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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. As discussed previously, pressure losses in the system accumulate and are reacted at the pump, where they cause additional pump pressure loading, leading directly to increased rod-string axial loads and system torque. 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).

Fig. 15.35 shows a good example of the effects that viscous flow losses and water slugging can have on pump loads in a heavy oil well. The axial and torsional loads on the well were monitored in real time with a purpose-built PCP system dynamometer unit. Fig. 15.35. Because the only significant difference during the operating period was the viscosity of the fluid being produced, these results clearly demonstrate the pronounced effect that flow losses can have on PCP system loads.

Elastomer selection and pump sizing are important in heavy oil applications to achieve optimal performance and pump run lives. It is normally preferred to start with medium-NBR elastomers in these applications because of the superior mechanical properties of these materials. However, in heavy oil applications in which the pumps are prone to swelling (e.g., eastern Venezuela), consideration should be given to the use of high nitrile elastomers. Several vendors have recently introduced soft elastomers (i.e., < 65 shore A hardness) for heavy oil service to facilitate effective sealing while allowing high concentrations of sand to pass through the pump without causing damage. Because slippage rates decrease and pump efficiencies increase with higher fluid viscosities, PC pumps can typically be sized with bench-test efficiencies of 70 to 80% at speeds of 100 to 150 rpm (i.e., at rated pressure without consideration for swell or thermal expansion) without negatively affecting performance. In new applications, optimal sizing criteria can be determined only on a trial-and-error basis by varying pump sizing and subsequently tracking both short-term and long-term performance. There is a tradeoff between sizing pumps more tightly to permit a larger degree of wear to be tolerated before a significant loss in efficiency is incurred and relaxing the fit to reduce the elastomer stresses and prevent elastomer fatigue failures. As a result, it is preferable to start by sizing pumps in the middle and adjusting the sizing criteria based on the types of failures that occur.

Production from heavy oil wells can also be highly variable in nature. To respond to the changing operating conditions, it is important to have a flexible power transmission system. Hydraulic systems are quite common because they provide variable speed capability with a high turndown ratio that is often necessary to facilitate the low pump speeds typically required. Electronic systems (electric motors with speed control systems) can also be effective as long as they have the ability to operate within the lower speed ranges.

Sand production is frequently a byproduct of oil production, especially in some primary heavy oil operations (e.g., Canada) where it is an important part of the recovery process. In such operations, sand influx is usually most severe during the initial stage of production when the volumetric sand cuts can exceed 40%. Subsequently, the sand cuts often stabilize at ≤ 3%. In high-rate applications (e.g., Venezuela), even low sand cuts can equate to significant volumes of produced sand over time. Sand and other solids production can cause problems in PCP systems by accelerating equipment wear, increasing rod torque and power demand, or causing a flow restriction by accumulating around the pump intake, within the pump cavities, or above the pump in the tubing. Also, given its specific gravity of ≈ 2.7, even moderate volumes of sand can substantially increase the pressure gradient of the fluid column in the production tubing.

With proper system design and operation, PCP systems can effectively handle produced fluids with significant sand cuts under reasonably steady-state conditions. Severe operational problems (equipment failures, shutdowns requiring workovers) generally develop due to short periods of rapid sand influx (slugging). Although some slugging occurs naturally, sudden sand influx can also be initiated by operating practices that cause fairly rapid changes in bottomhole pressure. The pressure variations affect inflow rates and can disturb stable sand bridges that develop around perforations, causing the bridges to collapse and sand to flow into the wellbore. For example, experience has shown that large changes in pump speed can precipitate sand slugging. Therefore, large adjustments in pump speed should be made gradually over a few days to allow the well time to stabilize. If possible, other practices that produce sudden variations in bottomhole pressure, such as well loading or casing gas blowdown, should also be avoided. Workover operations that cause swabbing of a well (e.g., rapid pulling of the production tubing string within the perforated interval) are often followed by periods of high sand production. Changes in the produced-fluid conditions can also precipitate sand influx. For example, a sudden increase in water production or a slug of higher-viscosity fluid can lead to a breakdown of stable sand arches, causing a slug of sand to enter the wellbore.

Sand accumulation inside the tubing just above the pump is a common problem. It leads to increased pump discharge pressures, reduced fluid rates, and in severe cases, increased potential for sudden pump failure. Sand buildup occurs when the produced-fluid stream cannot carry all the sand up the tubing to surface. Therefore, it is very important to assess the sand-handling capabilities of a PCP system design for applications in which sand production is expected. Sand settling and fluid transport velocities (in vertical pipes) can be assessed by comparing the fluid drag forces calculated using well-established methods

Low-productivity wells by definition deliver relatively low fluid rates; as a result, operators usually attempt to maximize recovery rates by producing them at low bottomhole pressures. If produced aggressively, the fluid column can be drawn down to very low levels even in some relatively high-productivity wells. These pumped-off conditions can cause pump inflow and gas interference problems that prevent the pump cavities from filling completely with liquid. This results in low volumetric pump efficiency, as illustrated by the field data in Fig. 15.36.

Pump inflow problems are common in wells producing viscous fluids under low submergence conditions. With highly viscous fluids, difficulties occur when the pump is operated at a speed that exceeds the rate at which the fluid can flow into and up the narrow pump cavities (cavity flow velocity of the PC pump). Fig. 15.37 shows, for example, a dramatic decline in pump operating efficiency with higher speed in a heavy oil well application. Although the trend evident in the data can be attributed in part to increased gas interference and reduced well inflow over time, the lower bottomhole pressures and pump inflow constraints definitely contributed to the large decline in efficiency.

Operating a PC pump at low volumetric efficiencies results in reduced heat removal rates, higher elastomer temperatures, and increased fluid slippage, which can substantially escalate wear rates (especially if sand is produced). As a result, continued operation at low volumetric efficiency (< 30%) can lead to significantly reduced pump life. Pump selection is a key consideration in low-productivity wells, given the potential for inflow problems to be mitigated to some degree through the use of a larger-displacement pump run at lower speed (i.e., the resultant higher torque requirements need to be considered). Pump intake designs with minimal flow restrictions are also desirable. In horizontal wells, pump submergence should be maximized by seating the pump intake as low as practical within the well.

