Operational Performance of Shale Shakers

1.1.1.1.          Shale Shakers

Since the advent of  Shaffer vibratory mud screens in the 1930’s (American Association of Drilling Engineers, 1999d), the shale shaker has been the dominant device for primary-solids removal (Aase et al., 2013). Generally, shale shaker equipment acts as the first stage in the remediation of solids-laden drilling fluid returning from the wellbore. Drilling fluid flows over meshed screens which are sized to separate the desired range of cuttings sizes from the fluid. Due to the rheological properties of the fluid, an acceleration is applied to the screen via a vibratory motion to facilitate high rates of fluid flow and cuttings removal (American Association of Drilling Engineers, 1999a).  The upward motion of the shaker screen forces fluid downward through the shaker openings and moves solids upward. When the screen moves on the downward stroke, solids do not follow the screen. They are, instead, propelled along the plane of the shaker screen where they are discarded from the system. Operational performance of shakers is generally assessed with respect to two key metrics: fluid limit and solids limit. The two metrics are inversely proportional with respect to rate; as the volume of fluid processing rate increase, the volume of solids decreases and vice versa (ASME, Merrill, & Robinson, 2005). With respect to equipment design, the rate at which fluids and solids can be processed via the shaker is directly influenced by vibrational motion, applied g-force, and design of the shaker’s screening beds (American Association of Drilling Engineers, 1999c). Furthermore, the rheological properties of the fluid itself may also influence the shaker systems ability to separate drilled solids from the fluid (ASME, Merrill, et al., 2005)

1.                      Path of Applied Motion

Since the adoption of shaker technology from the mining industry in the early 1930’s, modern shakers have witnessed distinct eras of technological development with respect to vibrational motion that is applied to the shaker screens. These developmental time frames can be divided into four main categories that include unbalanced elliptical, circular, linear, and balanced elliptical motion of the shaker beds (ASME, Merrill, et al., 2005). Each of which has offered incremental improvements in the minimum mesh size and the subsequent range of particle sizes separated from the drilling during processing.

1.   Unbalanced Elliptical Motion

The type of motion imparted to the shaker depends on the location, orientation, and a number of vibrators used. Unbalanced elliptical motion shakers accomplish motion of the screen bed through use a single vibrator consisting of counterweights mounted on an elliptical drive shaft. As seen in Figure 15, the rotating shaft assembly is located directly above the deck's center of gravity during operation, imparting a combination of elliptical motion at the ends and circular motion at the center of the shaker bed. The design of unbalanced elliptical motion shakers generally requires adjustment to the deck of the shaker screen to facilitate better conveyance of the cuttings to the discharge end of the screen. As seen in Figure 16.A, if left in a leveled state, the orientation of the elliptical motion axes at the discharge end of the screen imparts a thrust motion towards the feed end of the screen, making solids discharge from the shaker more difficult. To assist in solids conveyance, the major axis of the ellipsoidal trace to be directed toward the solids discharge end by tilting the discharge end downward as seen in Figure 16.B. This is done to counteract the effect cuttings piling at the end of the shaker’s discharge without compromising residence time (American Association of Drilling Engineers, 1999c).

2.   Circular Motion

In the mid-1960's, Baroid introduced shaker technology that utilized tiered screens as well as the circular motion of the shaker beds. Circular motion in shaker beds is accomplished via mechanisms similar to those used in unbalanced elliptical shakers. Except, instead of using an elliptical drive shaft, the design employs a concentric shaft fitted with counterweights located over the center of the shaker beds, which provides pure circular motion along the entire length of the vibrating deck (American Association of Drilling Engineers, 1999c). As illustrated in Figure 17, drilling fluid and cuttings are fed over a course meshed screen bed where the fluid containing finer solids are removed from the large cuttings that are conveyed of the upper screen of the shaker. Fluids passed through the upper screen bed onto a flow back tray that conveys the fluid to the beginning of the second screen bed to provide ample residence time during separation of the smaller cuttings (American Association of Drilling Engineers, 1999c). The circular motion reduces the reversed thrust effect witnessed in unbalanced elliptical shakers and transports drilled solids horizontally across the screen more effectively. Furthermore, the implementation of a tiered screen bed reduces cuttings load on the finer meshed screens in the lower tiers. Thus, reducing the loss of liquid without compromising conveyance (ASME & Robinson, 2005)

