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.

Figure 2.3. Effect of Solids on Mud Weight of Water-Based MudsFigure 2.4. Effect of Mud Weight and MBT on Viscosity of Acceptable WBM.
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].

Figure 2.5. Drilling Fluid Circulating System
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:

dilution volume

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.

Drilling Fluid Selection

Drilling-fluid costs can constitute a significant fraction of the overall costs of drilling a well. Often the cost is quoted per unit length drilled, which takes into account any problems encountered (and avoided), such as stuck pipe. In many cases, the cost ascribed to the fluid also includes costs associated with solids control/management and waste disposal.

tablet system

Thus, it is just as important to minimize costs associated with these two aspects as it is to ensure that the drilling fluid fulfills its primary functions [Young & Robinson]. Muds that require special attention and equipment to control the levels and types of solids frequently incur higher costs. Likewise, muds that generate waste fluid and cuttings, which must be hauled off (and perhaps treated) rather than discharged directly into the environment, generally incur higher costs.
Until recently, waste WBMs did not require any treatment and could be discharged directly into the environment. However, a number of components in WBMs are becoming increasingly restricted or prohibited. Chrome-containing materials, such as chrome lignosulfonates, are prohibited in many areas by governmental regulations. Tight restrictions are imposed in many areas on chloride, nitrate, and potassium salts, or, more generally, on the total electrical conductivity of the mud. In the North Sea, use of polyacrylamide polymers, such as partially hydrolyzed polyacrylamide (PHPA), is also severely restricted. OBMs tend to be restricted even more than WBMs, especially offshore, and in many places they can be used only if a zero discharge strategy (sometimes called a closed loop system) is adopted [Lal & Thurber].
On the other hand, SBMs often can be discharged directly into the sea if they meet certain toxicity/biodegradability criteria and, in the United States, do not create a sheen; as a result, though SBMs generally incur higher initial costs than OBMs, disposal costs for SBMs tend to be considerably less, which can make them more economical to run.

Types of drilling fluids

Drilling fluids are classified according to the type of fluids and other primary ingredients

1.Gaseous:Air, nitrogen
2.Aqueous: Gasified–foam, energized(including aphrons)clay, polymer, emulsion
3.Nonaqueous:Oil or synthetic–all oil, invert emulsion

True foams contain at least 70% gas(usually N2,CO2,or air)at surface of the hole,while energized fluids, including aphrons, contain lesser amounts of gas.Aphrons are specially stabilized bubbles that function as a bridging or lost circulation material(LCM)to reduce mud losses to permeable and microfractured formation.Aqueous drilling fluids are generally dubbed water-based muds (WBMs), while nonaqueous drilling fluids (NAFs) are often referred to as oil-based muds (OBMs) or synthetic-based muds (SBMs). OBMs are based on NAFs that are distilled from crude oil; they include diesel, mineral oils, and refined linear paraffins (LPs). SBMs, which are also known as pseudo– oil-based muds, are based on chemical reaction products of common feedstock materials like ethylene; they include olefins, esters, and synthetic LPs.

Type of invert-emulsion mud

Detailed classification schemes for liquid drilling fluids are employed that describe the composition of the fluids more precisely. One such classification scheme is shown in Figures 2.1 and 2.2. An even more precise classification scheme is described in Table 2.1, which includesthe mud systems most commonly used today, along with their principal components and general characteristics.

Functions of Drilling Fluids

A drilling fluid, or mud, is any fluid that is used in a drilling operation in which that fluid is circulated or pumped from the surface, down the drill string, through the bit, and back to the surface via the annulus.
Drilling fluids satisfy many needs in their capacity to do the following
[M-I llc]:
. Suspend cuttings (drilled solids), remove them from the bottom of the    hole and the well bore, and release them at the surface
. Control formation pressure and maintain well-bore stability
. Seal permeable formations
. Cool, lubricate, and support the drilling assembly
. Transmit hydraulic energy to tools and bit
. Minimize reservoir damage
. Permit adequate formation evaluation
. Control corrosion
. Facilitate cementing and completion
. Minimize impact on the environment
. Inhibit gas hydrate formation
The most critical function that a drilling fluid performs is to minimizethe concentration of cuttings around the drill bit and throughout the well bore. Of course, in so doing, the fluid itself assumes this cuttings burden, and if the cuttings are not removed from the fluid, it very quickly loses its ability to clean the hole and creates thick filter cakes. To enable on-site recycling and reuse of the drilling fluid, cuttings must be continually and efficiently removed.