The sensitivity of the dynamic fluid level to changes in the produced-fluid rate varies considerably between wells. Extra attention must be paid when implementing speed changes on low-productivity wells that can be pumped off rapidly to avoid damaging the pump. Caution should also be used when basing decisions on fluid-shot data in heavy oil and bitumen applications because it is common for a layer of foamy oil to exist in the annulus, which makes the acoustically measured fluid levels misleading.

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. When possible, the intake should be located below the perforations to facilitate natural gas separation. Even if the pump can be sumped below the perforations, small casing/tubing annuli can lead to high flow velocities that can "trap" free gas and carry it to the pump intake, thereby reducing the effectiveness of the natural gravity-based separation. Thus, seating of the stator, which typically has a larger diameter than the tubing, either within or above the perforation interval should be avoided if possible. Another option is the use of slimhole PC pumps in such circumstances.

In gassy wells in which the pump must be seated above the perforations, passive gas separators that divert free gas up the casing/tubing annulus can be effective. In such cases, assemblies that centralize the pump intake in the center of the casing should be avoided because free-gas bypass tends to be more efficient in a skewed annular space. Fig. 15.38. Loading variations can be attributed to discharge pressure fluctuations associated with changes in the fluid-column density and to the lifting effects of the gas produced up the tubing. Pump friction may also vary because of changes in fluid lubricity. The load fluctuations can be significant, particularly when substantial percentages or slugs of gas enter the pump. Large, continuous changes in load may accelerate rod fatigue problems or damage surface power transmission equipment.

When attempts are made to maximize fluid rates in gassy wells, the pump speed should be increased in relatively small increments, with subsequent monitoring of the resulting effects on production rates in order to identify the onset of gas interference problems.

Because of the inherent curvature (angle build sections) and angled bottomhole segment of directional and horizontal wells, optimization of a 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.

Fortunately, PC pumps can operate effectively at high well angles, even beyond horizontal. However, attention is required when the pump seating interval is selected to avoid potential wear, pump inflow, and gas interference problems. This is illustrated by Fig. 15.40, which presents a vertical section plot of a horizontal well that was inadvertently drilled with a "trap" at the base of the build section. Because the severe sand plugging and gas slugging problems that occurred with the pump initially seated within the angle build section led to several workovers, the operator was forced to try seating the pump in the horizontal section beyond the trap at the location shown. Although the equipment options were quite limited and wear problems were still a concern for this well, it was successfully pumped in this configuration through the use of a continuous-rod string and a larger pump that could be run at low speeds.

Ideally, the pump should be seated as low as possible in directional and horizontal wells to maximize intake pressures. As mentioned, use of long, small-diameter tail joints should be avoided as a means to lower the intake position because of the inherent pressure losses. Depending on casing size, reducing the wellbore curvature over the planned pump seating interval may be important to prevent the pump from having to operate in a bent configuration. This condition would negatively affect pump life and increase the potential for wear and rod-string fatigue failures directly above the pump. Operating a PC pump while bent may also introduce the possibility for fatigue failures of the rotor within the stator. Close attention to the wellbore inclination and curvature is also important in the selection of an optimal pump intake location to ensure that the intake will not be positioned against the high side of the casing, thus increasing the potential for gas interference problems. This is especially crucial in horizontal wells, which are more prone to gas-slugging conditions as a result of elevation variations along the horizontal section. Sand production should also be taken into consideration in establishing the pump intake position. Given that sand transport capabilities are reduced in the casing relative to the smaller-diameter production tubing, seating the pump at nearly horizontal will reduce the potential for problems resulting from sand buildup.

In many applications, the constituents of the produced fluids pose the greatest difficulty in the successful use of PC pumps. 2S can cause extended vulcanization, which results in hardening and eventual breakdown of the elastomer material. Diffusion of a significant quantity of gas (in particular, CO2) into the stator elastomer can lead to blistering or fracturing of the rubber because of rapid decompression of the pump during shutdowns.

Pump selection should be based on geometry considerations and stator elastomer properties to minimize the swell potential, although some swelling of the elastomer is inevitable in most cases. Depending on the type of elastomer and the downhole conditions, total elastomer swelling can exceed 3 to 4 vol% in extreme cases, although much lower percentages are usually required for a pump to operate effectively and have a reasonable run life. Performing swell tests is highly recommended to assist in pump selection and sizing when fluid compatibility is expected to be an issue. Experience has shown that the swelling process can be quite gradual, with it sometimes taking up to 6 months for the stator to reach the maximum swell condition. To compensate for the substantial swelling expected in some challenging well applications, pumps may be sized so loosely that they cannot generate any flow at pressures below their rated capacity in a standard bench test. In such cases, the sizing process is usually a delicate balance because, if pumps are fit too loosely, they will not be able to generate sufficient head to produce fluid to surface for a long period of time. One approach used to avoid low initial pumping efficiency because of loose sizing requirements is to complete the initial pump installation with a tighter-fit rotor and then occasionally to replace the rotor with progressively smaller sizes as the stator swells. However, this approach obviously requires additional workovers, which must be justified by the economics of the operation and comparison to other practical options.

Given the many parameters that can influence pump life, it is highly recommended that operators maintain a detailed database of all pump testing and field performance records to establish optimal pump selection and sizing criteria. This information is also crucial in terms of monitoring failure causes and effectively guiding pump replacement decisions as well conditions change.