3.   Linear Motion

Introduction of linear motion shaker systems in the 1980's, presented improvements in the conveyance of solids throughout the vibratory cycle due to the resulting bed motion acting linearly rather than elliptical or circular (Patent #). As illustrated in figure 18, The linear motion of the shaker bed is imparted by a pair of counter-rotating, eccentrically weighted, parallel vibrator shafts (PATENT). The forces generated through the rotation of the eccentric masses yields a thrust along a straight line at all positions along the vibratory trace, except at the very top and bottom of each stroke (ASME & Robinson, 2005). This summation of forces results in the straight-line motion of cuttings along the surface of the shaker bed. Furthermore, to achieve the proper relationship between the rate of solids conveyance and liquid throughput, drive systems with variable mount angles have been developed to optimize the resultant motion vectors during operation. The linear motion provided by the design also allows for the conveyance of cuttings when the screen deck is tilted upward to bed angles of 6˚ inclination(American Association of Drilling Engineers, 1999c). This inclination of the fluid bed not only positively affects residence time of the cuttings on the screen, but also allows pooling to occur at flowline end of the machine. Thus, allowing for the development of a positive liquid head that acts as a drive mechanism that forces liquid and its suspended solids through finer mesh cloths (ASME, Merrill, et al., 2005). The ability to employ finer cloths during operation facilitates better maintenance the drilling fluid and improves efficiencies of downstream equipment such as hydro cyclones and centrifuges(ASME, Merrill, et al., 2005).

4.   Balanced Elliptical Motion

The difference of balanced elliptical shale shakers from their unbalanced counterpart lies in the similarity between the long axis and short axis of the elliptic motion of the screen bed (de Wardt, Rushmore, & Scott, n.d.). The ellipsoidal axes, illustrated in Figure 19, are directed toward the discharge end of the shale shaker bed through the entire duration of the vibratory cycle. Unlike conventional unbalanced elliptical and circular motion designs, whose design only communicates a portion of the generated motion toward the discharge end, balanced elliptical motion shakers provide positive conveyance of solids towards the discharge end of the screen in the same manner as linear motion shakers (American Association of Drilling Engineers, 1999c). Balanced elliptical motion is accomplished by employing one of two configurations. The first configuration (American Association of Drilling Engineers, 1999c) produces balanced elliptical motion through a pair of eccentrically weighted vibrators of differing masses that rotate in parallel during operation. The variation in size between the vibratory masses seen in Figure 20 is the differentiating factor between this type of balanced elliptical shaker and linear motion shakers. For this configuration, the ellipse aspect ratio (major axis to minor axis) is controlled by varying the difference in mass between vibrators. As the aspect ratio increase from 1.5 to 3.0 and the elliptical motion becomes more elongated the conveyance across the screen bed increases. Conversely, as the aspect ratio of the motion decreases, conveyance of cuttings across the screens slows. As seen in Figure 21, the second configuration produces motion by employing a pair of eccentrically weighted vibrators of equal mass, that are angled away from each other during counter rotation (ASME & Robinson, 2005). The aspect ratio of the elliptical motion in this system is controlled by the intensity of the angle between vibratory motors, also known as the minor axis. As the minor axis angle, or angle of vibrators relative to each other, increases, the shaker bed will produce a broader with a smaller aspect ratio that slows the solids conveyance across the screens.

2.                      Shaker G-Force

Fine screen shale shakers usually provide a "G"-factor between 4 and 6. Some shale shakers can provide as much as 8 G's. The higher the "G"-factor, the greater the solids separation possible and, generally, the shorter the screen life. (American Association of Drilling Engineers, 1999c; ASME, Barrett, & Carr, 2005) Standard shakers operate with vibratory motors running at a constant speed, yielding a constant output force. This results in a shaker having its peak g-force during non-loaded conditions. (Dorry, Dufilho, & Varco, 2012). Either increasing the stroke, rate of motor rotation, or a combination both increase the g-factor; a decrease in any of the values would yield a decrease in applied g-force. As a general guideline, the stroke is increased by the inverse square of the rpm reduction to hold the g factor constant. (ASME, Merrill, et al., 2005) Controlled acceleration technology automatically adjusts the shakers motor rpm depending on the flow condition. This eliminates operator intervention and optimizes shakers performance. The controlled acceleration technology is available for new build shakers or as an upgrade kit to shakers currently operating in the field. Shakers equipped with controlled acceleration operate at maximum g in loaded conditions and nominal g when the shaker is not loaded. This provides increased solids conveyance, higher flow capacities and the capability to screen finer in optimum g shaker operation, while enhancing motor, bearing and screen life when programmed to run at nominal g in unloaded conditions.  

