The study of History is the beginning of wisdom. – Jean Bodin
The actual money saved by using correct drilling fluids processing is difficult to document. Most operators regard the cost of drilling wells as proprietary information.
However, the economics of having the correct homogeneous fluid in the drill pipe in case of a kick is almost self-evident. The inability to determine the underbalanced pressure could be disastrous or could just require much extra rig time to handle. The benefit of having good solids control practice is more difficult to quantify. Very few drilling programs schedule stuck pipes or other problems caused by drilled solids in the drilling fluid. How can you prove something didn’t happen because of some action taken?
Case histories are difficult to find when related to poor solids control. One event stands out in the past experience of one of the authors. A platform was scheduled to drill twelve wells. While drilling the sixth well, the operator was unhappy with the ability to control drilling fluid properties, especially the low gravity solids concentration. An evaluation of the plumbing revealed many problems. The contractor (who will remain anonymous) thought every pump should be able to pump from and to any compartment. The needed plumbing changes were so daunting that the recommendation from the rig was that it would cost too much. Operator management made the decision to modify the drilling fluid processing system. At the end of the sixth well, six welders were sent to the rig and spent several days modifying the system at a cost of 10% of the AFE of well number six. The savings on well number seven, because of the elimination of visible and invisible NPT, was much greater than the funds spent changing the system. That savings accrued on all of the rest of the wells.
Drilled solids management has evolved over the years as drilling becomes more challenging and environmental concerns are paramount. Equipment changes and improvements
have responded to the necessity of creating more and more expensive drilling fluids. Probably the largest impact was the recognition that polymers could make much better drilling fluids despite the cost. Polymer drilling fluids required lower drilled solids concentration so superior solids removal systems were developed to meet those demands. A historical perspective, including drilling fluid management, specifications, solids control, and auxiliary processes, provides a clear and complete picture of the evolution of current equipment and practices. The negative impact of drilled solids on drilling costs, performance, and non-productive time has been well documented in recent years. However, there have been many skeptics because the effects are not always immediately observed.
Drilling fluid was used in the mid-1800s in cable tool (percussion) drilling to suspend the cuttings until 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 wellbore. Clays were being added to the drilling fluid by the 1890s.
At the time Spindle top 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 the Spindle top, cuttings need to be brought to the surface by the circulating fluid. Water was insufficient so mud from mud puddles, spiked with some hay, was circulated downhole to bring rock cuttings to the surface.
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 “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. Based on the sole judgment of the driller or tool pusher, a system of pits and ditches were traditionally dug on-site to separate cuttings from the drilling fluid by gravity settling. This system included a ditch from the well, 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 the 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. Sometime later, steel pits were used with partitions between compartments. This partition 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 would fill with cuttings and the fluid became too thick to pump because of the finely ground cuttings being carried along in the drilling fluid. To remedy this problem, jets were placed in the settling pits to move the unusable drilling fluid to a reserve pit. Then 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 solved. Ore dressing plants and coal tipples were using:
- Fixed Bar Screens Placed on an Incline.
- Revolving Drum Screens.
- Vibrating screens
The fixed bar screens are currently used as “gumbo” busters, to remove very sticky clay from the drilling fluid. 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 wellbore. The drilling fluid flowing into the machine turned a paddle wheel which rotated the drum screen through which the drilling fluid flowed. These units were quite popular because no electricity was required and the settling pits did not fill so quickly. Currently, revolving drum units have just about disappeared from the scene. The screens were very coarse, API 4 to API 10, and sometimes with a fine screen (an API 12). The number after the “API” designation refers to the mesh size.
Mesh is the number of openings per inch. Common practice was to identify a “10-mesh” screen as one which has 10 openings in each direction or a square mesh screen.
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 to reduce the size and weight of the unit for transporting between locations. The name “shale shaker” was adopted to distinguish the difference between shakers used in mining and shale shakers used in oil well drilling. This nomenclature was necessary since both shakers were obtained from the same suppliers. The first publication about using a shale shaker in drilling operations described a “vibrating screen to clean mud” was in The Oil Weekly, October 17, 1930. The shaker screen was a 30-mesh, four by five feet, and supported by four coil springs.