The most common problem associated with gas diffusion into a stator is the damage caused by expansion of the gas trapped within the elastomer as a result of the rapid decompression that may occur under shutdown conditions. Elastomer selection is obviously important under such conditions because some materials are much less prone to damage than others. Although the options available to prevent rapid decompression and potential damage to the pump are limited, use of drive systems with brakes that prevent rapid drainage of the tubing during shutdown events is highly recommended in these situations. There was also a unique check valve product available previously that prevented the fluid column in the tubing from draining through the pump in the event of a shutdown. Caution should be exercised when attempting to restart such wells immediately after a shutdown to avoid a high-torque-overload condition and potential pump damage. It is also very important to avoid multiple restart attempts in rapid succession because this may lead to reduced brake effectiveness, rod-string failures, or severe pump damage. If a high-torque condition can be attributed to stator swelling/expansion, the options are to load the tubing string to surface before attempting a restart or simply leaving the well shut down for several hours (perhaps a full day) to give the elastomer time to relax.

Different well stimulation treatments are commonly used by operators to improve production. When contemplating treatment of a well produced with a PCP system, particular attention must be paid to the chemistry of any fluids that may come into contact with the pump. For example, the fluids commonly used in acidizing jobs will remove the chrome from standard rotors. Other chemicals may be incompatible with the elastomer and cause stator failure.

As the equipment has improved and operators have gained familiarity with PCP systems, pump operating speeds have increased substantially. Although the initial heavy oil well installations were typically run at speeds between 30 and 100 rpm, speeds in the 300 to 500 rpm range are now common, and some operators have been known to produce high-water-cut wells at speeds up to 1,000 rpm. Generally, speeds exceeding 500 rpm are not recommended because they typically lead to reduced pump and surface equipment life, increased potential for sucker-rod fatigue failures, and vibration problems.

Rod strings commonly experience excessive vibrations within certain speed ranges because of the resonant frequencies of the system. The potentially harmful vibrations can usually be minimized by adjusting the speed slightly up or down. Some speed control systems even allow the locking out of frequencies that cause harmonic problems. However, it is important to recognize that the resonant frequencies of the system will likely change over time with variations in the load and fluid flow conditions. Harmonics are an especially important consideration for the portion of the rod string directly above the pump that naturally experiences a "whipping" action because of the orbital motion of the rotor. The various factors influencing the severity of the whipping motion include the mass and eccentricity of the rotor, the extent to which the rotor sticks out above the stator, the well configuration, operating speed, anchored vs. unanchored tubing, and rod-string configuration. At higher speeds, this whipping action can lead to accelerated rod and tubing wear and fatigue failures of the sucker rod. In wells that experience repeated problems, additional rod centralization or different types of centralizers should be used.

Tubing-string failure is another problem that has been encountered in some higher-speed PCP applications. The failures were characterized by a parting of one or more tubing joints at the last thread on the pin adjacent to a coupling. The failures occurred at many different locations in the wells, including near surface, midstring, and above the pump, and attempts to solve the problem with tubing anchors and tubing centralizers simply led to a subsequent failure at another location in some cases. The failures occurred after only a few weeks in some wells and after many months in others. Available anecdotal information suggests that the problems were more prevalent in wells with large-volume pumps, high speeds, and improper rotor space-out (i.e., substantial rotor stickup above the stator). The evidence points to tubing fatigue failure induced by vibration; therefore, consideration should be given to possible corrosion-enhanced fatigue. Possible remedies may include changes in pump speed or pump seating depth.

PCPs have become one of the most common types of lift methods for dewatering coalbed-methane wells. Water rates are typically high during initial production and may exceed 400 m3/d [2,500 B/D] in some cases but normally decline to ≈ 25% of their original level after a few months. The produced water often contains high concentrations of suspended sand from hydraulic fracturing, coal particles, and dissolved solids. To facilitate maximum gas production, the wells are usually maintained in close to a pumped-off condition. This tends to exacerbate the problems associated with the handling of produced gas. Because coalbed-methane wells typically have quite modest gas flow rates, capital outlays and operating expenses must consequently be minimized for these operations to be economically viable.

Stator elastomer selection and pump sizing are critical in coalbed-methane applications. The many substances contained in the produced water, either naturally or as additives, can have a very detrimental effect on the performance of certain elastomers. Elastomer erosion characteristics are also important, given the typical presence of significant quantities of frac sand and coal particles in the produced water. In general, the best choice of elastomer for such abrasive pumping conditions is a medium NBR because it generally has the best mechanical properties and, with the inherently low ACN content (i.e., most nonpolar), can be expected to swell the least amount when producing water that is polar. However, one must use caution because some NBR compounds are prone to high water swell. This is not the result of the polymer itself but rather the presence of certain fillers or additives that have a tendency to draw in water. Since there is no oil in the fluid to provide lubrication in these applications, it is very important to ensure minimal elastomer swell because the tightening of the rotor/stator fit leads to high levels of friction, which in turn can cause operational problems and dramatically reduce pump life. As a result, some vendors offer elastomer products specifically formulated for water-production applications.

Solids production is usually most severe the first few weeks after a coalbed-methane well is brought on production. PC pumping systems usually can effectively handle the sand and coal particles contained in the produced water. However, some coal particles can reach diameters of up to 20 mm [0.8 in.]. Difficulties arise when these larger coal particles become lodged in the pump, resulting in a sharp escalation in operating torque, severe tearing of the stator, or complete pump seizure. To prevent these problems, slotted pump intake or tailpipe assemblies should be installed that are sized to prevent the entry of large coal particles but to allow passage of coal fines, sand, and water. Buildup of sand and coal particles around the pump intake can decrease production rates and may cause pump failure as a result of complete blockage of the pump intake. To minimize solids accumulation around the intake, it is common for the wells to have sumps that extend up to 50 m [160 ft] below the pump. When the tubing is pulled for a workover, the well must be flushed out to ensure that the maximum volume is available for solids deposition. To prevent solids from settling out in the tubing above the pump, the transport velocity of the water must exceed the settling velocity of the solids. Because the flow losses associated with water production are normally insignificant, relatively small-diameter tubing can be used to create high flow velocities and thus enhanced solids transport capability.