3.                      Shaker Screen Sizing

For any particular shale shaker, the construction screening cloth and the subsequent the size and shape of the apertures woven in the cloth largely influence the ability to remove solids from the fluid. (ASME, Merrill, et al., 2005). Traditionally, the petroleum industry has used the mesh number to designate the number of apertures per inch within the screen (Dahl, Saasen, & Omland, 2008). Unfortunately, the specification of mesh count for a particular shaker screen is not a direct indicator of separation performance since screen opening size, not mesh count, determines the particle sizes separated by the screen (American Association of Drilling Engineers, 1999b). The designation and labeling screens have been historically controversial; screen labels do not always correctly define the separation potential of a particular mesh (Datta, Saasen, von Hafenbrädl, Haugen, & Omland, 2007). This is due to the fact that API specifications utilize a dry-sieve D100 classification process, which effectively de-rates a screen mesh due to the fact that the apertures in the mesh will be reduced when coated with drilling fluid (Morgan, 2006). Various factors including the properties of the fluid coating the wires, the operational parameters of the shaker in use, and the particle size distribution of the drilled solids presented to the screens influence the degree to which the mesh of the screen is de-rated. (Morgan, 2006) To meet API RP 13C compliance two tests are required: cut point and conductance. API RP 13C allows the end user to compare by cut point, conductance (fluid flow), and non-blanked open area. The cut point test is based on a time-proven testing method used by ASTM to classify particles by size. The shaker screen designation is identified by matching the screen’s cut point to the closest ASTM sieve cut point. The D100 separation is used for assigning screen designations. D100 means that 100 percent of the particles larger than the test screen will be retained, and all finer particles will pass through. The conductance test measures the ability of a fluid to pass through the screen. The non-blanked open area of a screen describes the net unblocked area (in square meters or square feet) available to permit the passage of fluid. After identifying the cut point and conductance, API RP 13C requires the application of a permanent tag or label to the screen that is visible and legible. Both cut point expressed as an API number and conductance displayed in kD/mm are required on the screen label. The new procedure is a revision of the previous API RP 13E, which was based on optical measurements of the screen opening using a microscope and computer analysis. Under API RP 13E, screen designations were based on individual manufacturer test methods which produced inconsistent labeling It is important to note that API RP 13C states that this test only describes the openings of the screen and does not predict the conductance of the screen after contact with drilling fluids. Conductance in screens comprised of specific mesh geometry is dominated by the dependency on the drilling fluids viscosity and, even more, by the extensional viscosity of the drilling fluid (Dahl et al., 2008). The latter is the reason that conductance can be significantly different for water- and oil-based drilling fluids. Thus, the API recommended practices focus on utilizing a method of testing to describe the openings of the cloth, rather than conductance itself. Section 4.1 of Appendix A provides values for API D­₁₀₀  mesh separation in further detail

1.   Screen Construction and Design

To ensure and maintain good filtration and the stable properties of the drilling fluid, it is important that the screens have a durable design to resist abrasive wear and fatigue caused by vibration (Aase et al., 2013). The wear on the single-layer screens results from the impact of cuttings particles hitting the screen and from the continuous bending action of the screen-cloth wires because of the shaker vibration. Furthermore, wear arising from the scratching of the cloth by the movement of the particles along the screen. (Dahl et al., 2008). To mitigate this effect, fine mesh cloths are fitted with a coarse mesh-backing screen as illustrated in Figure 22. This course-meshed screen protects the fine screen from damage, extends life, and provides additional support for heavy solids loading. (ASME, Merrill, et al., 2005). If a fine-mesh screen with damages from wear, like holes, is allowed to be used for a long period, it will, in the long term, act like a significantly coarser screen. Therefore, if there is a possibility that the fine-mesh screen may be used for an extended period of time without being changed, it is generally better to use a slightly coarser, but stronger, screen.(Dahl et al., 2008) Advances in screening technology have led to the development of pre-tensioned multilayer screen assemblies (Figure 22) that offer significant improvements to screen longevity and performance. Pre-tensioned panels consist of a single scalping layer, or multiple layers, that are tensioned in all directions and bonded to a framed support grid. The panel frames and support grids offer flexibility with regards to construction material and offer commercially frames comprised of steel, plastic, or composite materials (G N General, 2017). This prefabrication process ensures that the screens are properly tensioned before and after being placed into service. Thus, mitigating tensioning problems observed in hook-strip style screens that have since been relegated to a minor role in linear motion shakers. (ASME, Merrill, et al., 2005) Regardless of configuration, the function of the pre-tensioned panel is to provide mechanical support for the fine-screen cloth bonded to it and at the same time occlude as little potential flow area as possible with the supporting grid structure (American Association of Drilling Engineers, 1999b). Depending on the manufacturer of the shaker, geometric apertures in screen panel vary in design and are found with square, rectangular, hexagonal, and oval patterns that comply with API RP 13C guidelines.

1.1.1.2.          Alternative Shaker Technology

Experience in recent years has demonstrated that, although dependent on correct operational procedures, several types of shale shakers have sufficient performance to act as the sole solids-control devices without the use of desanders and desilters. Despite often being the only measure for solids removal, the selection of shale shakers, the screening, and the establishment of operational procedures are often based on biased information (Dahl et al. 2006).

