Cut points are used to indicate the separation characteristics of solids control equipment at a given moment in time. The performance of the equipment, in addition to the condition of the drilling fluid, should be taken into consideration in the assessment of cut point data. Cut point curves are derived from the collected data and indicate, at the actual moment of data collection, the percentage of chance that a particle of a particular size can flow through or be discarded by the solids-control equipment. Therefore, the cut point curve is a function of the physical properties of the solids (i.e., density), particle size distribution of the solids, physical condition of the solids-control equipment (i.e., sealing capabilities), and the drilling-fluid properties.
Cut points may be determined for all drilled-solids removal equipment. The mass flow rate of various-size particles discarded from the equipment is compared with the mass flow rate of the same-size particles presented to the equipment. When testing a particular unit, knowledge of the feed flow rate to the unit and the two discharge flow rates are required. The density of the feed flow multiplied by the volume flow rate provides the mass flow rate into the unit. Discharge mass flow rates are also calculated by multiplying the density of the stream by the volume flow rate. Obviously, the sum of the discharge mass flow rates must be equal to the feed mass flow rate. Usually one of the discharge flow streams is discarded and the other is retained in the drilling fluid.The material balance—both the volume flow rate balance and the mass flow rate balance—should be verified before measuring the particle sizes of the various streams.
Solids-removal equipment removes only a very small fraction of the total flow into the equipment. For example, a 4-inch desilter processing about 50 gpm of drilling fluid will discard only about 1 gpm of material. Since the discarded material is such a small proportion of the total material processed, the difference between the retained stream and the feed stream is difficult to measure. For this reason, more accurate data are acquired by mathematically adding the value of the discarded solid concentrations to that of the retained solids concentration to determine the feed solids concentration.
To determine the mass flow of a particular-size particle in the feed (or retained) stream and the mass flow of the same-size particle in the discard, flow rate measurements and solids concentrations are needed. The discard volume flow rates are normally relatively low, but the feed rates require using a flow meter or a positive displacement pump.
For shale shakers, the feed to the shaker will be the circulating rate coming from the well. Mud pumps must be calibrated to provide an accurate feed rate. While drilling, move the suction from the suction tank to the slug tank and measure the rate of drop of the fluid leaving the slug pit. The fluid in the slug tank will contain liquid and gas (or air), so the volume percentage of (%vol) gas must be subtracted from the volume of fluid leaving the slug tank. The %vol gas is calculated by dividing the difference between the pressurized mud weight and the unpressurized mud weight by the pressurized mud weight and multiplying by 100. If the desilters or centrifuges are fed by centrifugal pumps, some type of flow meter will be required to accurately determine the feed rate. The flow meter could be a large container whose volume is calibrated and a stopwatch. A centrifuge underflow volume flow rate is difficult to measure because of the high concentration of solids. A barrel or other large container can be split vertically and support beams or pipes welded to provide a support when the container is placed across the top of a mud tank. Calibrated lines are painted inside of the container to provide volume measurements. A quantity of water is placed in the container and the container is positioned adjacent to a decanting centrifuge mounted on top of a mud tank. The stopwatch is started when the container is pushed under the centrifuge, and the rate of water level is observed.
The known volume between lines and the time permit calculation of the volume discard rate. Representative samples of the underflow or heavy slurry provide the density measurements of the underflow. After confirming that there is a mass and volume flow balance with the measured values, the particle sizes in the discharge streams are determined.
All of the discard stream may be captured for analysis during a period of several minutes. The contents of the feed stream during that period must be known so that the ratio of discard to feed particle mass can be determined for various particle sizes. The feed stream and retained stream for shakers and desilters, however, would require much larger containers, and it is impractical to try to weigh or measure their volumes directly. Representative samples of the retained stream must be used to determine the mass of various-size particles.
With the centrifuge and the desilters, the particle sizes must be measured with an instrument that discerns particle sizes as small as 1 micron. With the shaker measurements, sieves may be used because the cut point range will be within the range of screens standardized by the American Society for Testing and Materials (ASTM). A variety of different laboratory devices are available that measure small-diameter particles. Instruments using lasers are popular in many laboratories.
The discard sample will contain the solids and the liquid phase of the drilling fluid. With the shale shaker discard, the mass of solids retained on each ASTM test screen may be measured directly by weighing the solids after they are dried. With the desilter underflow and the centrifuge underflow (or heavy slurry) discharge, the density of the solids must be used to determine the mass percentage of solids.