By nature, coalbed methane operations produce substantial quantities of gas. Ideally, the produced gas flows up the casing/tubing annulus to the gathering facilities. In practice, however, some gas usually enters the pump, causing a corresponding reduction in efficiency (see Gassy-Well Applications section). Maintaining reasonably high pump efficiencies is especially important in coalbed-dewatering and water-source well applications because more heat is generated by pump friction than in an oil well where the produced fluids provide more lubrication. This is reflected by the fact that burnt pumps are a most common mode of pump failure in dewatering applications. As a result, it is important to keep gas away from the pump intake and to carefully monitor for pumped-off conditions. The pump intake should always be located below the perforations or near the bottom of openhole well completions to encourage natural gas separation. It is not uncommon for pumps to be seated up to 100 m [325 ft] below the perforations in coalbed-methane wells. In some coalbed-methane operations, the produced gas may contain a fairly high percentage of CO2, which, as noted, can cause elastomer swelling and rapid decompression problems. In such cases, it becomes even more important to limit gas flow through the pump, although the elastomer selection and pump sizing should take potential swelling into consideration.

To achieve economic gas rates in most coalbed operations, the pressure (i.e., fluid level) at the coal seam must be maintained at a very low level. It is not uncommon for pressures to be as low as 140 kPa [20 psi], which equates to a fluid column above the perforations of only 14 m [45 ft]. The low fluid level requirements, combined with the natural fluctuations in water flow rates from the coalbed, make it critical to use some form of pumpoff control to prevent premature pump failures. The sophistication of these systems depends on the application and can vary from basic manual to fully automated control. Typically, more elaborate systems are required for wells that either have low water flow rates or need the fluid level to be maintained near the pump intake. The most basic pumpoff control systems use some form of apparatus that senses whether water is flowing at surface. Commonly used devices include differential pressure switches and hot-wire anemometers mounted in the flowline near the wellhead. Once a low-flow condition is detected, the control system will usually shut down the pumping system. Some systems will subsequently have to be manually restarted; other more sophisticated systems will automatically restart the well after a certain time delay.

Elevated-temperature applications can be divided into medium- and high-temperature categories. The medium-temperature category covers deeper-well applications with natural, higher-temperature reservoir conditions ranging from 40°C [104°F] to ≈ 100°C [212°F]. Field experience has proved that PC pumps can be used successfully in wells producing fluids within this temperature range if the fluid temperatures remain relatively constant. However, to achieve reasonable run lives in such wells, additional attention must be given to elastomer and pump model selection, pump sizing practices, and system operation. The importance of these considerations rises substantially as temperatures increase toward the higher end of this range. In such applications, some additional investigations should be undertaken to assess the effects that elevated temperatures may have on the compatibility of the selected elastomer and the produced fluids. Stator elastomer debonding problems may be encountered in wells producing high-water-cut fluids at bottomhole temperatures exceeding ≈ 85°C [185°F].

Applications that fall into the high-temperature category (temperatures > 100°C [212°F]) include many geothermal wells and most thermal recovery operations. Thermal operations include mature steamfloods in which the temperatures are also relatively constant but may be as high as 200°C [400°F]; cyclic steam operations in which the temperatures can be even higher and typically change substantially; and steam-assisted gravity-drainage wells, which may operate over a wide range of high-temperature and -pressure conditions. Currently, such high-temperature applications pose significant challenges to routine PCP system use, and most of the relevant experience to date has been acquired through various experimental projects. Although the results from high-temperature tests conducted recently by various PC pump manufacturers under controlled laboratory conditions have shown considerable improvement and promise, caution is warranted in translating such results to a field application because other factors besides temperature may affect performance under the downhole operating conditions. Nevertheless, given the potential market, both equipment manufacturers and operators continue to actively pursue alternative pump design and elastomer developments to effectively extend the service temperature range of PC pumps for such applications.

Although the tolerance that elastomers have for high temperatures varies significantly with formulation, the different elastomers used in PC pumps will all begin to experience permanent chemical and physical changes with continued exposure to temperatures above their respective limits. These changes may cause the elastomer to become hard, brittle, and cracked and in some cases to shrink, which typically results in rapid deterioration in pump performance. In addition, the susceptibility of elastomers to damaging chemical attack always increases with higher temperatures. A general assessment of the values in the product literature from several different PC pump vendors indicates that the temperature limit for NBR elastomers is typically 100°C [212°F]; the limits for HNBR elastomers are 125°C [265°F] (sulfur cured) and 150°C [318°F] (peroxide cured); and for FKM elastomers, 200°C [425°F]. High temperature resistance typically comes at the expense of other desirable attributes, such as good mechanical properties (e.g., abrasion resistance), and these requirements often limit elastomer selection.

Severe problems with the sizing and performance of PC pumps are most common when the producing temperatures in a well fluctuate substantially. Although different-sized rotors may be interchanged to compensate for gradual temperature changes over several months, installation of PC pumps in wells in which the bottomhole temperature varies regularly by > 15°C [27°F] is usually not recommended.

The thermal expansion coefficient of elastomers is approximately an order of magnitude higher than that of steel; therefore, temperature changes cause stator elastomers to expand and contract far more than the steel tube housing or the mating steel rotor. The stator housings are also much stiffer than the elastomeric sleeve, so the thermal expansion of the elastomer leads to inward deformation and distortion of the pump cavity. The magnitude of the distortion is proportional to the elastomer thickness at any given point on the pump cross section. Fig. 15.41 shows the change in stator cavity geometry with increasing thermal expansion of the elastomer. It is important to understand that thermal expansion changes are independent of any fluid-induced swell effects, which can exacerbate pump sizing problems. As a result, some vendors now offer high-temperature bench-testing capabilities as a means to eliminate elastomer thermal expansion as a parameter to be addressed indirectly in the sizing of PC pumps. Because pump performance and fit are highly dependent on temperature, caution should be exercised when bench-test results from different vendors are compared to ensure consistency among test parameters.

Constant Bottom-Hole Pressure (CBHP) is the methodology within MPD, whereby bottomhole pressure is kept constant at a specific depth, with the rig mud pumps on or off.