1.1.1.3.          Fluid Degassing

The physical separation of liquid–gas flows is an integral part of industrial processes that include oil recovery, chemical processing, and nuclear plants (Xu, Yang, Wang, & Wang, 2015). Separation is necessary for drilling fluid processing as it reduces problems associated with the reduction in fluid density when gas is present in the mud. Furthermore, for solids control equipment to function properly, the gas cut drilling fluid must be processed before entering the pumps that feed the desander, desilter, and mud cleaner. (Bouse & Carrasquero, 1992). Failure to remove entrained gas from drilling fluid can result in premature failure of centrifugal pumps, and decrease overall efficiency fluid processing during drilling. Due shale shakers inability to effectively remove gas or air from drilling fluids, the remediation of entrained gas is accomplished through the use of an atmospheric, vacuum, or centrifugal degassing unit located downstream from the shakers on top of the removal section of the mud tanks. (ASME, Peard, Steen, & Stefanov, 2005).

1.                      Vacuum Degassers

Of the various types units available, vacuum degassers are the most prominent means of removing gas from drilling fluid and can be found in either a vertical or horizontal configuration depending on manufacturer and spatial availability on the rig site. Generally, vertical configurations are more spatially efficient and lighter than their horizontal counterparts and can achieve similar volumetric throughputs seen in horizontal configurations, given that the centrifugal pump powering the eductor is adequately sized. If the centrifugal motor or eductor is improperly sized, the system will observe a decrease in processing capacity due to the insufficient power needed to overcome lifting the fluid from the tank to the degasser (ASME & Rehm, 2005).  Dimensional sizing, weights, and subsequent throughputs of horizontal and vertical degassing systems are located in detail in Appendix XX. Both vertical and horizontal vacuum degassers mitigate gas entrainment by subjecting the drilling fluid to an environment under partial vacuum (ASME & Rehm, 2005). The reduction of atmospheric pressure within the vessel is achieved and maintained through the employment of either a secondary vacuum pump or systems of Venturi style eductors (Liljestrand, 1977). In either case, drilling fluid is drawn into the vessel through the use of a single eductor which powered by degassed fluid that is drawn from one of the forward tank compartments. As illustrated in Figure 23, the separation of gas from the fluid is achieved when fluid is drawn into the vessel and dispersed as a thin film over a series of baffles where the fluid forms a thin film. The film allows the gas bubbles within the fluid to expand, coalesce, and eventually rupture, which allows the mitigated gas to be discharged for disposal (R. F. Mitchell & Miska, 2011).

1.                      Atmospheric Degassers

Unlike vacuum degassers which employ reduced atmospheric pressure to mitigate gas from drilling fluid, atmospheric degassing units remediate gas from the fluid via impact forces generated during by the flow of fluid during operation. Gas laden fluid is drawn into a riser pipe via a submerged pump impeller that is located in the shale shaker discharge tank. The fluid is accelerated through the riser and discharged at high velocity against baffles located in the unit’s spray tank. The impact of the fluid against the baffling results in the formation of a thin fluid film that subsequently impacts the wall of the spray tank. As the film impacts the tank wall, the resulting forces and turbulence bring gas bubble to the surface of the fluid where they are allowed to escape. The degassed fluid collects at the base of the spray tank and flows out of the discharge trough to the next pit. The gasses escape through the top of the spray tank and dissipate into the atmosphere.

1.                      Centrifugal Hydrocyclone Degassers

As opposed to a conventional vacuum or atmospheric impact systems, centrifugal degassers invoke cyclonic rotation that forces the denser liquid phases of the fluid outward while the less dense gas particles remain in the middle section fluid vortex. As illustrated in Figure 25., drilling fluid is drawn into the unit via submerged impeller; the tangential forces imparted by the impeller form a vortex of drilling fluid on the outer walls of the unit. Formation of the fluid vortex multiplies the force acting on the gas bubbles to increase buoyancy and release, accelerating the bubble-rise velocity. As gas reaches the surface, it accumulates in the void at the center of the fluid vortex and is then pumped from the unit for disposal, while the remediated fluid exits ports at the top of the unit and is returned to the active fluid system.  