Cut points for shale shakers are measured by determining the particle size distribution of the feed and discard streams with the use of a stack of U.S. Standard Sieves. The flow rate of each stream is determined, and the mass flow rate for each sieve size in each stream is calculated. The mass flow rate of the discard stream for each sieve size is divided by the mass flow rate for the same size introduced into the equipment in the feed stream.
Using this method, the feed-stream sample represents a small fraction of the total overall flow. This can create a problem with material balances. A better method is to sample the discard and underflow streams. Combining these two solids distributions will yield a more accurate cut point curve. This method can be used on solids-control equipment in which the feed-stream flow rate is greater than the discard stream.
Samples of the discard and underflow streams are taken from the solids-control equipment for analysis. The density of all streams is measured. The volume flow rate of the discard stream is measured by capturing all of the discard stream in a container—a section of gutter works well at the discard end of a shaker screen. The volume flow rate of the discard stream is determined by multiplying the mass of fluid captured by the density, or mud weight, of the discard. The volume flow rate of the feed is determined by accurately measuring the flow rate from the rig pump. The mass flow rate of the feed is calculated by multiplying the density of the drilling fluid by the circulating flow rate. Each sample is wet sieved over a stack of U.S. Standard Sieves with a broad distribution of sizes. The excess drilling fluid is washed through the screen with the liquid phase of the drilling fluid. The samples at each individual sieve size are thoroughly dried. Weights of the solids retained at each individual sieve size are measured, and the flow rate for each stream at each individual sieve size is calculated. To determine the screen cut point curve, the quantity of a particular-size particle in the discard must be compared with the quantity of the same-size particles presented to the screen. All of the discard can be captured, and all of the mass of the discard solids of a particular size can be determined. However, it is impractical to try to capture and sieve all of the fluid passing through the screen during the period that the discard is being captured. For example, if the rig flow is 500 gpm and the discard sample is captured during a 3.50-min period, the underflow through the shaker screen would be 1750 gal. If the mud weight is 9.2 ppg, this means that 16,100 lb of drilling fluid has passed through the screen. A 9.2-ppg drilling fluid with no barite and 2.6 specific-gravity low-gravity solids would have 6.5% volume of solids. The total solids that would be presented to the screen during the 3.5-min period would be 113.75 gal [6.5% of 1750 gal] or 2467 lb of solids [(114 gal)(2.6)(8.34 ppg)]. Since it is not practical to capture and sieve this quantity of solids, a representative sample of the underflow through a screen can be used to determine the solids concentration and sizes that did pass through the screen. The flow rate of the underflow sample and the dry weight of the individual sieve sizes must be measured. This is the reason that flow rates of the dry solids are used in the calculations instead of using all of the solids captured in a specific time interval.
The corresponding feed mass flow rate (sum of discard and under flowrates) for each individual sieve size is also determined. The ratio of the discard and the feed flow rates at each sieve size determines the percentage of solids discarded over the solids-control equipment. The size of the sieves (expressed in microns) versus the percentage of solids removed produces a cut point curve.
A cut point curve graphically displays the fraction of various-size particles removed by the solids-control equipment compared with the quantity of that size of particle presented to the equipment. For example, a D50 cut point is the intersection of the 50% data point on the Y axis and the corresponding micron size on the X axis on the cut point graph. This cut point indicates the size of the particle in the feed to the solids control equipment that will have a 50% chance of passing through the equipment and a 50% chance of discharging off of the equipment. Frequently, solids-distribution curves are erroneously displayed as cut point curves. Cut point curves indicate the fraction of solids of various sizes that are separated. They also are greatly dependent on many drilling-fluid factors and indicate the performance of the complete solidscontrol device only at the exact moment in time of the data collection. The cut points of the solids-control equipment will be determined by the physical condition of the equipment and the properties of the drilling fluid.
Following is a procedure detailing the required steps to perform this method of particle-size analysis and the calculations used to create a cut point curve. An example of data collected and analyzed using a shale shaker is included after the detailed procedure. The example demonstrates useful information that can be obtained by following the procedure. This procedure is most applicable to performing cut point analysis with a shale shaker. Therefore, the example data measure solids to only 37 microns (No. 400 sieve).
Calculating cut point curves for hydrocyclones and centrifuges should use methods other than sieving. Measurements with a No. 635 sieve (20 microns) is about the limit of sieve analysis, but information is required about particles much smaller. Particle size analysis equipment, such as laser diffraction, is required for measurements of smaller sizes of solids. However, the assumption that the solids being analyzed have a constant density would have to be made.