In conventional drilling when the pumps are stopped in a very narrow drilling window, the bottom-hole pressure drops to a value below the pore pressure and an influx may be taken. Once the pumps are brought up back to drilling speed, the friction brings the bottom-hole pressure up to a level where the fracture pressure of the rock is exceeded and losses are encountered. The only option during conventional drilling is to drill with a reduced pump rate. Reduced pump speed, though temporarily controls the problem, slows down the drilling process since ROP needs to be controlled to reduce the risk of loading up the well with cuttings, delaying the completion of the well and increasing the risk of stuck pipe.

In order to stay within the drilling window, it is required to reduce the bottom-hole pressure variations between the circulating and non circulating modes. Using the MPD choke pressure to make adjustments on surface allows for better control of the bottom hole pressure.  Some surface backpressure is held as the pumps are stopped to keep the bottom hole pressure above the pore pressure and to avoid a potential influx.  As the pumps are brought up to speed, the choke pressure is lowered, thus allowing the friction to control the bottom hole pressure. Before the next connection is to be made, the choke pressure is once again increased to compensate for the loss of the friction and maintain the bottom hole pressure above the pore pressure. This procedure is illustrated in figure below and allows to maintain an almost constant bottom hole pressure at all times.

Precise flow modeling and hydraulic analysis are essential to evaluate alternative mud weight scenarios with MPD to reduce the static mud weight and the ECD at the modeled flow rates, rotary speed, and penetration rates. The use of well monitoring tools/equipment, specifically flow meters allows determining the actual required mud properties and backpressure on site.

Pressurized Mud-Cap Drilling (PMCD) refers to drilling with no returns to surface where an annulus fluid column, assisted by surface pressure, is maintained above a formation that is capable of accepting fluid and cuttings. The well is controlled by using a Light Annular Mud (LAM) that has a slightly lower density than is required to balance the formation pressure and is maintained above an open-hole formation that is taking all injected sacrificial (SAC) fluid and drilled cuttings assisted by surface pressure. The LAM density is chosen based on ability to make LAM and the desired surface pressure that can be maintained and observed. Periodically injecting more of the same fluid into the annulus provides a means to control the surface backpressure within the operating limits of the Rotating Control Device (RCD) and/or riser system. The annular fluid is injected at a rate high enough to ensure that gas is not migrating up the annulus. The injection rate and associated annular velocity are designed to stop gas migration to surface and to force any formation gas back into the well – effectively bullheading the gas back into the formation.

Pressurized Mud-Cap Drilling is a time-tested technique to safely penetrate the formations difficult or impractical to drill with other methods. PMCD is widely used in fractured or carbonate reservoirs that experience total fluid losses. Large volumes of sacrificial fluid are required and specialized rig modifications are minimal for PMCD operations. PMCD allows to keep dangerous gasses like H2S downhole, thus considerably enhancing the safety of the project.

Each fluid has different physical properties that must be taken into consideration when sizing and selecting a pump. The most important physical properties are suction pressure, specific gravity, viscosity, vapor pressure, solids content, and lubricity.

Positive displacement pumps add energy to a fluid by applying force to the fluid with a mechanical device such as a piston, plunger, or diaphragm. There are two types of positive-displacement pumps:

Reciprocating pumps use pistons, plungers, or diaphragms to displace the fluid, while rotary pumps operate through the mating action of gears, lobes, or screw-type shafts.

Kinetic Energy Pumps (energy associated with motion) is added to a liquid to increase its velocity and, indirectly, its pressure. Kinetic-energy pumps operate by drawing liquid into the center of a rapidly rotating impeller. Radial vanes on the impeller throw the liquid outward toward the impeller rim. As liquid leaves the impeller, it comes in contact with the pump casing or volute. The casing is shaped to direct liquid toward a discharge port. The casing slows the liquid and converts some of its velocity into pressure. There are three classes of kinetic-energy pumps:

Centrifugal pumps account for more than 80% of pumps used in production operations because they exhibit uniform flow, are free of low-frequency pulsations, and are not subject to mechanical problems. Fig. 1 illustrates pumps commonly used in upstream production operations.

Values are required at pumping conditions and, in some cases, at ambient conditions as well. The next step is to calculate available suction conditions such as rated suction pressure, maximum suction pressure, and net positive suction head available (NPSHA). (See Hydrodynamics for information on NPSHA.) Once the available suction conditions have been established, the effect of the selected control system on pump performance requirements must be determined (see Regulation of Flow Rate). The next step is to calculate the minimum discharge-pressure requirements of the pump. The last step is to calculate the total dynamic head (TDH) at the specific gravity corresponding to rated pumping temperature.

The first step in mechanical design is to determine the design pressure and temperature required for the pump and its associated piping. Once this is done, a pump type and materials of construction are selected. The next step is to determine the sparing (backup) requirements, the need for parallel operation and control-system details. Then select a shaft-seal type and determine the requirements for an external flushing or sealing system and estimate the power requirements and choose a driver (motor, engine, or turbine) for the pump. Lastly, document the design by including calculations, studies, design specifications, utility requirements, and estimate summary.

Operating pressure is expressed in feet of the liquid that is being pumped. Suction and discharge pressures are expressed as suction head and discharge head, respectively. Pressures are expressed in feet of head, because it is more important to know how much a pump can raise the liquid it is pumping, rather than the amount of pressure the pump is adding to the liquid.

Fig. 3 illustrates the relationship between static head, static lift, and submergence. Static head is the vertical distance between a liquid level and a datum line, when the supply is above the datum. Static lift is the vertical distance between a liquid level and a datum level, when the datum is above the liquid. Datum line is the centerline of the pump inlet connection, or the horizontal centerline of the first-stage impeller in vertical pumps.

A pump that develops a perfect vacuum at its suction end can lift a column of water 34 ft. This vertical distance is called theoretical lift. The pressure to lift the liquid comes from atmosphere pressure. At sea level, atmosphere pressure is approximately 14.7 psia.