1.1.1.4.          Desanding and Desilting Hydrocyclones

After drilling fluid processing drilling fluids over the shakers and through the degasser, there is a possibility that the fluid still contains appreciable amounts of drilled solids that need to require removal before the fluid is mixed and recirculated into the wellbore. Increased drill-solids content of drilling fluids leads to effects rheological degradation including increased viscosities, higher filtration rates, increased filter-cake thickness (Robinson & Heilhecker, 1975). Furthermore, excess drilled solids content can lead to excessive wear on the bit and pumping components (King, 1959). Mitigation of drilled solids that are too fine for shale shakers can be achieved through the use of hydrocyclone technology that has been historically employed for processing of produced fluids in offshore exploration (Ditria, 1994), stock preparation of virgin pulp for paper (Holik & Stetter, 2006), and processing of starch milks in various food industries (Trim & Marder, 1995). Generally, Hydrocyclones as in Fig. 1, are widely used for the separation of materials normally in the form of solid particles (Park, Yoon, Lee, & Kwon, 2005). In principle, hydrocyclone technology is a purely mechanical means of solids separation that is driven by Stokes' law (Appendix A) for the settling of spherical particles in a viscous liquid (ASME & Morgan, 2005a). Operating under hydrostatic head, tangentially directed injection of fluid into the hydrocyclone invokes a spiraling motion that generates strong centrifugal forces; centrifugal forces induce the solids to separate from the fluid. Higher density particles in the fluid are forced outward toward the wall of the hydrocyclone tube, which displaces lower density particles toward the center of the cone where a column is formed. By controlling the pressure across the tube, the core consisting of fluid and low-density solids is forced to flow through the overflow while high-density solids are directed to the underflow.

1.                      Particle Separation and Performance

Performance of hydrocyclones, much like shale shakers, is evaluated based on the mass flow rate of a specified particle size range that is discarded from the equipment compared to the mass flow rate of the same-size particles originally presented to the equipment (Morgenthaler & Robinson, 2007). The data from the resulting flows are then used to generate a cut-point curve, as shown in Figure 26, which is used as a graphical representation of the performance of the unit (Morgenthaler & Robinson, 2007). These generated cut-points are neither invariant nor a unique property of any particular piece of solids removal equipment and are only specific for the particular set of conditions existing at the time of the test. Thus, making the processes of measuring rejection of solids across a range sizes difficult to achieve. The inherent difficulty of obtaining cut points reduces the range of published values for a particular cone size. Consequently, perceived performance is weighted heavily on capacity expectations and the importance of solids removal becomes marginalized (Morgenthaler & Robinson, 2007). The cut point within a particular hydrocyclone is dictated by a collection of empirical relationships that are influenced by drilling-fluid properties such as fluid and particle density, the percentage of solids (and solids distribution), and viscosity (Ditria, 1994). Due to the dynamic nature drilling fluid rheology, variations in rheological properties make it difficult to quantify cut point values for a particular pairing of drilling fluid and hydrocyclone size. Therefore, manufactures publish the D₅₀ cut-point for hydrocyclone units, which is representative of the particle size in microns for which the unit rejects 50% of the mass of the solids presented to it in a dilute sand and water slurry (Morgenthaler & Robinson, 2007).

1.1.1.4.2.                  Sizing and Configuration

Desanding hydrocyclones differ from those used for desilting with respect to cone dimension but operate on exactly the same principles. By convention, the diameter inside cone at the inlet port dictates the selection process for hydrocyclones. Typically, cones designated for desilting are manufactured in a range between two to six inches in diameter, while desanding cones vary in size from six to twelve inches in diameter (ASME & Morgan, 2005a). Furthermore, as seen in Table I, variations cone diameter directly affects the volume of fluid processed through individual cones. As the nominal hydrocyclone diameter decreases, efficiency improves and capacity decreases (Ditria, 1994). Depending on the processing flow rates required during drilling, multiple hydrocyclones assembled into a larger manifold to provide adequate processing capacity. For desilter and desander hydrocyclones assembled into a manifold where a number of hydrocyclones operating in parallel simultaneously receive solids laden drilling fluid. As illustrated in Figure 26, individual cones within the manifolds are typically arranged in either a linear or circular pattern with all cone overflows discharge from one end and all underflows discharge from the other (Svarovsky, 1977). Linear or radial configuration of individual cones within the manifold assembly has an influence on the performance of the system as a whole. The employment of linear manifolds results in heavy solids loading of cones furthest from the fluid inlet due to high-energy particles bypassing the cones close to the inlet. These reductions in performance due to lack of uniformity in feed concentrations and particle size distribution within the cones can be mitigated with a radial configuration rather than linear. Although the performance of hydrocyclone assemblies are influenced by arrangement and flow distribution, the orientation of the cones does not affect performance due to fact that the gravitational effects imparted by the angling of the cones are negligible when compared to the centrifugal forces generated during operation. Therefore, angled and vertical manifolds are readily available for desilting and desanding operations.

1.1.1.5.          Mud Pumps

As one of the critical components of the rig’s circulating system, mud pumps are generally designed to provide adequate discharge pressure, flow rates, and hydraulic horsepower requirements needed during drilling operations (R. F. Mitchell & Miska, 2011). Recent developments in reciprocating mud pump technologies have added value for operators, drilling contractors, and service providers by offering systems with increased performance envelopes, reduced pressure pulsations on the rig structure and piping, and substantially increased data rate-transfer bandwidth during MWD/LWD operations (Berryhill & Shelton, 2013). Furthermore, performance criterion such as spatial footprint and weight have been incrementally addressed by manufacturers to provide systems that are collectively more efficient than previously implemented high-pressure pumping configurations (H Kverneland, 2005).