Separation of Drilled Solids from Drilling Fluids

The types and quantities of solids (insoluble components) present in drilling mud systems play major roles in the fluid’s density, viscosity, filter-cake quality/filtration control, and other chemical and mechanical properties. The type of solid and its concentration influences mud and well costs, including factors such as drilling rate, hydraulics, dilution rate, torque and drag, surge and swab pressures, differential sticking, lost circulation, hole stability, and balling of the bit and the bottom-hole
assembly. These, in turn, influence the service life of bits, pumps, and other mechanical equipment. Insoluble polymers, clays, and weighting materials are added to drilling mud to achieve various desirable properties.
Drilled solids, consisting of rock and low-yielding clays, are incorporated into the mud continuously while drilling. To a limited extent, they can be tolerated and may even be beneficial. Dispersion of clay-bearing drilled solids creates highly charged colloidal particles (<2 μm) that generate significant viscosity, particularly at low shear rates, which aids in suspension of all solids. If the clays are sodium montmorillonite, the solids will also form thin filter cakes and control filtration (loss of liquid phase) into the drilled formation. Above a concentration of a few weight percent, dispersed drilled solids can generate excessive low-shear-rate and high-shear-rate viscosities, greatly reduced drilling rates, and excessively thick filter cakes. As shown in Figures 2.3 and 2.4, with increasing mud density (increasing concentration of weighting material), the high-shear-rate viscosity (reflected by the plastic viscosity [PV]) rises continuously even as the concentration of drilled solids (low-gravity solids [LGSs]) is reduced. The methylene blue test (MBT) is a measure of the surface activity of the solids in the drilling fluid and serves as a relative measure of the amount of active clays in the system. It does not correspond directly to the concentration of drilled solids, since composition of drilled solids is quite variable. However, it is clear that, in most cases, drilled solids have a much greater effect than barite on viscosity and that the amount of active clays in the drilled solids is one of the most important factors. Thus, as mud density is increased, MBT must be reduced so that PV does not reach such a high level that it exceeds pump capacity or causes well-bore stability problems.

As shown in Figure 2.4, increasing the mud density from 10 lb/gal to 18 lb/gal requires that the MBT be reduced by half [M-I llc]. Different mud densities require different strategies to maintain the concentration of drilled solids within an acceptable range. Whereas low mud densities may require only mud dilution in combination with a simple mechanical separator, high mud densities may require a more complex strategy:
(a) chemical treatment to limit dispersion of the drilled solids (e.g., use of a shale inhibitor or deflocculant like lignosulfonate).
(b) more frequent dilution of the drilling fluid with base fluid,
(c) more complex solids removal equipment, such as mud cleaners and centrifuges [Svarovsky].
In either case, solids removal is one of the most important aspects of mud system control, since it has a direct bearing on drilling efficiency and represents an opportunity to reduce overall drilling costs. A diagram of a typical mud circulating system, including various solids-control devices, is shown in Figure 2.5 [M-I llc].

While some dilution with fresh treated mud is necessary and even desirable, sole reliance on dilution to control buildup of drilled solids in the mud is very costly. The dilution volume required to compensate for contamination of the mud by 1 bbl of drilled solids is given by the following equation:

where Vsolids is the volume of drilled solids expressed in volume percentage. As discussed earlier, drilled solids become less tolerable with increasing mud density. For drilling-fluid densities less than 12 lb/gal, Vsolids<5% is desirable, whereas for a density of 18 lb/gal, Vsolids<2 or 3% is best. When Vsolids=5%, the equation above gives Vdilution=19 bbl
drilling fluid/bbl drilled solids. The cost of this extra drilling fluid (neglecting downhole losses) is the sum of the cost of the drilling fluid itself plus the cost to dispose of it. This dilution cost is generally so high that even a considerable investment in solids-control equipment is more economical.
Solids removal on the rig is accomplished by one or more of the following techniques:
. Screening: Shale shakers, gumbo removal devices
. Hydrocycloning: Desanders, desilters
. Centrifugation: Scalping and decanting centrifuges
. Gravitational settling: Sumps, dewatering units
Often these are accomplished using separate devices, but sometimes these processes are combined, as in the case of the mud cleaner, which is a bank of hydrocyclones mounted over a vibrating screen. Another important hybrid device is the cuttings dryer (also called a rotating shaker), which is a centrifuge fitted with a cone-shaped shaker; this apparatus is used to separate cuttings from NAF-based muds and strip most of the mud from the cuttings’ surfaces before disposal. Additional devices
can help to enhance solids-removal efficiency. For example, a vacuum or atmospheric degasser is sometimes installed (before any centrifugal pumps, typically between the shakers and desanders) to remove entrained air that can cause pump cavitation and reduction in mud density. Refer to Chapter 5 on Tank Arrangements for more details.