Because a perfect vacuum is never achieved and because some lift is lost to friction in the suction line, the maximum actual suction lift for a positive-displacement pump is approximately 22 ft. The maximum actual suction lift for a centrifugal pump is approximately 15 ft when pumping water from an open air tank. Positive-displacement pumps can operate with lower suction pressures or high suction lifts because they can create stronger vacuums. Suction lift will be greater if the pressure in a closed tank is greater than atmospheric pressure.

Submergence is often confused with either suction static head or static lift. For vertical pumps, submergence relates the liquid level to the setting of the pump. For horizontal pumps, submergence relates to the height of liquid level necessary in the source vessel or tank to prevent the formation of vortexing and the resulting flashing of vapors in the pump suction.

The amount and type of suspended solids entrained in the liquid can affect the characteristics and behavior of that liquid. Increased concentrations of solids increase the specific gravity, viscosity, and abrasiveness of a liquid. The type and concentration of suspended solids can affect the style of pump selected and the materials of construction. Suspended solids also affect the selection of impeller design in centrifugal pumps, which in turn affects the wear rate, efficiency, and power consumption.

Small amounts of dissolved gases have little effect on flow rate or other pumping requirements. If large amounts of gas enter the liquid through piping leaks or as a result of vortexing in vessels, the specific gravity of the liquid will decrease. Dissolved gases can also reduce the amount of NPSHA at the pump suction. (See Hydrodynamics for a discussion of NPSHA).

Viscosity offers resistance to flow because of friction within the fluid. Viscosity levels have a significant impact on pump type selection, efficiency, head capacity, and warm-up. High-viscosity liquids decrease a centrifugal pump’s efficiency and head performance, while increasing the power requirements. The viscosity of all liquids varies with temperature. For viscosities of liquids, refer to standard industry references (e.g., Hydraulic Institute Engineering Data Book

The corrosive nature of the fluid being pumped has a bearing on pump type selection, materials of construction, and corrosion allowance. Special mechanical seals and flushing arrangements may be required.

hf = friction loss between points 1 and 2. Subscripts 1 and 2 refer to locations along a pipe. An examination of each of the terms in Eq. 3 provides a better understanding of the general equation for modeling a pumping system.

The velocity head increases the amount of work required of a pump. The velocity head is usually not included in actual system calculations when piping velocities are kept within the prescribed limits of 3 to 15 ft/sec. The velocity head is included in the total dynamic head on the centrifugal-pump curves.

Control losses occur on the discharge side of a centrifugal pump that has been equipped with a backpressure valve to control flow rate. As the liquid flows through the control valve, energy is lost. Next to static head, control losses are frequently the most important factor in calculating the pump’s total dynamic head. For pump applications, control losses are treated separately from head losses, even though they are included in the hf term in Eq. 3.

Acceleration head is used to describe the losses associated with the pulsating flow of reciprocating pumps. Theoretically, acceleration head should be included in the hf term of Eq. 3. The Hydraulic Institute Engineering Data Book

TDH is the difference between the pumping system’s discharge head and suction head. It is also equal to the difference in pressure-gauge readings (converted to feet) across an existing operating pump (discounting velocity head).

Suction head is defined as the sum of the suction-vessel operating gauge pressure (converted to feet), the vertical distance between the suction-vessel liquid level and the pump reference point, less head losses in the suction piping [discounting change in velocity,

Discharge head is defined as the sum of the discharge-vessel operating gauge pressure (converted to feet), the liquid level in the discharge vessel above the pump reference point, pressure drop because of friction in the discharge piping, and control losses (discounting velocity head). It can be expressed as

NPSH is defined as the total suction head in feet of liquid (absolute at the pump centerline or impeller eye) less the vapor pressure (in feet) of the liquid being pumped.

Net positive suction head required (NPSHR) is defined as the amount of NPSH required to move and accelerate the liquid from the pump suction into the pump itself. It is determined either by test or calculation by the pump manufacturer for the specific pump under consideration. NPSHR is a function of liquid geometry and the smoothness of the surface areas. For centrifugal pumps, other factors that control NPSHR are:

NPSHR is determined on the basis of handling cold water. Field experience coupled with laboratory testing have confirmed that centrifugal pumps handling gas-free hydrocarbon liquids and water at elevated temperatures will operate satisfactorily, with harmless cavitation and less NPSHR than would be required for cold water.

NPSHA must be equal to or greater than NPSHR. If this is not the case, cavitation or flashing may occur in the pump suction. Cavitation occurs when small vapor bubbles appear in the liquid because of a drop in pressure and then collapse rapidly with explosive force when the pressure is increased in the pump. Cavitation results in decreased efficiency, capacity, and head and can cause serious erosion of pump parts. Flashing causes the pump suction cavity to be filled with vapors and, as a result, the pump becomes vapor locked. This usually results in the pump freezing up, which is called pump seizure.

When a new system offers insufficient NPSH margin for optimum pump selection, either the NPSHA must be increased, the NPSHR must be decreased, or both. To increase the NPSHA, one can raise the liquid level, lower the elevation of the selected pump, change to a low-NPSHR pump, or cool the liquid. To reduce the NPSHR, one can use different design impellers or inducers or use several smaller pumps with lower NPSHRs in parallel.

When an existing pumping system exhibits insufficient NPSH margin, it is too late to use these solutions without going through an expensive change. Most of these problems can be traced to suction flow restrictions (orifice plates, plugged strainers, partially closed valves, etc.) and inadequate source-tank liquid levels.

This page discusses the specific artificial-lift technique known as beam pumping, or the sucker-rod lift method. Many books, technical articles, and industry standards have been published on the sucker-rod lift method and related technology.artificial lift system. The Gipson and Swaim “Beam Pump Design Chain” is used as a foundation and built upon using relevant, published technology.

Beam pumping, or the sucker-rod lift method, is the oldest and most widely used type of artificial lift for most wells. A sucker-rod pumping system is made up of several components, some of which operate aboveground and other parts of which operate underground, down in the well. The surface-pumping unit, which drives the underground pump, consists of a prime mover (usually an electric motor) and, normally, a beam fixed to a pivotal post. The post is called a Sampson post, and the beam is normally called a walking beam. Figs. 1 and 2 present a detailed schematics of a typical beam-pump installation.

