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Composition and Properties of Drilling and Completion Fluids
By Ryen Caenn H. C. H. Darley George R. Gray
Gulf Professional Publishing
Copyright © 2011 Elsevier Inc.
All right reserved.
ISBN: 978-0-12-383859-9
Chapter One
Introduction to Drilling Fluids
Chapter Outline Functions of Drilling Fluids 2 Composition of Drilling Fluids 2 Properties of Drilling Fluids 5 Density 5 Flow Properties 7 Control of Flow Properties at the Well 12 Filtration Properties 14 pH 16 Alkalinity 17 Cation Exchange Capacity: Methylene Blue Test 17 Electrical Conductivity 18 Lubricity 18 Corrosivity 18
Drilling Fluid Selection 19 Location 21 Mud-Making Shales 21 Geopressured Formations 22 High Temperature 22 Hole Instability 23 Fast Drilling Fluids 24 Rock Salt 24 High Angle Holes 25 Formation Evaluation 25 Productivity Impairment 25 Mud Handling Equipment 26 Solids Removal Equipment 26 Optimization 33 References 34
The successful completion of an oil well and its cost depend to a considerable extent on the properties of the drilling fluid. The cost of the drilling fluid itself is relatively small, but the choice of the right fluid and maintenance of the right properties while drilling profoundly influence the total well costs. For example, the number of rig days required to drill to total depth depends on the rate of penetration of the bit, and on the avoidance of delays caused by caving shales, stuck drill pipe, loss of circulation, etc., all of which are influenced by the properties of the drilling fluid. In addition, the drilling fluid affects formation evaluation and the subsequent productivity of the well.
It follows that the selection of a suitable drilling fluid and the day-to-day control of its properties are the concern not only of the mud engineer, but also of the drilling supervisor, the drilling foreman, and drilling, logging, and production engineers. Drilling and production personnel do not need a detailed knowledge of drilling fluids, but they should understand the basic principles governing their behavior, and the relation of these principles to drilling and production performance. The object of this chapter is, therefore, to provide this knowledge as simply and briefly as possible, and to explain the technical terms so that the information provided by the mud engineer may be comprehensible. Aspiring drilling fluid specialists who have no previous knowledge of drilling fluids should also read this chapter before going on to the more detailed coverage in the subsequent chapters.
FUNCTIONS OF DRILLING FLUIDS
Many requirements are placed on the drilling fluid. Historically, the first purpose of the drilling fluid was to serve as a vehicle for the removal of cuttings from the bore hole, but now the diverse applications for drilling fluids make the assignment of specific functions difficult.
In rotary drilling, the principal functions performed by the drilling fluid are to:
1. Carry cuttings from beneath the bit, transport them up the annulus, and permit their separation at the surface.
2. Cool and clean the bit.
3. Reduce friction between the drilling string and the sides of the hole.
4. Maintain the stability of uncased sections of the borehole.
5. Prevent the inflow of fluids—oil, gas, or water—from permeable rocks penetrated.
6. Form a thin, low-permeability filter cake that seals pores and other openings in formations penetrated by the bit.
7. Assist in the collection and interpretation of information available from drill cuttings, cores, and electrical logs.
In conjunction with the above functions, certain limitations—or negative requirements—are placed on the drill fluid. The fluid should:
1. Not injure drilling personnel nor be damaging or offensive to the environment.
2. Not require unusual or expensive methods of completion of the drilled hole.
3. Not interfere with the normal productivity of the fluid-bearing formation.
4. Not corrode or cause excessive wear of drilling equipment.
COMPOSITION OF DRILLING FLUIDS
Drilling fluids are classified according to their base:
• Water-base muds. Solid particles are suspended in water or brine. Oil may be emulsified in the water, in which case water is termed the continuous phase.
• Oil-base muds. Solid particles are suspended in oil. Water or brine is emulsified in the oil, i.e., oil is the continuous phase.
• Gas. Drill cuttings are removed by a high-velocity stream of air or natural gas. Foaming agents are added to remove minor inflows of water.
In water-base muds the solids consist of clays and organic colloids added to provide the necessary viscous and filtration properties, heavy minerals (usually barite, added to increase the density when needed), and solids from the formation that become dispersed in the mud in the course of drilling. The water contains dissolved salts, either derived from contamination with formation water or added for various purposes. Further details are given in Table 1.1.
The solid particles may be conveniently divided into three groups according to size: (1) colloids, from about 0.005–1 micron (1 micron = 0.001 mm), which impart viscous and filtration properties; (2) silt and barite (sometimes called "inert solids"), 1–50 microns, which provide density as just discussed but are otherwise deleterious; and (3) sand, 50–420 microns (assuming a 40-mesh screen on the shale shaker), which, apart from bridging large openings in certain very porous formations, is objectionable because of its abrasive qualities.
The activity of the colloidal fraction fundamentally is derived from the very small size of the particle (and consequent high surface area) relative to its weight. Because of this high specific surface, the behavior of the particles is governed primarily by the electrostatic charges on their surfaces, which give rise to attractive or repulsive interparticle forces. Clay minerals are particularly active colloids, partly because of their shape—tiny crystalline platelets or packets of platelets—and partly because of their molecular structure, which results in high negative charges on their basal surfaces, and positive charges on their edges. Interaction between these opposite charges profoundly influences the viscosity of clay muds at low flow velocities, and is responsible for the formation of a reversible gel structure when the mud is at rest.