With the advent of closed loop systems, dewatering of WBMs has received strong impetus, and it has been found useful to add a dewatering unit downstream of a conventional solids-control system [Amoco]. Dewatering units usually employ a flocculation tank—with a polymer to flocculate all solids—and settling tanks to generate solidsfree liquid that is returned to the active system. Dewatering units reduce waste volume and disposal costs substantially and are most economical
when used to process large volumes of expensive drilling fluid.
Solids-control equipment used on a rig is designed to remove drilledsolids—not all solids—from a drilling fluid. As such, the equipment has to be refined enough to leave desired solids (such as weighting material) behind while taking out drilled solids ranging in size from several millimeters to just a few microns. Although such perfect separation of desired from undesired solids is not possible, the advantages offered by the solids-control equipment far outweigh their limitations. Each
device is designed to remove a sufficient quantity and size range of solids. The key to efficient solids control is to use the right combination of equipment for a particular situation, arrange the equipment properly, and ensure that it operates correctly. This, in turn, requires accurate characterization of the drilled solids, along with optimal engineering and maintenance of the drilling fluid.


Drilled-solids management has evolved over the years as drilling  has become more challenging and environmental concerns have become paramount. Equipment changes and improvements have responded to the necessity to treat more and more expensive drilling fluids. In this context, probably the largest impact on the drilling industry has been the recognition that polymers can make much better drilling fluids than those used heretofore even though they are expensive. Polymer drilling
fluids require lower drilled-solids concentration, so superior solids removal systems were developed to meet those demands. A historical perspective on drilling-fluid management, specifications, solids control, and auxiliary processes, provides a clear and complete picture of the evolution of current equipment
Drilling fluid was used in the mid-1800s in cable tool (percussion)drilling to suspend the cuttings until they were bailed from the drilled hole. (For a discussion of cable tool drilling, see History of Oil Well Drilling by J. E. Brantley.) With the advent of rotary drilling in the water-well drilling industry, drilling fluid was well understood to cool the drill bit and to suspend drilled cuttings for removal from the well bore.
Clays were being added to the drilling fluid by the 1890s. At the time that Spindle top, near Beaumont, Texas, was discovered in 1901, suspended solids (clay) in the drilling fluid were considered necessary to support the walls of the borehole. With the advent of rotary drilling at Spindle top, cuttings needed to be brought to the surface by the circulating fluid.
Water was insufficient, so mud from mud puddles, spiked with some hay, was circulated down hole to bring rock cuttings to the surface. Most of the solids in the circulating system (predominantly clays) resulted from the so-called disaggregation of formations penetrated by the drill bit. The term disaggregation was used to describe what happened to the drilled clays. Clays would cause the circulating fluid to thicken, thus increasing the viscosity of the fluid. Some of the formation drilled would not disperse but remain as rock particles of various sizes commonly called cuttings.
If the formations penetrated failed to yield sufficient clay in the drilling process, clay was mined on the surface from a nearby source and added to the drilling fluid. These were native muds, created either by so-called mud making formations or, as mentioned, by adding specific materials from a surface source.
Drilling fluid was recirculated and water was added to maintain the best fluid density and viscosity for the specific drilling conditions.
Cuttings, or pieces of formation—‘‘small rocks’’—that were not dispersed by water, required removal from the drilling fluid in order to continue the drilling operation. At the sole discretion of the driller or tool pusher, a system of pits and ditches were dug on site to separate cuttings from the drilling fluid by gravity settling. This system included a ditch from the well, or possibly a bell nipple, settling pits, and a suction pit from which the ‘‘clean’’ drilling fluid was picked up by the mud pump and recirculated.
Drilling fluid was circulated through these pits, and sometimes a partition was used to accelerate settling of the unwanted sand and cuttings. Frequently, two or three pits would be dug and interconnected with a ditch or channel. Drilling fluid would slowly flow through these earthen pits. Larger drilled solids would settle, and the cleaner fluid would overflow into the next pit. Some time later, steel pits were used with partitions between compartments. These partitions extended to within a foot or two of the bottom of the pit, thereby forcing all of the drilling fluid to move downward under the partition and up again to flow into a ditch to the suction pit. Much of the heavier material settled out, by gravity, in the bottom of the pit. With time, the pits filled with cuttings and the fluid became too thick to pump because of the finely ground cuttings entrained in the drilling fluid. To remedy this problem, the fluid was pumped out of the settling pits to reserve pits to provide room for dilution. Water was added to thin the drilling fluid and drilling continued.