This system allows the beam to rock back and forth, moving the downhole components up and down in the process. The entire surface system is run by a prime mover, V-belt drives, and a gearbox with a crank mechanism on it. When this type of system is used, it is usually called a beam-pump installation. However, other types of surface-pumping units can be used, including hydraulically actuated units (with and without some type of counterbalancing system), or even tall-tower systems that use a chain or belt to allow long strokes and slow pumping speeds. The more-generic name of sucker-rod lift, or sucker-rod pumping, should be used to refer to all types of reciprocating rod-lift methods.

Linked rods attached to an underground pump are connected to the surface unit. The linked rods are normally called sucker rods and are usually long steel rods, from 5/8 to more than 1 or 1 1/4 in. in diameter. The steel rods are normally screwed together in 25- or 30-ft lengths; however, rods could be welded into one piece that would become a continuous length from the surface to the downhole pump. The steel sucker rods typically fit inside the tubing and are stroked up and down by the surface-pumping unit. This activates the downhole, positive-displacement pump at the bottom of the well. Each time the rods and pumps are stroked, a volume of produced fluid is lifted through the sucker-rod tubing annulus and discharged at the surface.

Sucker-rod pumping systems should be considered for new, lower volume stripper wells, because they have proved to be cost effective over time. Operating personnel usually are familiar with these mechanically simple systems and can operate them efficiently. Inexperienced personnel also can operate rod pumps more effectively than other types of artificial lift. Most of these systems have a high salvage value.

Understanding the makeup of the producing reservoir, its pressure, and the changes that occur in it are important to attain maximum production. Because reservoir conditions change as fluids are produced, ongoing measurement of the reservoir conditions is necessary. The main considerations in measuring and understanding the reservoir are the types and volumes of reservoir fluids being produced, their pressures in both the reservoir and at the wellbore or pump intake, and the effects these fluids have as they pass through the producing system.

A variety of well tests and measurements may be used to determine production rates for oil-, gas-, and water-supply wells and to observe the status of the reservoir. Each test reveals certain information about the well and the reservoir being tested. The main reservoir considerations are determining bottomhole pressure and the inflow relationship of the fluids with changing reservoir and pump-intake pressure.

Bottomhole pressure measuring equipment (pressure bombs) makes it possible to determine reservoir and tubing intake pressures within the desired range of accuracy. When this test is conducted at scheduled intervals, valuable information about the decline or depletion of the reservoir from which the well is producing can be obtained. However, it is difficult to obtain either bottomhole reservoir or operating pressures while the rod-pump system is installed and operating.

The key to accurate bottomhole pressure determination in any pumping well is the ability to predict the gradient of the fluid in the casing/tubing annulus. In 1955, W.E. Gilbert (Unpublished internal report: “Curve Annulus Gradient Correction for Gas Bubbling Through Static Liquid Column,” Shell Oil Co.) developed an iterative calculation procedure on the effect of gas bubbling up a static fluid column. This can be used in a trial-and-error method to determine a gradient correction factor (F) to determine the pressure at the desired depth in the presence of gas production. If the term Q /(aP)0.4 is greater than 0.25, this method should be used with caution because this is an indication that liquid flow up the annulus may occur. Also, the crude pressure/volume/temperature (PVT) characteristics alter the results. The Gilbert curve and a calculation example are presented in "The Beam Pump Design Chain."

Knowing the reservoir and pump intake pressures during static and operating conditions will allow a determination of the well"s production capacity. This is required to optimize the artificial-lift equipment and properly size the equipment that is installed. The well productivity under varying production conditions must then be known.

One of the most critical decisions in an artificial-lift system is the selection and design of equipment appropriate for the volume of fluid the reservoir produces. Reservoir inflow performance detaisl the productivity index and IPR of fluids with changes in reservoir pressure. Because most fluid produced by an artificial lift method is not single phase, it is not in a steady-state condition. Also, because most pumping operations occur after the fluid is below the bubblepoint pressure, the IPR method is usually considered. This technique takes into account various fluid phases and flow rates. It was originally devised by Vogel

Producing rates can be estimated within the desired range of accuracy using the IPR technique with two stabilized producing rates and corresponding stabilized producing pressures. This makes it possible to use the IPR without needing to shut in the well and lose production to obtain shut-in information. Obtaining a bottomhole pressure equal to 10% of the shut-in reservoir pressure is recommended for determining maximum production rates for sucker-rod lifted wells. At this pressure, the maximum well productivity will be 97% of the well"s theoretical maximum production rate. However, the maximum lift-design rate should, in most cases, be slightly higher to permit some downtime and decreased pump efficiency.

In any artificial lift system, the volume of gas produced should be considered in designing the system and in analyzing the operation after the system has been installed. A complete analysis requires knowing the volume of gas in solution, the volume of free gas, the formation volume factors, and whether gas is produced through the pump or is vented. If PVT analyses of reservoir fluids are available, they are the most accurate and easiest to use as a source of solution gas/oil ratio (GOR), formation volume factors, etc. The next best source is an analysis from a nearby similar reservoir.

When pumping through tubing in the absence of a production packer, free gas, which breaks out of the oil, should be vented up from the casing/tubing annulus. However, when it is necessary to produce from beneath a production packer, a vent string can be installed. The possibility of needing a vent string should be considered when planning casing sizes for a new well.

Both the size of the vent string and the location of its bottom, with respect to the location of the pump intake and producing perforations, will influence the string"s effectiveness in removing free gas. The string"s diameter should be designed to allow the production of the anticipated free-gas volume with a pressure drop no greater than the desired producing bottomhole pressure minus the surface backpressure. If the required pressure drop is greater than this, a portion of the free gas will have to go through the pump. Fig. 2 is an indication of the effect of vent-string size on the pressure drop through it. Care should be taken if small-diameter tubing is used, because it may not allow all the gas to flow up the vent or may simply load up and prevent most gas flow.