Clays as they occur in nature are composed of various clay minerals, such as montmorillonite, illite, and kaolinite, of which montmorillonite is by far the most active. Other minerals, such as quartz, feldspar, calcite, etc., may also be present, in both the colloidal and silt-size ranges. When clays are mixed with water, the viscosity of the resulting mud per unit weight of clay added depends on the proportion of the various clay and other minerals present. Commercial clays that are used in drilling muds are rated by their yield, which is defined as the number of 42-gallon barrels (0.16 m3) of mud with an apparent viscosity of 15 centipoises produced by a ton (2000 lb; 907 kg) of clay. Figure 1.1 shows that Wyoming bentonite, which contains about 85% montmorillonite, has by far the greatest yield. Similarly, in the drilling well, the rise in mud viscosity per foot of hole drilled is much greater when drilling in rich formations, such as the recent montmorillonitic sediments of the Gulf Coast, than when drilling in lean formations, such as the silty shales of the Mid-Continent. In the former case, the viscosity must be kept within bounds by chemical treatment, dilution, or mechanical separation of drilled solids at the surface. In the latter case, the silts must be removed by mechanical separation, and the necessary rheological and filtration properties must be obtained by adding commercial clays.
Clay colloids are sometimes supplemented, or even entirely replaced, by organic colloids when required by particular problems. For instance, if clays are flocculated by soluble salts with consequent loss of rheological and filtration control, salt-resistant colloids (such as pregelatinized starch or cellulosic polymers) are added to salt water, or to salt-contaminated muds. Cellulosic, polyacrylic, and natural gum polymers are also used in low-solid muds to help maintain hole stability and to minimize dispersion of drill cuttings into the mud. These polymers consist of long chains of unit cells, which are adsorbed on the surface of the cuttings, protecting the cuttings from disintegration. The viscous properties of these polymers are mainly due to mechanical interference between the chains, which do not build gel structures (except in the case of one polymer whose chains can be crosslinked by chemical bonding).
The colloidal fraction of one type of oil-base mud consists of oxidized asphalt. Viscous and filtration properties are obtained in another type (known as invert emulsion) by tightly emulsifying substantial quantities of water. Gel structures may be obtained by adding clays treated with surfactants so as to make them dispersible in oil, and similarly treated lignite may be added to obtain improved filtration properties, if these are required.
PROPERTIES OF DRILLING FLUIDS
Density
Density is defined as weight per unit volume. It is expressed either in pounds per gallon (lb/gal) or pounds per cubic foot (lb/ft3), or in kilograms per cubic meter (kg/m3), or compared to the weight of an equal volume of water, as specific gravity (SG). The pressure exerted by a static mud column depends on both the density and the depth; therefore, it is convenient to express density in terms of pounds per square inch per foot (psi/ft), or kilograms per square centimeter per meter (kg/cm2/m). The densities of some mud components are given in Table 1.2. The relationship between various units of measurement used in this section are given in the Appendix, Table A.1.
In order to prevent the inflow of formation fluids and to lay down a thin, low-permeability filter cake on the walls of the hole, the pressure of the mud column must exceed the pore pressure—the pressure exerted by the fluids in the pores of the formation—by at least 200 psi (14 kg/cm2). The pore pressure depends on the depth of the porous formation, the density of the formation fluids, and the geological conditions. Two types of geological conditions affect pore pressure: normally pressured formations, which have a self-supporting structure of solid particles (so the pore pressure depends only on the weight of the overlying pore fluids), and abnormally pressured or geopressured formations, which are not fully compacted into a self-supporting structure (so the pore fluids must bear the weight of some or all of the overlying sediments as well as the weight of the overlying fluids). The hydrostatic pressure gradient of formation fluids varies from 0.43 psi/ft to over 0.52 psi/ft (0.1 to 0.12 kg/cm2/m), depending on the salinity of the water.
The bulk density of partially compacted sediments increases with depth, but an average SG of 2.3 is usually accepted, so that the overburden (or geostatic or litholostatic) pressure gradient is about 1 psi/ft (0.23 kg/cm2/m), and the pore pressure of geopressured formations is somewhere between the normal and the overburden pressure gradients, depending on the degree of compaction. Besides controlling pore fluids, the pressure of the mud column on the walls of the hole helps maintain borehole stability. In the case of plastic formations, such as rock salt and unconsolidated clays, the pressure of the mud is crucial. The buoyant effect of the mud on the drill cuttings increases with its density, helping transport them in the annulus, but retarding settling at the surface. Very rarely is an increase in mud density justified as a means of improving cutting carrying capacity.
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Excerpted from Composition and Properties of Drilling and Completion Fluids by Ryen Caenn H. C. H. Darley George R. Gray Copyright © 2011 by Elsevier Inc.. Excerpted by permission of Gulf Professional Publishing. All rights reserved. No part of this excerpt may be reproduced or reprinted without permission in writing from the publisher.
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