In the late 1920s, drillers started looking at other industries to determine how similar problems were being solved. Ore dressing plants and coal tipples were using fixed bar screens placed on an incline; revolving drum screens; and vibrating screens. The latter two methods were selected for cleaning cuttings from drilling fluids.
The revolving drum, or barrel-type, screens were widely used with the early, low-height substructures. These units could be placed in a ditch or incorporated into the flow line from the well bore. The drilling fluid flowing into the machine turned a paddle wheel that rotated the drum screen through which the drilling fluid flowed. In those days, a coarse screen was 4 to 10 mesh and a fine screen was a 12 mesh. These units were quite popular because no electricity was required and the settling pits did not fill so quickly. Revolving drum units have just about disappeared.
The vibrating screen, or shaker, became the first line of defense in the solids-removal chain and for a long time was the only machine used. Early shakers were generally used in dry sizing applications and went through several modifications to arrive at a basic type and size for drilling. The first modification was a reduction in the size and weight of the unit for transport between locations. The name shale shaker was adopted to distinguish between shakers used in mining and shakers used in oil well drilling. This nomenclature was necessary, since both types of shakers were obtained from the same suppliers. The first publication about using a shale shaker in drilling operations, describing a ‘‘Vibrating Screen to Clean Mud,’’ was in the Oil Weekly of October 17, 1930. The shaker screen was a 30 mesh, 4 by 5 feet, supported by four coil springs.
Prior to the new ISO (International Standards Organization) standard, screens were identified by mesh size. Mesh size was the number of openings per linear inch of screen. Most screens were woven with square openings, so the designation was logical. With ISO nomenclature, the English unit of inches could not be used. In addition to the change in units, a more compelling change was required because of the complexities of the new shaker screens. Screens ceased to be easily described with a simple measurement of openings in either direction.
Screens are now layered to form complex opening patterns and are described with the equivalent opening size in microns and an API (American Petroleum Institute) number (which was formerly the mesh designation). Currently, API 20 to API 50 are considered coarse screens. API 150 to API 325 are fine screens.
The early shale shakers had 4- by 5-feet hook strip screens mounted that were tensioned from the sides with tension bolts. The vibrators were usually mounted above the screens, causing the screens to move with an elliptical motion. The axis of the ellipse pointed toward the vibrator. Since the axis of the ellipse at the feed end pointed toward the discharge end and the axis of the discharge end pointed toward the feed end, these shakers were called unbalanced elliptical motion shakers. The screens required a down slope to move cuttings off the screen. Solids at the feed end, particularly with sticky clay discards, would frequently start rolling back uphill instead of falling off the shaker. Screen mesh was limited from about API 20 to API 30 (838 microns to 541 microns). These units were the predominant shakers in the industry until the late 1950s. Even though superseded by circular motion and linear motion shale shakers, the unbalanced elliptical motion shale shakers are still in demand and are
still manufactured today.
Research laboratories of large oil companies and began to explore oil well drilling problems. The smaller cuttings, or drilled solids, left in the drilling fluid were discovered to be detrimental to the drilling process. Another ore dressing machine was introduced from the mining industry: the cone classifier. This machine, combined with the concept of a centrifugal separator, taken from the dairy industry, became the hydrocyclone desander, introduced to the industry around 1957. The basic principle of the separation of heavier (and coarser) materials from the drilling fluid lies in the centrifugal action of rotating the volume of solids-laden drilling fluid to the outer limit or periphery of the cone. Application of this centripetal acceleration causes heavier particles to move outward against the walls of the cone. These heavier particles exit the bottom of the cone and the cleaner drilling fluid exits from the top of the cone. The desander ranges in size from 6 to 12 inches in diameter and removes most solids larger than 30 to 60 microns. Desanders have been refined considerably through the use of more abrasion-resistant materials and more accurately defined body geometry. Hydrocyclones are now an integral part of most solids-separation systems today.
After the oilfield desander development, it became apparent that side wall sticking of the drill string on the borehole wall was generally associated with soft, thick filter cakes. Using the already existing desander design, a 4-inch hydrocyclone was introduced in 1962. Results were better than anticipated. Unexpected beneficial results were longer bit life, reduced pump repair costs, increased penetration rates, less lost circulation problems, and lower drilling-fluid costs. These smaller hydrocyclones
became known as desilters, since they removed solids called silt down to 15 to 30 microns.