Development of Solids Remove Equipment in the 1940s
These shale shakers had 4 ft. by 5 ft. hook strip screens mounted that were tensioned from the sides with tension bolts. The vibrators were usually mounted above the screens causing the screen 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 an API 20 to API 30 (838-541 micron). These units were the predominant shakers in the industry until the late 1950s. Even though superseded by circular motion in the 1960s and linear motion shale shakers in the 1980s, the unbalanced elliptical motion shale shakers are still in demand and are still manufactured today.
Development of Solids Remove Equipment in the 1950s
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 hydro-cyclone “desander”, and was introduced to the industry around the late 1950s. The basic principle of the separation of heavier (and coarser) materials from the drilling fluid is 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 caused heavier particles to move outward against the walls of the cones. These heavier particles exit the bottom of the cone and the cleaner drilling fluid exits the top of the cone. The desander, which ranges in size from 6 to 12 inches in diameter, removes most solids larger than 30-60 mm. During the past few decades, 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 sidewall 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 remove solids called “silt” down to 15-30 microns.
George Ormsby, then with Pioneer Centrifuge Company, related a story about the first desilter that they installed on a drilling rig. 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 the unweighted drilling fluid. After two days, however, the rig personnel called to have the equipment picked up “because it was no longer working”. When George arrived at the location, the equipment was completely buried in drilled solids so there was no way more solids could be removed by the hydrocyclones.
During this period, research recognized the problems associated created with ultra fines (colloidal) in sizes less than 10 mm. These ultra-fines “tie up” or trap large amounts of liquid and create viscosity problems that were traditionally solved only by water additions (dilution). As large cuttings are ground into smaller particles, the surface area increases greatly even though the total volume of cuttings does not change. Centrifuges, which had been used in many industries for years, were adapted to drilling operations in the early 1950s to remove and discard colloidal solids from weighted drilling fluids. The heavy slurry containing drilled solids and barite larger than about 10 mm 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.
Development of Solids Remove Equipment in the 1960s
These hydrocyclones were usually loaded with solids because of the coarse screens on the shale shakers. Removing more of the intermediate-size 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 “fine screen-high speed” shakers for two reasons:
- 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 tearing.
- The screen basket required greater development expertise than that required for earlier modifications in drilling fluid handling equipment.
Tandem shakers have a top screen with larger openings for removal of larger particles and a bottom screen with smaller openings (finer 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. The screens can be made of larger wires so they had greater strength. Layered screens (fine mesh screen for good solids removal over a coarse mesh screen for strength) was developed in the 1960s. 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 80XAPI 80 (177 microns).
Development of Solids Remove Equipment in the 1970s
In the 1970s the mud cleaner was developed. At that time, no shale shaker could handle the full rig flow on an API 200 screen. Desanders and desilters were normally used after the shale shaker in unweighted drilling fluid; however, they discard large quantities of barite when used on weighted drilling fluid. This meant that the drilled solids larger than an API 80 and API 200 (the upper limit of the barite size) could not be removed from the drilling fluid. API specifications currently allow three weight percent of barite larger than 74 mm, which is an API 200 screen. To solve this problem, the underflow from desanders and desilters was reported to a pre-tensioned API 200 screen on a shaker. Much of the liquid from the underflow of the hydrocyclones and most of the barite passes through an API 200 screen. This was also the first successful oilfield application of a pre-tensioned fine screen bonded to a rigid frame. Some 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.
Development of Solids Remove Equipment in the 1980s
In the 1980s the linear motion shale shaker was developed. The first commercial unit, called a Shimmy Shaker, used hydraulic pistons to move screens in a straight line. This entry went out of business in a short time. This version had screens that sloped downward from the back tank instead of creating a pool of liquid and transporting solids up an incline. Two electric vibrators were introduced that caused the screen to vibrate with a linear motion. 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. The pool of liquid provided an additional head to help to drill fluid pass through the screen. Screens with smaller openings, such as API 200 (74 mm), 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 pre-tensioned screens to be layered and, in some cases, have three-dimensional surfaces.