The rotating separator process is based on a different principle than the shale shaker process. The mud line flow is fed into the slowly rotating separator. The drilling fluid contaminated with drilled cuttings is fed into the centre of a screen coated drum as shown schematically in Fig. 1. The outside of the drum is connected to an under-pressurised ventilation system.
Hook-strip screens have been mounted with both underslung and overslung supports. Some previous generations of oilfield shale shaker designs used screens that were underslung, or pulled up from the bottom of a group of support, or ‘‘bucker,’’ bars (Figure 7.15). These support bars would divide the flow of material down the screen. Some problem is experienced occasionally when solids are trapped under the rubber bar supports.
Some linear motion shale shakers utilize overslung screens (Figure 7.16). With this approach, screens are attached to the bed of the shaker by being pulled down onto the bed from the top. This results in a screening area completely free of obstacles. Modern shale shaker bed design has also increased the number of support ribs located beneath the screen to aid in fine-screen support and to reduce the amount of ‘‘crown,’’ or ‘‘bow,’’ necessary to properly tension screen panels. Some problem is experienced occasionally when the fluid leaves the high center of the screen and flows down the sides of the screen.
Most circular motion shale shakers were built with a double deck, meaning that fluid flowed over and through the top screen onto a finer screen immediately below. This arrangement led to some problems in operation, because the bottom screen was not easily visible. (Generally a flashlight was needed to inspect it.) A torn screen could remain in operation for a long time before it was noticed and changed. This created problems with solids removal because the bottom screen would not provide
the intended finer screening. Some manufacturers installed backflow pans under the top screen to direct the flow through the entire screen area of the bottom screen, but these just made it even more difficult to see the bottom screen.
Most manufacturers of linear motion shale shakers have adopted a single-deck design. The units have clear visibility for ease of care and maintenance. This unobstructed approach also makes screen changing much easier. The fluid pool tends to obscure any torn screens until drill pipe connections are made. Therefore, a torn screen on a single deck shaker reduces solids-removal efficiency until a new screen is installed.
Crews need to be alert to torn screens no matter what shaker is used. This is especially true during slow drilling, when drill pipe connections are infrequently made. When riser-assist pumps are used, flow should be periodically directed to different shakers during connections. This allows screens to be properly inspected and replaced, if needed.
Gumbo is formed in the annulus from the adherence of sticky particles to each other. It is usually a wet, sticky mass of clay, but finely ground limestone can also act as gumbo. The most common occurrence of gumbo is during drilling of recent sediments in the ocean. Enough gumbo can arrive at the surface to lift a rotary bushing from a rotary table. This sticky mass is difficult to screen. In areas where gumbo is prevalent, it should be removed before it reaches the main shale shakers.
Many gumbo removal devices are fabricated at the rig site, frequently in emergency response to a ‘‘gumbo attack.’’ These devices have many different shapes but are usually in the form of a slide at the upper end of a flowline. One of the most common designs involves a slide formed from steeply sloped rods spaced 1 to 3 inches apart and about 6 to 8 feet long. The angle of repose of cuttings is around 42 °, so the slides have a slope of around 45 °. Gumbo, or clay, does not stick to stainless steel very well; consequently, some of the devices are made with stainless steel rods. Drilling fluid easily passes through the relatively wide spacing in the rods, and the sticky gumbo mass slides down to disposal (Figure 6.1).
Several manufacturers have now built gumbo removal devices for rig installation. One of these units consists of a series of steel bars formed into an endless belt. The bars are spaced 1 to 2 inches apart and disposed perpendicular to the drilling-fluid flow. The bars move parallel to the flow. Gumbo is transported to the discharge end of the belt, and the drilling fluid easily flows through the spacing between the bars. Another machine uses a synthetic mesh belt with large openings, like an API 5 to
an API 10 screen. The belt runs uphill and conveys gumbo from a pool of drilling fluid. A counterrotating brush is used to clean gumbo from the underside of the belt. The belt speed is variable so it can be adjusted for the solids-loading and fluid properties.
When linear motion shale shakers were introduced into oil well drilling operations, drilling fluid could routinely be sieved through API 200 screens for the first time. This goal was desirable because it allowed the removal of drilled-solids sizes down to the top of the size range for barite that met American Petroleum Institute (API) specifications. Circular motion and unbalanced elliptical motion shale shakers were usually limited to screens of about API 80. Drillers soon found, however,
that gumbo could not be conveyed uphill on a linear motion shale shaker. The material adhered to the screen. To prevent this, the circular and unbalanced elliptical motion shakers were used as scalping shakers.
The ‘‘rig’’ shakers remained attached to the flowline to remove very large cuttings and gumbo. These were called scalping shakers. Even in places where gumbo might not be present, scalpers were used to prevent very large cuttings or large chunks of shale from damaging the API 200+ screens. These screens have finer wires, which are much more fragile than wire used on an API 20 or API 40 screens. Scalping shakers also had the advantage of removing some of the larger solids that would enter
the mud tanks when a hole appeared in the fine screen.
Tests indicated that fitting the scalper with the finest screen possible, an API 80 or API 100, did not result in the removal of more solids when combined with the API 200 on the main shaker. Apparently, shale in that size range would break apart on the scalper into pieces smaller than 74 microns, or it would damage the cuttings enough so that the linear motion shaker screen broke the cuttings. This action resulted in fewer total solids rejected from the system. Scalping shakers should be used as
an insurance package to prevent very large cuttings from hitting the fine screens. Scalping shakers, even with an API 20 screen, will still convey gumbo. Frequently, relatively fine screens on a scalping shaker experience near-size blinding. Coarse screens are preferred.
Scalping shakers should be used with either linear motion or balanced elliptical motion shale shakers.Gumbomust be removed before any screen can convey drilled solids uphill out of a pool of liquid. These motions may be used on shakers to remove gumbo if the screen slopes downward from the back tank (possum belly) to the discharge end of the shaker.
Combination shakers are available that mount a downward-sloping screen on a linear motion shaker above an upward-sloping screen with a linear motion. Gumbo will move down the top screen and be removed before the fluid arrives at the lower screen. Again, however, the scalping screen should be a very coarse screen. Some screens reject gumbo significantly better than others. Some screens also convey gumbo more efficiently than others. Manufacturers have a great assortment of screens
that have been tested in various regions of the world that experience gumbo attacks. Hook-strip screens with large rectangular openings—in the range of API 12—have been used very effectively in many regions. Experience indicates that the rectangular openings should be oriented so that the long opening is parallel to the flow.
Several important factors control whether to use a shale shaker/scalping shaker to effectively remove gumbo. If the screen deck can be tilted downward, with an articulated deck, gravity will assist gumbo removal. If the older-style unbalanced elliptical motion shaker is used, the fixed downward angle will usually satisfactorily convey gumbo. If the deck angle is flat, like most circular motion machines, the shaker has to generate a sufficient negative, or downward, force vector, normal to
screen, to overcome the adhesion factor (or stickiness) of the gumbo so that the screen separates from the solids. If it does not separate, the gumbo is effectively glued to that spot on the screen. If the drilling fluid is changed to decrease the quantity of gumbo reaching the surface, gumbo removal may not be a problem for main shakers with a high g factor. Scalping shakers, however, will still provide insurance for removal of large cuttings and in case the break in a shale shaker screen goes unnoticed.
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.