The Pioneer Centrifuge Company related a story about the first desilter it installed on a drilling rig (private communication from George Stonewall Ormsby). The bank of 4-inch desilters was mounted on the berm of the duck’s nest (the duck’s nest was an earthen pit used for storing excess drilling fluid and was usually an area of the reserve pit). The equipment was removing large quantities of drilled solids from an unweighted drilling fluid. After 2 days, however, the rig personnel called
to have the equipment picked up because, they said, it was no longer working. When Pioneer arrived at the location, the equipment was completely buried in drilled solids, so that there was no way that more could be removed by the hydrocyclones.
During this period, major oil company research recognized the problems associated with ultra-fines (colloidal) in sizes less than 10 microns. These ultra-fines ‘‘tied up,’’ or trapped, large amounts of liquid and created viscosity problems that could be solved only by water additions (dilution). As large cuttings are ground into smaller particles, surface area increases greatly, even though the total cuttings volume does not change. Centrifuges had been used in many industries for years and
were adapted to drilling operations in the early 1950s. They were used first on weighted drilling fluids to remove and discard colloidal solids. The heavy slurry containing drilled solids and barite larger than about 10 microns is returned to the drilling fluid system.
In recent years centrifuges have been used in unweighted drilling fluids to remove drilled solids. In these fluids, the heavy slurry containing drilled solids down to around 7 to 10 microns is discarded and the light slurry with solids and chemicals (less than 7 to 10 microns) is returned to the drilling fluid. This application saves expensive liquid phases of drilling fluid. Dilution is minimized, thereby reducing drilling-fluid cost. However, these machines are quite expensive and require a great amount of care.
Unfortunately, many drillers did not believe that these benefits accrued to drilling-fluid systems that were properly arranged to take advantage of them. Mud tanks were, and still are, frequently plumbed incorrectly because of indifference concerning the detrimental effects of drilled solids. These benefits were not really generally accepted until the mid-1980s. Inspection of drilling-fluid processing systems on drilling rigs still reveals that proper plumbing is not well understood or is not a priority.
These hydrocyclones were usually loaded with solids because of the coarse screens on the shale shakers. Removing more of the intermediatesize particles led to the development of the circular motion shale shakers. These ‘‘tandem shakers,’’ utilizing two screening surfaces, were introduced in the mid-1960s. Development was slow for these so-called fine screen–high speed shakers for two reasons: First, screen technology was not sufficiently developed for screen strength, so screen life was short.
There was not sufficient mass in the screen wires to properly secure the screens without their tearing. Second, the screen basket required greater development expertise than had been required for earlier modifications in drilling-fluid handling equipment.
The tandem shakers had a top screen with larger openings for removal of larger particles and a bottom screen with smaller openings (finer mesh screen) for removal of the smaller particles. Various methods of screen openings were developed, including oblong, or rectangular, openings. These screens removed fine particles and had a high fluid capacity. They could be made of larger wires, so they had greater strength. Layered screens (a fine mesh screen for good solids removal over a coarse mesh
screen for strength) were developed. These layered screens were easier to build and had adequate strength for proper tensioning for increased screen life. This development made it possible for the shale shaker to remove particles greater in size than API 80~API 80 (177 microns).
In the 1970s the mud cleaner was developed. During this period, no shale shaker could handle the full rig flow on an API 200 screen. Desanders and desilters were normally used after the shale shaker; however, they discarded large quantities of barite when used on a weighted drilling fluid—this meant drilled solids larger than an API 80 and the upper limit of the barite size. API specifications currently allow three weight percent of barite larger than 74 microns, which is an API 200 screen. To solve this problem, the underflow from desanders and desilters was presented to a pretensioned API 200 screen on a shaker. Much of the liquid from the underflow of the hydrocyclones and most of the barite passed through an API 200 screen. This was also the first successful oilfield application of a pretensioned fine screen bonded to a rigid frame. Many mud cleaners had screen cleaners, or sliders, beneath the screen to prevent screen blinding. Mud cleaners have also been used with API 250 screens in unweighted drilling fluids that have expensive liquid phases.
A more recent development, introduced in the 1980s, has been the linear motion shale shaker. Linear motion is the best conveying motion to move solids off the screen. Solids can be conveyed uphill out of a pool of liquid as it flows onto the screen from the flow line. Screens with smaller openings, such as API 200 (74 microns), can be used on linear motion shakers, but they could not be used on any of the earlier types of shakers. Developments in screen technology have made it possible for pretensioned screens to be layered and, in some cases, have thredimensional surfaces.