1.1.1.5.1.                  Single-Acting Positive Displacement Mud Pumps

Generally, pumps used for high-pressure pumping of drilling fluids operate by converting the reciprocating motion of a piston plunger to work energy at the fluid end of the pump. Piston plunger pumps are the simplest form of a positive displacement pump and are used in industrial applications because their ability generates high head that is independent of fluid density (Herbert H.Tackett, James A. Cripe, 2008). This type of pump controls subsequent suction and discharge fluid conditions by means of check valves placed in series on both the suction side and the discharge side of the fluid cylinder. The check valves ensure unidirectional fluid movement from pump suction toward the pump discharge. As the piston is drawn backward to open the chamber, the piston draws fluid into its chamber through the inlet or suction value. As the piston reaches the full length of the suction stroke, the inlet valve is closed and the outlet valve opened as the piston is forced forward to discharge the fluid from the chamber (Lyons & Plisga, 2011). Each time the plunger displaces the fluid from the chamber, the plunger element is acting upon the fluid. This stage of the cycle period is referred to as the power stroke. Therefore, pumps designed to provide a single a power stroke per revolution are known as single acting (Herbert H.Tackett, James A. Cripe, 2008).

1.                      Fluid End Technology

As with reciprocating pumps used in non-oilfield applications, mud pumps are generally partitioned into two sub-assemblies referred to as the fluid end and power end (Lyons & Plisga, 2011). The mud pump fluid end uses the reciprocating action of the power or drive end to create a suction and discharge flow that circulates remediated drilling fluid into the wellbore. Albeit hydraulic requirements dictate a number of mud pump design features and constituents within both sub-assemblies, appropriate design of the fluid end components is essential to achieving long mean time between failure (Herbert H.Tackett, James A. Cripe, 2008). Therefore, improvements in technologies related the pump's fluid end module, piston, and liner system, and valve and seat systems have been developed to maximize the performance of modern multiplex mud pump systems. Multiplex plunger pump fluid ends are manufactured in either mono-block or modular configurations as seen in Figure 31(Pendelton & McPheron, 2013). Of these configurations, pumps used for circulating drilling fluids generally employ modular fluid end configurations. Though mono-block fluid ends have been primarily used in stimulation pumps, a limited number of manufacturers have employed the design for application in drilling. Mono-block assemblies typically develop stress concentrations at the intersection of the suction and discharge cross-bores, as well as the suction valve seat deck (Kiani, 2015). When coupled with cyclic loading during operation, the fluid end is likely to experience a fatigue failure within one of the cylinders (Kiani, 2015). The resulting failure of a single cylinder in the unitized body requires replacement of the entire fluid end before operation of the pump can continue. In contrast, single modular fluid ends provide a natural break in the stress transfer, and thus isolating potential failures to the individual modules while prolonging the service life of the fluid end as a whole (Pendelton & McPheron, 2013).

1.   Single and Two-Piece Linear  Fluid Modules

Generally, modular fluid ends are offered in either a single or two-piece module depending on the OEM and rated performance envelope of the pump with respect to hydraulic horsepower and maximum surface pressure. As illustrated in Fig 32, single piece fluid end modules employ a design where the suction-discharge valve arrangement is designed so that the suction valve is positioned directly under the discharge valve. Variations of valve-over-valve modules are offered by multiple manufacturers in both OEM configurations, as well as third-party module replacements for various pumps in the marketplace.  Modules of this type, though marginally lighter than two-piece fluid ends for pumps of the same horsepower (Rylan Ardoin, 2014), experience drawbacks associated with valve maintenance, operating pressure limitations of 5000 psi, and fatigue failures. Therefore, manufactures of mud pumps have turned to fluid ends that utilize two-piece or L-Shaped modules. Since its introduction, the L-shaped fluid end design has become the preferred design of many manufacturers due to several design advantages it has over one-piece fluid end modules. The L-shaped profile of two-piece modules is derived from the configuration in which the suction and discharge sub-assemblies are joined together. As illustrated in Figure 33, the suction valve assembly is bolted to the discharge section of the module. By partitioning the suction and discharge sub-assemblies, it is possible to replace only the defective suction or discharge assembly in the event of failure, as opposed to replacing the entire fluid end. Modules of this type, though marginally heavier than single-piece fluid ends for pumps of the same horsepower (Rylan Ardoin, 2014), experience a range of benefits associated with ease of valve maintenance, increased operating pressures of 7500 psi, and increased resistance to fatigue failure. Variations of L-shaped modules are offered by pump manufacturers as part of OEM configurations, as well as third-party manufacturers that offer replacement modules for maintenance purposes, or as upgrades to existing single-piece assemblies.

