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This article gives an overview of a pump's effect on the shearing of production fluids in the oil industry. Most of the world's oil reservoirs produce oil together with water. The liquids are subjected to shear forces through the pumps and are sheared as they pass through pressure-reducing devices in the production line. A common oil field emulsion is a dispersion of water droplets in oil. Formation of emulsions in the main separation process is a big concern for the operators.
The primary surface equipment for a sucker-rod lift system is the pumping unit and its prime mover. But a variety of other equipment is also used in the surface operations for this type of artificial lift. This page discusses the polished rod, associated clamps, stuffing boxes, rod rotators, pumping tees, check valves, and surface valves. A polished rod is the top-most rod in a rod string. These rods come in various lengths and sizes.
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.
The rod string and tubing are important components of the overall progressing cavity pump (PCP) system. In a PCP system, the rod string must be capable of carrying axial load and transmitting torque between the bottomhole pump and the surface drive. Therefore, rod-string design encompasses an evaluation of the axial tension and torque loading conditions for the full range of anticipated operating conditions. An appropriate size and grade of rod string can then be selected on the basis of appropriate design criteria, such as ensuring that the maximum calculated combined stress does not exceed the yield capacity or manufacturer's recommended values. Fatigue-loading considerations must also be addressed in certain applications.
In many applications, the constituents of the produced fluids pose the greatest difficulty in the successful use of progressive cavity (PC) pumps. In fact, the current use of PCP systems in many medium- and light-oil wells can be attributed to the recent development of new elastomers that can withstand the produced-fluid chemistry, allowing reasonable pump run lives to be achieved. However, further developments and improvements are required because there are still relatively few PCPs used in fields producing light oils with gravities 40 API. The presence of different quantities of carbon dioxide, methane and hydrogen sulfide gases, aromatics, and paraffins in the produced fluids, as well as different downhole temperature conditions, requires that special consideration be given to elastomer selection, pump sizing, and well operation. Aromatics such as benzene and toluene typically induce swelling of the stator elastomer, which makes pump sizing more difficult, whereas H2S can cause extended vulcanization, which results in hardening and eventual breakdown of the elastomer material.
Because of the inherent curvature (angle build sections) and angled bottomhole segment of directional and horizontal wells, optimization of a progressive cavity pump (PCP) system design for such applications begins with the drilling program. The proposed well geometry, or directional plan, should take into consideration the design and operation attributes of a PCP system, including equipment selection, to contend with potential rod/tubing-wear and rod-string fatigue problems, the preferred pump seating location for achieving optimal production rates throughout the well life, and possible issues related to gas and solids production. The first line of defense against rod/tubing-wear and sucker-rod fatigue problems in deviated and horizontal wells is a good wellbore profile (see previous sections on rod-string/tubing wear and rod loading). Ideally, the planned angle build rates should be kept as low as practical, and additional monitoring is typically required during drilling to ensure that the well closely follows the prescribed path. Note that slant wells (wells spud at an angle on surface), which typically have no planned curvature, often provide a good alternative to deviated wells for shallow reservoir developments as a means to avoid rod/tubing-wear problems.
In most operations, dissolved gas begins to evolve as free gas when the pressure drops as the fluid moves toward and then enters the well. Depending on the fluid properties and gas volumes, the free gas may coalesce and flow as a separate phase, or, as in the case of many heavy oil wells, it may remain trapped as discrete bubbles within the liquid phase (foamy oil). Gas entering the pump causes an apparent decrease in pump efficiency because the gas occupying a portion of the pump cavities is normally not accounted for in the fluid volume calculations. The pump must then compress the gas until it either becomes solution gas again or it reaches the required pump discharge pressure. The best way to reduce gas interference is to keep any free gas from entering the pump intake.
A progressing cavity pump (PCP) system includes a variety of components. The basic system includes downhole PC pumps (and appropriate elastomers), along with sucker rod and production tubing strings and surface drive equipment(which must include a stuffing box). Surface-driven PCP systems require a sucker-rod string to transfer the torsional and axial loads from the surface drive system down to the bottomhole PC pump. Several different rod-string configurations are commonly used in PCP applications. These include continuous rods, standard rods with couplings (including hollow rods), standard rods with centralizers, and standard rods with bonded/molded rod guides. Within these categories are numerous additional variations resulting from differences in centralizer and rod guide design. The centralizers can be divided into two groups based on functionality. The first group consists of "coated" centralizers that have a urethane, plastic, or elastomer sleeve bonded to either a coupling or the rod body. The second group consists of "spin-thru" centralizers that have an outer stabilizer that is free to rotate on either an inner core or the rod body. With the spin-thru design, the rod string rotates inside the stabilizer, which remains stationary against the tubing.
Plunger lift is used primarily in low rate, high gas-oil ratio (GOR) wells. This page focuses on the features desired in key equipment required to operate a plunger lift operation. Desirable features in a plunger include efficient sealing, reliability, durability, and the ability to descend quickly. Rarely does a plunger exhibit all these characteristics, though. Usually a plunger that excels at one aspect sacrifices others. A wide variety of plungers is available to accommodate differences in well performance and operating conditions. The plunger seal is the interface between the tubing and the outside of the plunger, and probably is the most important plunger design element. Most plungers do not have a perfect seal; indeed, turbulence from a small amount of gas slippage around the plunger is necessary to keep liquids above and gas below the plunger. A more efficient seal limits slippage and allows the plunger to travel more slowly, which reduces the energy and pressure required to lift the plunger and liquid load. Less efficient seals allow excessive slippage, and so increase the energy and pressure required to operate the plunger. The velocity at which the plunger travels up the tubing also affects plunger efficiency (Figure 1). Very low velocities increase gas slippage and lead to inefficient operation and possible plunger stall.