casing-head pressure (kPa [psi]),
Pg = annular gas-column pressure (kPa [psi]),
PL = annular liquid-column pressure (kPa [psi]),
Ptail = pressure loss associated with auxiliary components (kPa [psi]).
The pump discharge pressure can be calculated as the sum of the tubing head pressure, the liquid column pressure in the production tubing and the flow losses that occur in the tubing as follows:
Pth = tubing-head pressure (kPa [psi])
PL = tubing liquid-column pressure (kPa [psi])
Plosses = tubing flow losses (kPa [psi]).
For most existing applications, an accurate estimate of the tubing-head pressure will be available from previous measurements, but some additional calculations may be required to establish an appropriate value for the surface piping and related facilities in new installations. When the producing wells flow directly to a central gathering facility, consideration needs to be given to the fact that production from individual wells may be diverted to a test separator system that, in some cases, may impose above-normal backpressures on the pumping system.
Although the determination of static liquid- and gas-column pressures is routine, accurate calculation of flow losses and fluid densities can be much more difficult, especially in multiphase flow situations. As such, the use of analytical or empirical models is often necessary to determine these values.
Once the minimum pump displacement and net lift requirements are established, these values can be used to determine the range of pump models that will satisfy the requirements of a particular application. The main sources for obtaining pump specification information are product brochures and Websites of the various PC pump manufacturers and distributors, as well as design program databases. As noted, if there are no pumps that satisfy a particular set of requirements, then the system design or operating conditions must be changed. The relative cost and availability of particular pump models should also be taken into consideration during the pump selection process.
Rotation of the rotor within the stator forces fluid to move up the pump from cavity to cavity. A series of dynamic interference seals separate the cavities and provide a differential pressure capacity. The energy required to turn the rotor and move the fluid against this pressure gradient is provided in the form of torque. Pump torque is composed of hydraulic, viscous, and friction components. Hydraulic torque, the component used to overcome differential pressure, is directly proportional to pump displacement and differential pressure and can be calculated from
Th = hydraulic pump torque (N•m [ft•lbf]),
s = pump displacement (m3/d/rpm [B/D/rpm]),
Plift = differential pump pressure (kPa [psi]),
C = constant (0.111 [8.97 × 10–2 ]).
Fig. 2 shows the variation in hydraulic torque as a function of differential pressure for a number of different pump displacement values.
“Friction torque” must be applied to overcome the mechanical friction associated with the interaction between the rotor and stator. The magnitude of the friction torque depends on the interference fit of the rotor and stator, the type of rotor coating and stator elastomer, the lubricating properties of the fluid, and the pump length. Because friction torque reduces the mechanical efficiency of a PC pump, use of rotor/stator pairs with excessive values should be avoided. Understanding the magnitude of the friction torque in a downhole application can be difficult because the torque value can only be established empirically from bench test results (see the Pump Sizing Practices page).
In wells producing highly viscous oil, PC pumps require some magnitude of additional input torque to overcome flow losses that occur within the pump itself. The magnitude of this torque requirement depends on the fluid properties (viscosity vs. shear rate), pump geometry, pump speed, and fluid rate. The additional torque requirements are typically quite small (i.e., can be ignored) in most low-rate wells (e.g., < 20 m3/d) but can be quite significant in heavy oil wells producing at high rates (e.g., > 150 m3/d). Unfortunately, little published information is available at this time to provide guidance or models to estimate these loads accurately. However, some proprietary empirical determinations have been made with data from several instrumented, high-rate, heavy oil wells in Venezuela and full-scale pump tests conducted with viscous oils.
The total pump torque is thus equal to
Tt = total pump torque (N•m [ft•lbs]),
Tf = pump friction torque (N•m [ft•lbf]),
Tv = viscous pump torque (N•m [ft•lbf]).
In the pump selection process, it is essential to make a proper allowance for the torque requirements associated with pump friction and viscous pump torque (i.e., especially in the case of highly viscous fluids) to ensure that the power limitations and load capacities of the surface-drive system and rod string are not exceeded. In some cases, the available torque or power may affect pump selection by limiting the maximum pump displacement. Also, note that the friction torque at startup can be considerably higher than the nominal operating torque due to swell or compression set of the stator elastomer or settling of produced sand above the pump after a shutdown.
