Tag: drilling fluid

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Hole cleaning

Good solids control begins with good hole cleaning. One of the primary functions of the drilling fluid is to bring drilled cuttings to the surface in a state that enables the drilling-fluid processing equipment to remove them with ease. To achieve this end, quick and efficient removal of cuttings is essential.
In aqueous-based fluids, when drilled solids become too small to be removed by the solids-control equipment, they are recirculated downhole and dispersed further by a combination of high-pressure shear from the mud pumps, passing through the bit, and the additional exposure to the drilling fluid. The particles become so small that they must be removed via the centrifuge overflow (which discards mud, too) and/or a combination of dilution and chemical treatment. Thus, to minimize mud losses, drilled solids must be removed as early as possible. Figure 2.9 shows a decision tree that can be useful in identifying and solving hole-cleaning problems.

Figure 2-9. Hole-Cleaning Flow Chart.

1. Detection of Hole-Cleaning Problems
Historically, the combination of the necessity to pump or backream out of the hole and a notable absence of cuttings coming over the shale shaker prior to pulling out of the hole has been a reliable indicator of poor hole cleaning. When some cuttings are observed, however, the quantity of cuttings itself does not adequately reflect hole-cleaning efficiency. The nature of those cuttings, on the other hand, provides good clues: Good cuttings transport is indicated by sharp edges on the cuttings, whereas smooth and/or small cuttings can indicate poor hole cleaning and/or poor inhibition. With the advent of PWD (pressure while drilling) tools and accurate flow modeling, a number of other indicators have come to light that foreshadow poor hole cleaning and its attendant consequences. Among these are:
. Fluctuating torque
. Tight hole
. Increasing drag on connections
. Increased ECD when initiating drill string rotation
2. Drilling Elements That Affect Hole Cleaning
Critical elements that can affect hole cleaning include the following:
. Hole angle of the interval
. Flow rate/annular velocity
. Drilling-fluid rheology
. Drilling-fluid density
. Cutting size, shape, density, and integrity
. ROP
. Drill string rotational rate
. Drill string eccentricity
For a given drilling-fluid density, which is generally determined by well bore stability requirements, the hole may be classified into three hole cleaning “zones”according to hole angle:

Generally, in near vertical and moderately inclined hole intervals, annular velocity (AV) has the largest impact upon whether a hole can be cleaned of cuttings. However, in extended-reach, high-angle wells (Zone III), AV places third in critical importance, though there is a critical velocity below which a cuttings bed will not form [Gavignet & Sobey].
In practice, the optimum theoretical flow rate may vary from the achievable flow rate. The achievable flow rate is restricted by surface pressure constraints, nozzle selection, use of MWD (measurement while drilling) tools, and allowable ECD. On the other hand, little is gained from very high AVs. Indeed, above 200 ft/min, little improvement in hole cleaning is usually observed, and the primary effect of increasing AV above this level is to increase ECD. In Zone III applications, lowviscosity
sweeps—so low that the flow regime in the annulus changes from laminar to turbulent—can be effective. Unfortunately, the volume of fluid required to reach critical velocity for turbulent flow is frequently outside the achievable flow rate for hole sizes larger than 8(1/2)-inch and is frequently limited by maximum allowable ECD and/or hole erosion concerns.
Another way to increase AV is to reduce the planned size of the annulus by using larger-OD drill pipe. Not only does a larger pipe generate a smaller annular gap, thereby increasing fluid velocity, it also increases the effect of pipe rotation on hole cleaning. Thus, increasing the OD of drill pipe to 6(5/8)inches with 8-inch tool joints has proven to be effective in aiding the cleaning of 81 2-inch well bores. A caveat: Although reducing the annular gap can greatly improve hole cleaning, it also makes fishing more difficult; indeed, it violates the rule of thumb that stipulates a 1-inch annular gap for washover shoes.
Rheology
In a vertical hole (Zone I), laminar flow with low PV and elevated YP or low n-value and high K-value (from the Power Law model) will produce a flat viscosity profile and efficiently carry cuttings out of the hole [Walker]. Viscous sweeps and fibrous pills are effective in moving cuttings out of a vertical hole.
In a deviated hole (Zones II and III), cuttings have to travel but a few millimeters before they pile up along the low side of the hole. Consequently, not only do cuttings have to be removed from the well bore, they also have to be prevented from forming beds. Frequently a stabilized cuttings bed is not discovered until resistance is encountered while attempting to pull the drill string out of the hole. Close monitoring of pressure drops within the annulus using PWD tools can provide warning of less than optimal hole cleaning. Increased AV coupled with low PV, elevated low-shear-rate viscosity, and high drill string rpm will generally tend to minimize formation of a cuttings bed. To remove a cuttings bed once it has formed, high-density sweeps of low-viscosity fluid at both high and low shear rates, coupled with pipe rotation, are
sometimes effective in cleaning the hole. Viscous sweeps and fibrous pills tend to channel across the top of the drill pipe, which is usually assumed to be lying on the lower side of the hole.
For extended-reach drilling programs, flow loop modeling has generated several rules of thumb for low-shear-rate viscosity to avoid cuttings bed formation. The most popular is the rule that for vertical holes the 6-rpm Fann Reading should be 1.5 to 2.0 times the open-hole diameter [O’Brien and Dobson]. Another rule of thumb specifies a 3-rpm or 6-rpm Fann Reading of at least 10, though 15 to 20 is preferable. However, each drilling fluid has its own rheological characteristics, and these rules of thumb do not guarantee good hole cleaning. If the well to be drilled is considered critical, hole-cleaning modeling by the drilling-fluid service company is a necessity.
NAFs generally provide excellent cuttings integrity and a low coefficient of friction. The latter allows easier rotation and, in extended-reach drilling, more flow around the bottom side of the drill string. As the drill string is rotated faster, it pulls a layer of drilling fluid with it, which in turn disturbs any cuttings on the low side and tends to move them up the hole.
Optimizing the solids-control equipment so as to keep a fluid’s drilledsolids content low tends to produce a low PV and a flat rheological profile, thereby improving the ability of the fluid to clean a hole, particularly in extended-reach wells. The fluid is more easily placed into turbulent flow and can access the bottom side of the hole under the drill pipe more easily. In the Herschel-Bulkley model, a moderate K, a low n (highly shear-thinning), and a high o are considered optimal for good hole cleaning.
Carrying Capacity
Only three drilling-fluid parameters are controllable to enhance moving drilled solids from the well bore: AV, density (mud weight [MW]), and viscosity. Examining cuttings discarded from shale shakers in vertical and near-vertical wells during a 10-year period, it was learned that sharp edges on the cuttings resulted when the product of those three parameters was about 400,000 or higher [Robinson]. AV was measured in ft/min, MW in lb/gal, and viscosity (the consistency, K, in the Power Law model) in cP.
When the product of these three parameters was around 200,000, the cuttings were well rounded, indicating grinding during the transport up the well bore. When the product of these parameters was 100,000 or less, the cuttings were small, almost grain sized.
Thus, the term carrying capacity index (CCI) was created by dividing the product of these three parameters by 400,000:
CCI =(AV)×(MW)×(K)/400,000.
To ensure good hole cleaning, CCI should be 1 or greater. This equation applies to well bores up to an angle of 35°, just below the 45° angle of repose of cuttings. The AV chosen for the calculation should be the lowest value encountered (e.g., for offshore operations, probably in the riser).
If the calculation shows that the CCI is too low for adequate cleaning, the equation can be rearranged (assuming CCI¼1) to predict the change in consistency, K, required to bring most of the cuttings to the surface:
K= 400,000/（MW）×（AV）
Since mud reports still describe the rheology of the drilling fluid in terms of the Bingham Plastic model, a method is needed to readily convert K into PV and YP. The chart given in Figure 2.10 serves well for this purpose. Generally, YP may be adjusted with appropriate additives without changing PV significantly.