2.   Axial Fluid Module

Multiplex pumps typically found in drilling are comprised of a linear arrangement of fluid modules, with the number of cylinders varying depending on the circulation requirements of the rig. As a departure from traditional multiplex pumps, the Hex Pump was developed in 2003 as a prototype to remedy pulsation seen in 7,500 psi pumping systems used in offshore drilling (Whyte, 2003). In contrast to crankshaft-driven multiplex pumps whose cylinders are in a linear configuration, the Hex Pump employs six vertical pistons in an axial configuration. Powered by two AC motors, a single gear rotates a specially-profiled cam above the pistons/plungers to produce pumping action with specific timing (Hege Kverneland, Kyllingstad, & Moe, n.d.). Test results indicate that the design delivers multiple advantages over traditional multiplex pumps that include nearly pulsation-free flow, weight and footprint reductions, and the elimination of the need to exchange liner sizes for higher pressure or flow. Though the system observed success in onshore land drilling applications (Hege Kverneland et al., n.d.), further commercial development of the design remains to be seen past initial stages of prototype development.

2.                      Power End Technology

A power pump drives a pumping element(s) through the reciprocating motion using either a crank and slider mechanism or camshaft to convert rotary motion and power from an electric motor, engine, or turbine into reciprocating motion and work energy inside the fluid end of the pump. These pumps can be powered by a variety of prime movers, internal combustion engines, and electric motors (and in some cases, powered by a gas turbine motor). In such applications, the separate pump unit is connected to the prime mover by a power transmission. These factors are set by the application.

1.   Permanent Magnet AC Motors

Long used in servo motor applications, permanent magnet AC (PMAC) motors are increasingly being used in industrial motor drive systems (McCoy, 2010), and are emerging as an alternative to the commonly used alternating current induction motor. The key difference between PMAC motors and traditional AC induction motors is that PMAC motors replace the conducting metal bars in the rotor with powerful ceramic or rare earth neodymium iron boron magnets (McCoy, 2010). The magnets are attached to the surface of the rotor or interior to the rotor in order to establish a permanent magnetic field which is used create torque and motion. Rare-earth permanent magnets are employed because they produce more flux for their physical size than their induction counterpart (Murphy, 2012). As a result, PMAC motors can be built much smaller than an AC induction motor of the same horsepower rating and come in reduced frame sizes. This means more torque can be produced in a given physical size, or equal torque produced in a smaller package (Murphy, 2012). The reductions in physical size and material requirements yield a motor weight savings of nearly 50 percent, and a subsequent torque-to-weight ratio of nearly twice that of conventional AC induction motors (Bartos, 2008). Due to their relatively light weight, high torque, and compact size, PMAC motors are suitable for applications where the spatial footprint is limited and a high-power density is required (McCoy, 2010). Currently, PMAC motors have proven useful in many non-oilfield applications including hybrid vehicles (Schultz & Huard, 2015), marine propulsions systems (Greenberg, 2008), military vehicles, wind turbines, and automation equipment (Liu, 2010). With the proven success of PMAC motors in other industries, manufacturers have incrementally adapted the technology for use in powering rig components that include kingpost cranes, rig draw works, and top drive assemblies (Greenberg, 2008). Furthermore, to maximize the bene­fits of a direct drive mud pump con­figurations, PMAC technology has been developed as an alternative to AC induction and diesel power sources. As with PMAC motors used in applications outside the drilling industry, motors developed for use with direct drive mud pumps offer reductions in weight, spatial footprint, while boosting increasing efficiency. As seen in Fig 31., the rotor of the motor is interconnected with the crankshaft of the pump, which results in the rotational motion created by the PMAC being directly imparted to the shaft. In doing so, the design removes the need for use of a transmission, subsequently eliminating the need for components any belts, sheaves, or motor bearings. By removing these components, the unit also becomes inherently safer as there are no rotating components that need to be caged during operation. Currently, mud pump configurations are commercially available in power outputs from 275 HP to 2250 HP, offering weight savings as high as 20% and volumetric savings of 25% depending on the power of the motor and manufacturer.