Pump geometric design
In most cases, several different pumps will satisfy the minimum fluid rate and lift requirements. However, depending on the application, some pumps will likely be more suitable than others. As discussed, pumps with similar displacements can differ significantly in terms of design. These geometric variations cause pumps to perform differently under certain conditions. When selecting a specific pump, it is important to evaluate:
- The nature of the application
- The geometric design of the pump
- The compatibility between the performance characteristics inherent to the pump design and the anticipated operating conditions
The first consideration is whether the casing size will impose a restriction on the pump diameter. Pump diameters currently range between 48 and 170 mm [1.89 and 6.75 in.], typically increasing with pump displacement, as illustrated in Fig. 3. Most vendors have pumps available in both standard diameters and slimhole configurations; i.e., the stator housing of many pump models can be machined down to facilitate use in smaller casing sizes. Reasonable clearances (e.g., > 6 mm [0.25 in.] diametrical clearance on casing drift) should be maintained to limit the annular fluid flow velocities to facilitate annular gas separation and to help prevent sand bridging. In the pump selection process, once the maximum allowable stator diameter has been determined, pumps that do not satisfy this requirement can be eliminated. Note also that the rotor major diameter for the selected pump model must be less than the drift diameter of the production tubing string.
For applications producing significant quantities of sand (i.e., > 2% sand by volume), the respective capabilities of different PC pump models to effectively transport the sand becomes an important selection criterion (see also High-Sand-Cut Wells page). The sand-handling capabilities of a PC pump are strongly influenced by its geometric design, with shorter-pitch-length, wider-cavity pumps generally offering better performance than pumps with long, narrow cavities.
In applications producing high-viscosity fluids, pump inflow should be considered in the pump selection process. The rate at which fluids can flow into and along the narrow pump cavities is limited. The inflow rate declines with increasing fluid viscosity (because of viscous restrictions) and decreasing pump intake pressure (because of reduced driving force). Some vendors refer to a minimum net positive suction head. If the pumping rate exceeds the inflow rate, incomplete cavity filling occurs, resulting in a pressure drop at the pump inlet, possible cavitation, and reduced pump efficiency (see also High-Viscosity Oil Wells page).
Suppliers should be consulted for assistance when choosing between different pump models to contend with sand or highly viscous fluid production.
Pump elastomer type and rotor coating
In many cases, the most important pump selection consideration is fluid compatibility. Even if the optimal pump geometry has been selected, reasonable pump service life can be achieved only if the stator elastomer is properly matched to the produced fluid conditions. Refer to the Elastomer page for guidance on elastomer selection criteria.
Fluid properties should also be considered when it comes to rotor selection. In most cases, the standard chrome-plated rotor is the most suitable. However, if pumping corrosive or acidic fluids, a stainless steel rotor will be less susceptible to corrosion damage. Because the rotor is often the first component to wear when pumping abrasive solids, the use of better wear-resistant coating materials should be considered. Most pump suppliers offer rotors with special coatings for improved wear resistance.
Progressive cavity pump (PCP) sizing practices
Elevated temperature applications of progressive cavity pumps (PCP)
- Weir, B. 2001. PC Pumps for High Volume Heavy Oil Production. Paper presented at the 2001 SPE Applied Technology Workshop— Progressing Cavity Pumps, Puerto La Cruz, Venezuela, January.
- Delpassand, M.S. 1997. Progressing Cavity (PC) Pump Design Optimization for Abrasive Applications. Presented at the SPE Production Operations Symposium, Oklahoma City, Oklahoma, 9-11 March 1997. SPE-37455-MS. http://dx.doi.org/10.2118/37455-MS.
- Vetter, G., Kiebling, R., and Wirth, W. 1996. Abrasive Wear in Pumps: A Tribometric Approach to Improve Pump Life. Proc., 13th Intl. Pump Users Symposium, Houston, Texas.
Noteworthy papers in OnePetro
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