Solids-control Equipment Comments

One word of caution is appropriate here. Neophytes in drilling have a tendency to try to minimize the cost of each category of expense on the basis of the misconception that this will minimize the cost of the well. Minimizing individual items will only minimize a total if there is no dependence of variables on other costs. For example, increasing mud weight with drilled solids is cheaper than using barite. The cost savings from not purchasing barite is easy to calculate. The cost of all of the problems that ensue is much more difficult to predict. This is the insidious nature of drilled solids.
Decreasing individual costs to decrease the total cost is somewhat analogous to the accountant with appendicitis who decides to save money by renting a room at a cheap motel and calling a doctor friend rather than going to a hospital for an appendectomy. Room and board might be cheaper, but the net cost of improper care will probably make the decision very costly. Extra costs can be incurred because of inadvisable decisions to cut costs in easily monitored expenses while drilling wells. When line items are independent of each other, minimization of each line item will result in the lowest possible cost. When line items are interconnected, minimization of each line item may be very expensive. Drilled-solids concentrations and trouble costs (or costs of unscheduled events) are very closely intertwined.
One common mistake, usually made with the misconception that the well will be less expensive, is to allow the initial increase in mud weight to occur with drilled solids. Clearly, less money will be spent on the drilling fluid if no weighting agents are added to it. These savings are easily documented. Less revealing, however, will be the additional expenses because of the excessive drilled solids in the drilling fluid. Many of these problems will increase the well cost and have been discussed in the preceding sections.
Another common mistake, usually made while drilling with weighted drilling fluid, is to relate the cost of the weighting agent discarded with the drilled-solids discard. The cost of discarded weighted agents (barite or hematite) can be relatively small compared with the tragedies associated with drilled solids. This is particularly true in the expensive offshore environment. Even in cheaper land drilling, a comparison normally tilts in favor of discarding weighting agents.
Solids-control equipment, properly used, with the correct drilling-fluid selection, will usually result in lower drilling costs. Decisions made for various wells are very dependent on the well depth and drilling-fluid density. Shallow, large-diameter, low-mud-weight wells can tolerate more drilled solids than can deeper, more complicated wells. Each well must be evaluated individually with careful consideration of the risk of problems associated with drilled solids. As a general practice, however, since rigs drill a variety of wells during the course of a year, investing in a proper mud tank arrangement with adequate equipment is wise and frugal.
Yet another common mistake is to believe that different types of drilling-fluid systems will require different mud tank arrangements for solids removal. This is FALSE. Following the guidelines presented in this book will result in a system that will properly remove drilled solids from water-based, oil-based, synthetic-based drilling fluids. The waterbased drilling fluids could be dispersed or nondispersed, with or without polymers, or of low or high density or mud weight.


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.