1.   Worm Gear Power Ends

Historically, worm gear drives (WGD) have been implemented in applications that require high power transmission ratios. As a result, WGD's have proven useful in many non-oilfield applications including mechatronics (Boxerbaum et al., 2009), marine steering, and electric transmissions (Jelaska, 2012). Though WGD’s have experienced success in non-oilfield applications, their adoption to technologies within the oilfield has been limited. Currently, the technology has been adapted for use in hydraulic fracturing pumps (Jiang, Liang, & Zhong, 2007) and specific configurations of constant-duty drilling mud pumps. Newly configured quadruplex mud pumps have been designed to employ the WGD over conventional pinion and bull gear configurations. Though worm drives have many advantages when compared to pinion and bull gears, their employment requires that the crankshaft, more specifically, the worm wheel, remains stable during operation. Thus, the technology is scarcely employed in triplex mud pumps whose crankshaft experiences a large bending moment, and varying levels of displacement when loaded due to support bearings located at either end of the crankshaft (Fig. 32 A). As a result, the WGD is generally employed in quadruplex systems whose crankshaft is supported by bearings immediately adjacent to the connecting rods inside the pump housing as seen in Fig. 32 B. The balancing of the crankshaft coupled with the four piston design yield a crankshaft that is resistant to flexing and suitable for use with a WGD  

3.                      Volumetric Output Capacity

The volumetric pumping capacity of single acting positive displacement pumps used for circulation while drilling is determined by the number of plungers or pistons and the size of the cylinder bore and pump stroke (Lyons & Plisga, 2011). The rate at which fluid need to be pumped is dependent on variables that include, but are not limited to, the geometry of the wellbore, cuttings load, and the specific type of drilling application. In short, the flow rate must be high enough maximize cleaning efficiency of the bit and wellbore during drilling operations (Pessier & Fear, 1992), but low enough to avoid hole erosion, equipment wear, and excessive standpipe pressure (Husband et al., 2007). In applications which volumetric capacity and pressure capability are known, a designer can determine the plunger piston bore and stroke, rotational speed range, and the power of the prime mover needed to complete the system (Lyons & Plisga, 2011). Generally, an approximation of minimum volumetric rates needed while drilling in gal/min can be obtained via Eq. (3), where D_h is the hole diameter in inches, D_p is the pipe diameter in inches, and  is the weight of the drilling fluid in lb/gal. Unlike centrifugal pumps whose output is contingent upon an operational pressure head, there is no capacity-head curve for reciprocating pumps due to the pump yielding a fixed displaced volume per pump revolution and the independence of pressure from pump speed and flow rate (Herbert H.Tackett, James A. Cripe, 2008). As a result, the pump output curve is a linear function similar to that in Figure 31, where the change in the pumps volumetric output is proportional to the change in pump speed. Furthermore, because of the fixed volume of fluid displacement at a given speed, more precise capacities can be achieved during operation. The volumetric rate at which fluid can be pumped is contingent upon the maximum rated input power of the pump at a given speed and the subsequent pressures that are developed downstream from the pump’s discharge when circulating at the given rate.  Pressures seen at the discharge manifold of the pump are equal to the sum of frictional pressure losses in the system, surface back pressure, and hydrostatic-pressure difference between the annulus and drill string (API, 2010).  As seen in Eq.(4), the required input engine power IHP in (hp) is estimated for any theoretical output Q_t and subsequent pump working pressure PWP. where ∆P_s = pressure loss through surface equipment in psi; ∆P_d = pressure loss through the inside of the drill string in psi; ∆P_a = pressure loss in the annulus in psi ∆P_b = pressure drop through bit nozzles in psi (Lyons & Plisga, 2011). Frictional pressure losses in the drill string and annulus that affect the hydraulic horsepower of the pump are impacted by key parameters such as flow rate, flow regime, rheological properties, and conduit geometry (API, 2010). Methods to calculate frictional pressure losses and hydrostatic pressures through the different segments of the circulating system are expressed in detail within Section 7 of API Recommended Practice 13 D. The resulting values from these calculations are deemed suitable for hydraulics analyses, planning, and optimization (API, 2010). Given that the resulting hydraulic horsepower requirements of the system cannot exceed the maximum rated input power of the pump itself, flow rate and maximum working pressure develop a relationship to one another that is inversely proportional. Thus, the maximum discharge pressure and flow rate can be varied by changing the stroke rate and liner size depending on the hydraulic power requirements of the system (R. F. Mitchell & Miska, 2011). Generally, employment of a smaller liner will allow the operator to obtain higher discharge pressure but will yield a decrease the volumetric rate. It is for this reason if pressure losses developed in the system or the volumetric flow rate is limiting the pump performance during operation, resizing of the pump liners is a plausible solution (Husband et al., 2007).

4.                      Triplex Pumps

With the exception of several experimental types mud pumps always have used reciprocating. Both positive-displacement pistons two-cylinder duplex and three-cylinder triplex pumps are common. The duplex pumps generally are double-acting pumps that pump on both forward and backward piston strokes. The triplex pumps generally are single-acting pumps that pump only on forward motion piston strokes. Triplex pumps are lighter and more compact than duplex pumps their output pressure pulsations are not as great and they are cheaper to operate. For these reasons the majority of new pumps being placed into operation are of the triplex design.