Example: A vertical well is being drilled with a 9.0 lb/gal drilling fluid circulating at an AV, with PV=15 cP and YP=5 lb/100 ft2. From Figure 2.10, K=66 cP, and from the CCI equation, CCI=0.07. Clearly, the hole is not being cleaned adequately. Cuttings discarded at the shale shaker would be very small, probably grain size. For a mud of such low density, PV appears to be much too high, very likely the result of comminution of the drilled solids. Solving the equation for the K value
needed to give CCI=1 generates K=890 cP. From Figure 2.10, YP needs to be increased to 22 lb/100 ft2 if PV remains the same (15 cP). If the drilled solids are not removed, PV will continue to increase as drilled solids are ground into smaller particles. When PV reaches 20 cP, YP will need to be raised to 26 lb/100 ft2. As PV increases and YP remains constant, K decreases. It is easier to clean the borehole (or transport solids) if PV is low. Low PV can be achieved if drilled solids are removed at the surface.
Cuttings Characteristics
The drier, firmer, and smaller the cuttings, the easier they are to remove from the hole. Small polycrystalline diamond compact (PDC) bit, small cutters on the bit generate small cuttings, which settle out more slowly than large cuttings and are more easily entrained in the annular column of drilling fluid by drill string rotation. As per Stokes’ law (see Chapter 13 on Centrifuges), large cuttings will fall out of suspension more rapidly than smaller cuttings, but in high-angle holes, even smaller cuttings may settle and form a cuttings bed. Rounded or agglomerated cuttings are indicative of an extended period of time in the hole and poor hole cleaning.
Rate of Penetration
Preventing cuttings beds in deviated wells is far easier than removing them. Controlling instantaneous ROP is one way to avoid overloading the annulus with cuttings. ROP should always be controlled so as to give the fluid enough time to remove the cuttings intact from the bottom of the hole and minimize spiking of the fluid density in the annulus. The treatment for poor hole cleaning is to reduce ROP, circulate the hole clean, and take steps to optimize hole cleaning. Additional information is provided in the next section.
Pipe Rotation
As pipe rotation rate increases, the pipe drags more fluid with it. In deviated wells, this layer of drilling fluid disrupts cuttings beds that have formed around the pipe while lying on the low side of the hole. Step changes appear to be the norm, occurring in most cases at around 85, 120, and 180 rpm. There is some evidence that above 180 rpm, turbulent flow ensues for many fluids. At these high levels, there seems to be little additional benefit to hole cleaning from increasing pipe rotation any
further; most likely this is because cuttings beds cannot form in turbulent flow. During sliding, hole cleaning is minimal and cuttings beds are likely to form. Thus, sliding should be kept to a minimum during any drilling operation. Indeed, this is one of the reasons that rotary steerable tools have become popular.
Drill String Eccentricity
In high-angle wells, the drill string does not remain stable on the bottom of the hole while rotating. The drill string tends to climb the wall of the well bore and fall back, providing additional agitation—though also additional cuttings degradation—while aiding in the removal of cuttings beds on the low side of the hole.

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CHARACTERIZATION OF SOLIDS IN DRILLING FLUIDS

Selecting, arranging, and operating solids-removal equipment to optimize the drilling-fluid cleaning process require accurate information about the intrinsic nature of the cuttings (drilled solids) and solid additives.
1. Nature of Drilled Solids and Solid Additives
Particle size, density, shape, and concentration affect virtually every piece of equipment used to separate drilled solids and/or weighting material from the drilling fluid. In the theoretically perfect well, drilled solids reach the surface with the same shape and size that they had when they were created at the drill bit. In reality, cuttings are degraded by physicochemical interaction with the fluid and mechanical interaction with other cuttings, the drill string, and the well bore.
Cuttings hydrate, become soft, and disperse in aqueous fluids and even in invert-emulsion NAFs with excessively low salinity. On the other hand, cuttings may become more brittle than the formation in highwater- phase-salinity NAFs and can be mechanically degraded by the action of the rotating drill string inside the well bore, particularly in deviated, slim-hole, and extended-reach wells. Cuttings are also degraded by mechanical action. Abrasion of the cuttings by other cuttings, by the steel tubulars, and by the walls of the well bore can lead to rapid comminution of the particles. In summary, cuttings recovered at the surface are generally smaller and frequently more rounded than at their moment of creation, depending on the nature of the cuttings themselves and the drilling fluid. Accordingly, the particle size distribution (PSD) seen at the flowline can range from near-original cutting size to submicron-sized particles.
The surface properties of the drilled solids and weighting material, such as stickiness and amount of adsorbed mud, also can play major roles in the efficiency of a rig solids-separation device. Large, dense particles are the easiest to separate using shale shakers, hydrocyclones, and centrifuges, and the differences in size and density among different types of particles must be well known to design the appropriate piece(s) of equipment for the separation process. Indeed, the optimum efficiency window for each device depends on all four of these parameters: concentration, size, shape, and density. Furthermore, since removal of some— but not all—particles is desirable, characterization of each and every type of particle with respect to those variables is critical. LCM serves as a good example of this. Usually economics dictates removal of large LCM along with cuttings using scalping shakers. Sometimes, however, large concentrations of LCM are required—as much as 50 to 100 ppb— in the circulating system. In such cases, a separate scalping shaker may be installed ahead of the regular battery of shakers to remove the LCM and recycle it back into the mud system [Ali et al ].
2 Physical Properties of Solids in Drilling Fluids
Particle sizes in drilling fluids are classified as shown in Table 2.2 [M-I llc]. PSD is measured using various techniques. For particles >45 mm diameter, wet sieve analysis is simple, accurate, and fast [API RP 13C]. Alternative methods include the American Petroleum Institute (API) sand test, which provides a measure of the total amount of particles >74 mm diameter [API RP 13B1]; microscopic image analysis, whose size limit at the low end depends on the type of microscope employed; sedimentation, for particles 0.5 to 44 mm diameter [Darley & Gray]; Coulter counter, for particles 0.4 to 1200 mm diameter [API RP 13C]; and laser granulometry (also called laser light scattering, diffraction analysis, and Fraunhoffer diffraction), for particles 1 to 700 mm diameter [API RP 13C].