Gas that remains in solution when the liquid enters the pump increases the volume of total fluid through the pump compared to the liquid measured at the surface by the formation volume factor at pump-intake conditions. The gas also decreases the density of the fluid and, thus, the head or pressure to be pumped against in the tubing. Free gas that enters the pump must be compressed to a pressure equivalent to the head required to lift the fluid. This free gas will reduce the volume of both the produced liquid that enters the pump and the liquid measured at the surface. Any time the pump does not compress the free gas to a pressure greater than that exerted on the pump by the fluid column in the producing string, production ceases and the pump is said to be "gas locked." This condition can exist in both plunger and centrifugal pumps.

Intake pressure is the pressure in the annulus opposite the point at which the fluid enters the pump. If the pump intake pressure is increased by increasing the pump submergence, the free gas volume decreases because the fluid retains more gas in solution. Reducing the pressure drop in the pump-suction piping also reduces the free gas to be produced. The pump intake should not be deeper than is necessary to maintain the desired intake pressure. A pump intake that is too deep results in unnecessary investment and increased operating costs.

Fig. 3 is a graph of the liquid produced as a percent of the displacement of a plunger pump plotted against the pump intake pressure for a typical reservoir.

Fig. 3—Example of liquid produced as a percentage of plunger-pump displacement for various pump-intake pressures and the effects of gas on efficiency.

Gas bubbles entrained in the produced liquid(s) tend to rise because of the difference in the liquid and gas densities. The rate of bubble rise depends on the size of the bubbles and the physical properties of the fluid. The size of the bubbles increases as the pressure decreases. At low pump-intake pressures, the rate of gas-bubble rise in low-viscosity fluids will approximate 0.5 ft/sec, assuming a 400-μm bubble rise in water. The increase in bubble size and rate of rise as the pressure decreases causes the reversal in curves B–D and B–E in Fig. 3.

Downhole gas separators are used in gassy wells to increase the volume of free gas removed from the liquids before reaching the pump. However, they are not 100% effective in separating the gas. In sucker-rod-pumped wells, these separators are normally called "gas anchors." Gas anchors are usually designed and built in the field; Fig. 4 contains schematic drawings of six common types. The most commonly used are the "natural" gas anchor (A) and the "poor boy" gas anchor (C). Typically, there are two major components for these gas anchor assemblies, the mud anchor run on the bottom of the tubing string and the dip tube or strainer nipple run on the bottom of the pump.

The largest downhole gravity separator is normally the casing/tubing annulus. This area provides a maximum down passage for liquid and up-flow area for gas. This allows the oil (and water) to move relatively slowly, typically, downward from the perforations to the pump, and permits the gas to separate and flow upward. For this reason, a natural gas anchor should be used whenever practical because it takes advantage of the entire casing internal cross-sectional area. This type of separator typically should be placed approximately 15 ft below the lowest most-active well perforations. However, if there is insufficient distance in the well to place the pump intake below the perforations, then the pump intake should be placed approximately 15 ft above the top-most perforation and a poor boy separator should be properly designed and installed.

There are limitations on how much gas can be handled by the downhole separator. If more gas is produced than can be handled by the separator, the gas will not separate completely. The downhole pump must then handle the excess gas. If the wells exceed these theoretical gas rates, then:

The situation worsens if excessive gas enters the pump and there is insufficient compression ratio to pump all the fluids, resulting in a gas-locked pump. When this occurs, operating costs for this well increase dramatically because when there is no production, there is no revenue. However, a properly designed and spaced pump should not gas lock if the well is not pumped off.

It is often recommended that the outside diameter (OD) of the gas anchors" steel mud anchor be less than the ID of the largest overshot or wash pipe that can be run in the well casing. This limits the gas-anchor separation capacity that can be secured in wells with small casings. Reinforced plastic mud anchors that can be drilled up, or steel designs that can be recovered with spears, should be considered when mud anchor OD must approach casing-drift diameter. This design would then be considered the "modified poor boy." Agreement should be obtained from the field before installation to ensure acceptance of the possible problems when trying to pull this type of installation.

In 1954, an in-depth study of the complex aspects associated with sucker rod pump design was started. Through this effort, Sucker Rod Pumping Research, Incorporated, a non-profit organization was created. The services of the Midwest Research Institute at Kansas City were retained to perform the work necessary to achieve the objectives of the organization. Midwest Research Institute published its report in 1968, which was then used to create the industry standard API RP 11L. Gipson and Swaim did an excellent job of summarizing a sucker-rod lift-system design in The Beam Pump Design ChainRP 11L approach. API RP 11L is superseded by API TR 11L. This recommended practice should be consulted for continued discussion of this equipment, along with a review of a sample problem and a recommended solution. Prior to this, Gibbs (1963) introduced a solution for wave equation that simulates force wave propagation through sucker rod string. The approach has been enormously updated since then by multiple authors to consider further details of the physics of the phenomena and to enhance capturing the effect of fluid properties. . The approach has become the base for multiple commercial beam pump design software.

In summary, use the design procedure presented in API TR 11L or a suitable wave equation. Several commercial wave-equation computer programs are available that many operators have successfully used. In the following, the beam pump design procedure based on API TR 11L is introduced. Further details are found in Takacs (2015).

Due to the elasticity of the rod, the rod string might strength or contract through the pumping cycle. This results in a downhole stroke length at the plunger "Sp" that slightly differs from the design stroke length S. This difference results in an actual flow "qa" that is different from the design flow rate "q". Based on API TR 11L, the rod stretch is predicted. "qa" is then calculated and is compared to the desired "q". The optimum "q" can then be reached with an iterative procedure. The procedure or this calculation stats with determining the theoretical flow rate "q" from the pump speed "N", surface stroke length "S" , and plunger size "dp" as follows,

A primary selection of rod string design is required. Firstly, the total length of rod string approximately equals the pump setting depth L in non-literal wells. Moreover, the configuration of rod string diameters is determined from a standard set of configurations provided in API RP 11L. The standard provides a table of the characteristics of the ta