Several nonstandard Progressing cavity pumping systems have been developed by various companies to improve pumping capacity, performance, and serviceability for certain applications. These nonstanard PCP systems includes a number of different downhole drive systems that inherently eliminate tubing wear problems and reduce fluid flow losses. Rod-insert PC pump designs are available that preclude the need to pull the tubing string for pump replacement. Charge pumps and fluidizer pumps are currently being used to increase the gas- and solids-handling capabilities of PCP systems. The following sections provide a brief description of the rationale for developing each hybrid system and a description of the basic operating principles of the product where applicable.
In a PCP system, produced fluid flows from the pump to surface through the annular area between the rod string and tubing. High fluid viscosities, elevated flow rates, or restricted flow paths can result in large shear stresses developing in the fluid, which cause large frictional forces to act on the rod string. Fluid-flow effects can range from having a minor to a dominant influence on PCP system design. This is illustrated in Figure 1, which shows pressure losses for a range of flow rates and viscosities through a 100 m [328 ft] length of 76 mm [3.0 in.] Note that the pressure-drop values range from nearly zero to values that exceed the corresponding hydrostatic pressure.
As with other artificial-lift systems, the basic objective in the design of a PCP system is to select system components and operating parameters (e.g., pump speed) that can achieve the desired fluid production rates while not exceeding the mechanical performance capabilities of the equipment components to facilitate optimal service life and system value. Figure 1 presents a "design process" flow chart that outlines the many factors and considerations that should be addressed in the selection of an effective overall system configuration and operating strategy. At each step, the designer selects certain operating parameters or specific equipment components and must then assess the impacts of these decisions on system performance. For example, selection of a particular tubing size is based on such design considerations as flow losses and casing size. Some considerations apply to more than one decision, as is the case with flow losses that affect pump, tubing, and rod-string selection.
Production of high-viscosity fluids can result in significant flow losses through the production tubing and surface piping. In some instances, the pressure requirements generated because of flow losses can exceed the hydrostatic head on a well. It is critical that system design account for the "worst-case" flow losses, particularly the selection of the pump (pressure rating), rod string (torque capacity), and prime mover (power output). Over the past decade, progressive cavity pump (PCP) systems have become a very popular artificial-lift method for producing heavy oil (API gravity 18) wells throughout the world. Fluid viscosity under downhole conditions can range from a few hundred centipoise to 100,000 cp in these applications, and the production rates also vary significantly although low rates are far more typical.
The basic system components include the downhole pump, sucker rod and production tubing strings, and surface drive equipment, which must include a stuffing box. However, a PCP installation may also include different accessory equipment, such as gas separators, rod centralizers, tubing-string rotator systems, and surface equipment control devices. The following sections describe the various components of a PCP installation in further detail. Figure 1.5--Cross sections of conventional and modified 2:3 multilobe PC pumps. Figure 1.14--Speed vs. torque characteristics for a squirrel-cage induction motor. This section outlines some auxiliary equipment commonly used with PCP systems. A tag bar or "rotor stop" is normally required to facilitate installation and spaceout of the rod string. Several different tag bar designs are available, but they usually consist simply of a steel rod or bar (approximately 25 mm [1 in.] in diameter) fastened widthwise across the middle of a short (e.g., 0.6 m [2 ft]) perforated tubing pup joint that is threaded to the pump intake. In some designs, the rod is replaced with a steel plate with holes to permit fluid flow. The number and shape of the perforations in the pup joint vary among manufacturers. A large perforated area is particularly important in highly viscous fluid applications to minimize flow losses and to facilitate sand flow to the pump intake. The pump vendor usually supplies a tag bar joint with the PC pump. Although the tag bar pup is usually the bottom component of the tubing string in a PC pump completion, an additional length of tubing is sometimes run below the tag bar as a tail joint to lower the pump intake. For example, in horizontal wells, the pump may be seated in the vertical section to alleviate wear problems while a tail joint is installed to allow fluid to be drawn from the curved or horizontal sections of the wellbore. This technique can also be used effectively to increase the fluid flow velocity below the pump, which can be important for maintaining solids in suspension. In some cases, tail joints can be used to reduce the gas-to-liquid ratio at the pump intake, although the pressure losses through the tail joint may lead to additional solution gas breakout, resulting in little or no improvement in volumetric pump efficiency.