With the Coulter counter, the solids are suspended in a weak electrolyte solution and drawn through a small aperture separating two electrodes, between which a voltage is applied and current flows. As each particle passes through the aperture, it displaces an equal volume of conducting fluid and the impedance between the electrodes increases in a manner that can be correlated with the particle size.
Laser granulometry is rapidly gaining popularity as the method of choice for PSD measurements. In laser granulometry, the solids are dispersed in a transparent liquid and suspended by circulation, if necessary, the slurry may be viscosified with a material like xanthan gum polymer. A beam of light is shone on a sample of the suspended solids, and the intensity versus the angle of the scattered light is analyzed to determine the PSD. Freshwater is used to disperse inert materials like barite. The drilling-fluid base fluid (saltwater, etc.) is used for all other solids (e.g., drilled solids). The sample is diluted to make it sufficiently transparent to obtain accurate readings. The instrument fits the particles to a spherical model to generate a histogram of number of particles versus particle size. For particles that do not fit a spherical model very
well, such as plates or rods, calibration with a known PSD of those particles is preferable. Laser granulometry results also depend on the step size chosen—for instance, for step sizes of 5 mm versus 10 mm, using 5 mm will generate two peaks that are each about half the size of a peak generated using 10 mm. If the step size chosen is too large, the reported PSD may miss some of the fine structure of the spectrum; on the other hand, a step size that is too small will generate excessive oscillations and the spectrum will appear to be very ‘‘noisy.’’


Figure 2.6 shows typical laser granulometry PSD curves for feed, liquid effluent (overflow), and solids discharge (underflow) for a field mud processed by a centrifuge. The efficiency of the device may be calculated from these data. PSD curves for each piece of equipment allow a more detailed understanding of what the device is doing and whether the equipment is optimally configured for the fluid being processed. There are calls within the drilling industry now to make laser granulometers standard equipment on critical wells, particularly high temperature/ high pressure and extended-reach wells, where the equivalent circulating density (ECD) is likely to exceed the fracture gradient.
Adsorbed mud, as well as swelling and/or dispersion of the cuttings resulting from interaction with the mud, can affect the PSD of cuttings. Comminution (degradation) of drilled solids has a strong impact on rheology and the total amount of mud adsorbed on the solids, inasmuch as the forces between the particles and the amount of mud adsorbed on them is proportional to their surface area. Drilled solids generally become comminuted while in the well bore and mud pits, as well as during passage through solids-control devices, through abrasion and chemical interaction with the base fluid. Surface-area increase due to comminution is proportional to the decrease in particle diameter. For example, breaking up a 100-mm-diameter particle into 5-mm particles will increase the total surface area by a factor of 20. Consequently, the
amount of mud adsorbed on the solids in this case will increase roughly by a factor of 20 as a direct result of comminution. Low-shear-rate viscosity will also increase significantly with this increase in total surface area, though the relationship is not strictly linear.
Average particle density, also termed ‘‘true’’ or ‘‘intrinsic’’ density, has units of weight/volume. Specific gravity (SG) is the ratio of the density of the material in question to the density of water and is, of course, unitless. Since the density of water is close to 1 g/cm3 over a wide range of temperature and pressure, the values reported for average particle density and SG are essentially the same. Average particle density should not be confused with bulk density (as often given in the Material Safety Data Sheet), which is a measure of the density of the packaged material. The LeChatelier flask method is the standard for determination of the average particle density of barite and hematite [API 13A]. In this method, one measures the incremental change in volume accompanying the addition of 100 g of the weighting material to a precisely measured volume of kerosene. A more convenient, but less accurate, method for determining density of weighting materials is the air pycnometer
[API RP 13I]. Another convenient method, which is rapidly gaining in popularity, is the stereopycnometer [API RP 13I]. In contrast to the air pycnometer, the stereopycnometer is as accurate as the LeChatelier flask method, and it can be used to measure density of any kind of particulate, including drilled cuttings. The stereopycnometer employs Archimedes’ principle of fluid displacement (helium, in this case) and the technique of gas expansion [API RP 13I].
Particle shape, partly described by the so-called aspect ratio, is not fully quantifiable. Neither is it possible to incorporate the broad spectrum of particle shapes in drilling fluids into particle-separation mathematical models. At this time, an old simple classification scheme is still used: granule, flake, fiber [Wright].
Concentration of particles in a mud is generally measured using aretort (an automatic portable still). The volume percentage of lowgravity solids (% LGS)—clays, sand, and salt—and the volume percentage of high-gravity solids (% HGS)—weighting material—are calculated from the measured volumes of the distilled fluids and the density of the mud. The calculated % LGS serves as an indicator of the effectiveness of the solids-control equipment on the rig. Occasionally both the overflow
and underflow solids from each piece of equipment are reported. Unfortunately, inaccuracies inherent in the retort, combined with the common practice of using an average density for the LGS and an average density for the HGS, can generate considerable uncertainties in % LGS. This is particularly true for low-density fluids, where a slight error in reading the retort will generate misleading—usually high— values of % LGS. However, if the calculated % LGS is below the target
limit (typically 5%), and dilution is not considered excessive, the solidscontrol equipment is considered to be efficient. (Calculation of solidsremoval
efficiency is presented in Chapter 15 on Dilution.) It should be noted that % LGS includes any clays that are purposefully added to the drilling fluid (for viscosity and filtration control). If a fluid contains 20 lb/bbl bentonite, it already contains 2.2% LGS before it acquires any drilled cuttings; in such fluids, the target limit of % LGS may be somewhat higher than 5%.
Concentration of particles affects mud properties, particularly rheology, which in turn affect the amount of residual mud on drilled solids. For noninteracting particles, the Einstein equation describes the effect of particles on the effective viscosity, μe, fairly well:

where μ is the viscosity of the liquid medium and μ is the volume fraction of the inert solids. This effect is independent of particle size, as long as the particles are suspended in the medium. The Einstein equation represents the effect of ‘‘inert’’ particles like barite fairly well, at least until their concentration becomes so great that the particles begin interacting with each other. Most particles in drilling fluids, however, have strong surface charges and interact strongly with each other at any concentration. Since all particles are enveloped by drilling fluid, attractive forces among strongly interacting particles (e.g., clays, drilled solids) generally lead to higher internal friction, hence a higher viscosity. Repulsive forces, such as are generated in muds containing high levels of lignosulfonate or other anionic polymers, will tend to exhibit lower viscosity. Because of these attractive/repulsive forces, strongly interacting particles generate an internal ‘‘structure’’ in a fluid, which manifests
itself most clearly at low fluid velocities. Thus, in most drilling fluids, significant deviations from the Einstein equation are the norm, as is discussed in more detail in the next section.
The viscosity of a drilling fluid must be maintained within certain limits to optimize the efficiency of a drilling operation: low-shear-rate viscosity needs to be high enough to transport cuttings out of the hole efficiently and minimize barite sag, while high-shear-rate viscosity needs to be as low as possible to maintain pumpability, remove cuttings from beneath the bit, and minimize ECD of the mud. In an analogous manner, for efficient operation of solids-control devices, the concentration
of drilled solids needs to be maintained within a specified range [Amoco]. The upper end (e.g., 5%) is particularly important, but the lower end (typically higher than 0%) is also important for most devices.
Stickiness of cuttings and its effect on the performance of solidscontrol devices are only beginning to be investigated. Various properties of the mud, along with lithology of the formation being drilled, are known to affect stickiness of particles, especially cuttings [Bradford et al.]. Generally, separation efficiency of any solids-control device decreases with increasing stickiness of the cuttings. Rheology, shale inhibition potential, and lubricity of the mud all can affect the stickiness of particles, which in turn affects performance of solids-control equipment, especially shale shakers. To handle gumbo (very sticky cuttings consisting primarily of young water-sensitive shale), operators will install special gumbo removal devices ahead of the shakers. To aid in conveyance of gumbo, the shaker screens are kept wet with a fine mist and
angled horizontally or downward toward the discharge end. Gumbo cannot be transported effectively on a linear motion or balanced elliptical
motion screen that is sloped upward.

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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.

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HISTORICAL PERSPECTIVE AND INTRODUCTION

1.1 SCOPE
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.
1.2 PURPOSE
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.
1.3 INTRODUCTION
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.