The latest entry into the shale shaker challenge is a balanced elliptical motion shaker. The motion is similar to an unbalanced elliptical motion shaker except that all axes of vibration are pointed toward the discharge end. The movement of the screen is similar to a linear motion shaker except that the motion makes an ellipse. Solids are transported from a pool of liquid at the feed end of the shaker screen just as they are on a linear motion screen.
When the linear motion shale shakers were introduced, several were frequently arranged in parallel to receive drilling fluid from scalping shakers. Since API 200 screens could be used on these primary shale shakers, mud cleaners were widely considered superfluous, and mud cleaner use diminished significantly. However, installation of mud cleaners, even with API 150 screens downstream from these linear motion shale shakers, revealed that some removable drilled solids were
still in the drilling fluid. In real situations, sufficient drilling fluid bypasses linear motion shale shakers to make mud-cleaner installation economical. In retrospect, since the lower apex discharge of desilters frequently plugs downstream from linear motion shale shakers, this provides proof that all of the large solids are not removed by linear motion shakers.
Emphasis on minimization of liquid discharges for environmental considerations has created techniques to remove liquid from the drilledsolids discard. Since the decanting centrifuge is a very low shear-rate device for the drilling fluid (even though the drilling fluid is rotating at over 15,000 rpm), it can be used to concentrate flocculated and coalesced solids. The light slurry, which is almost a clear stream of water, is returned to the drilling fluid. This has become an important part of the
‘‘closed mud’’ system. Actually, the intent is to eliminate or reduce the quantity of liquid discarded.
A recent innovation for environmental purposes and minimization of liquid discharge is the dryer. The discharge from linear motion shale shakers, desanders, and desilters flows onto another linear motion shaker that has even finer screens than the main shale shakers (as fine as API 450, or 32 microns) and usually has a larger screening surface. The dryer has a closed sump under the screen with a pump installed. Any liquid in the sump is returned to the active system through a centrifuge.
These systems, or combinations of the various items discussed above, meet most environmental requirements and conserve expensive liquid phases. The desirable effect is to reduce the liquid content of the discarded drilled solids so that they can be removed from a location with a dump truck instead of a vacuum truck.
An innovation introduced in the Gulf of Mexico in the 1990s‘ was the gumbo conveyer. Before this was introduced, some drilling rigs would mount stainless steel rods about 2 to 3 inches apart on a downward slope. Gumbo, or large, pliable sticky cuttings, would slide down these rods and be removed from the system. Drilling fluid would easily flow through the openings between the steel rods. At least two versions are currently marketed. One is a chain and the other is a continuous permeable belt. These special conveyors drag gumbo out of the drilling fluid before the drilling fluid encounters a shale shaker. This operation reduces the severe screen loading problems caused by gumbo.
Innovations in drilled-solids removal equipment will probably continue. However, novel, spectacular equipment is useless if it is installed improperly and subjected to poor maintenance and operating procedures. This book concentrates on providing guidelines for practical operations of the surface drilling fluid system.


This handbook describes the method and mechanical systems available to control drilled solids in drilling fluids used in oil well drilling. System details permit immediate and practical application both in the planning/design phase and in operations.
Good solids-control programs are often ignored because basic principles are not understood. This book explains the fundamentals of good solids control. Adherence to these simple basic principles is financially rewarding.
This American Society of Mechanical Engineers (ASME) textbook/handbook is a revision of the American Association of Drilling Engineers (AADE) Shale Shaker Handbook, which was a revision of the International Association of Drilling Contractors (IADC) Mud Equipment Manual. Many of the authors of this book were authors of those books as well. Patience, dedication, many long hours of work, and evaluation of the latest technology have been required of all members of this committee. Ten years were required to write the IADC Manual;
7 years were required to write the AADE Handbook; and 2 years were required to write this textbook.
None of the authors of any of the three books have received any compensation for their work and writing. The group was dedicated to providing the drilling industry with the best technology available, and many hours of discussion were frequently required to resolve controversial issues.
Fallacious arguments persist that drilled solids are beneficial. Drilled
solids are evil and insidious. Increases in drilled-solids concentrations
generally do not immediately reveal their economic impact. Their
detrimental effects are generally not immediately obvious on a drilling
rig; so skeptics fail to believe that drilled solids foster the havoc that they
truly do. The secret to drilling safely, fast, and under budget is to remove
drilled solids. Drilled solids increase drilling costs, damage reservoirs,
and create large disposal costs. Specific problems associated with drilled
solids are:
. Filtrate damage to formations
. Drilling rate limits
. Hole problems
. Stuck pipe problems
. Lost circulation problems
. Direct drilling-fluid costs
. Increased disposal costs
These bad effects of drilled solids are explored in greater detail here
and in the rest of the book. The eradication of these effects is discussed
in great detail in this book. The book may be used for planning and
designing a drilling-fluid processing system, improving current systems,
troubleshooting a system, or improving rig operations. Drilled solids are
evil, and this is the theme of this Handbook.
The effects of drilled solids on the economics of drilling a well are
subtle. Increasing drilled-solids content does not immediately result in
disaster on a drilling rig. When a drill bit ceases to drill and torque
increases, a driller knows immediately that it is time to pull the bit.
When drilled solids increase, the detrimental effects are not immediately
apparent. Decreasing drilled solids is analogous to buying insurance for an event that will not happen. Proving that something will not happen—
like stuck pipe—is difficult to do. This is somewhat like the story of
Salem, who was walking down Main Street snapping his fingers. Friend
asks, ‘‘Why are you snapping your fingers?’’ Salem: ‘‘Keeps the tigers
away.’’ Friend: ‘‘There are no tigers on Main Street.’’ Salem: ‘‘Yeah,
works doesn’t it?’’ No drilling program calls for stuck pipe or fishing
jobs even if they are common in an area with a particular drilling rig.
The evil effects of drilled solids are real. Acknowledging that fact and
preparing to properly handle them at the surface will result in much
lower drilling costs.
Good drilled-solids removal procedures start at the drill bit. Cuttings
should be removed before another drill bit cutter crushes rock that has
already been removed from the formation. These cuttings should be
transported to the surface with as little disintegration as possible. In
addition to the cuttings produced by the drill bit, slivers or chunks of
rock from the well-bore walls also enter the drilling fluid stream. Large
drilled solids are easier to remove than small ones. After the cuttings
have reached the surface, the correct equipment must be available to
handle the appropriate solids loading, and the processing routing must
be correct. Surprisingly, after all these years of using drilling fluids, the
simple principles of arranging equipment are seldom practiced in the
field. Some drilling rigs, particularly offshore ones, have a complex
manifold of plumbing in the surface drilling fluid pits. The concept is
that any one of the centrifugal pumps can pump from any compartment
to any other compartment by adjusting valves. This concept is incorrect
and detrimental to proper drilled-solids removal. Generally, arranging
the complex routing for correct solids-removal processing is so
unobvious that all of the drilling fluid is not processed by the equipment.
Also, valves can leak in this system and go undetected for many wells.
Better to follow the rule, One pump/one purpose. Add additional
plumbing or pumps but do not use solids-removal equipment feed
pumps for anything but their stated purpose. This book shows how the
equipment works and how it should be plumbed.
While drilling wells, drilling fluid is processed at the surface to remove
drilled solids and blend the necessary additives to allow drilling fluid to
meet specifications. Drilling-fluid processing systems are described in
this book from both a theoretical point of view and practical guidelines.
It will be as useful for a student of drilling as for the person on the rig.
Drill bit cuttings and pieces of formation that have sloughed into the
well bore (collectively called drilled solids) are brought to the surface by
the drilling fluid. The fluid flows across a shale shaker before entering the
mud pits. Most shale shakers impart a vibratory motion to a wire or
plastic mesh screen. This motion allows the drilling fluid to pass through
the screen and removes particles larger than the openings in the screen.
Usually drilled solids must be maintained at some relatively low
concentration. The reason for the need for this control is explained in
the next section. The shale shaker is the initial and primary drilled-solids
removal device and usually works in conjunction with other solidsremoval
equipment located downstream.
Solids-control equipment, also called solids-removal equipment or
drilled-solids management equipment, is designed to remove drilled
solids from a circulating drilling fluid. This equipment includes gumbo
removers, scalper shakers, shale shakers, dryer shakers, desanders,
desilters, mud cleaners, and centrifuges. These components, in various
arrangements, are used to remove specific-size particles from drilling
fluid. Knowledge of operating principles of auxiliary equipment, such
as agitators, mud guns, mud hoppers, gas busters, degassers, and
centrifugal pumps, is necessary to properly process drilling fluid in
surface systems. All of this equipment is discussed in this book.
However, the best equipment available is insufficient if it processes only
a portion of the active drilling fluid coming from the well.