Drilling Fluids Properties and Classification Systems

Drilling Fluids: A drilling fluid is any fluid which is circulated through a well in order to remove cuttings from a wellbore. This section will discuss fluids which have water or oil as their continuous phase. Air, mist and foam, which can be used as drilling fluids, will not be discussed at this time. A drilling fluid must fulfill many functions in order for a well to be drilled successfully, safely, and economically. The most important functions are: Remove drilled cuttings from under the bit, Carry those cuttings out of the hole, Suspend cuttings in the fluid when circulation is stopped, Release cuttings when processed by surface equipment, Allow cuttings to settle out at the surface, Provide enough hydrostatic pressure to balance formation pore pressures, Prevent the bore hole from collapsing or caving in, Protect producing formations from damage which could impair production and Clean, cool, and lubricate the drill bit.

Drilling Fluid Properties: For those working at wellsites, a basic knowledge of “fluid” properties is required, especially those properties that distinguish fluids from solids. Fluids can be either a gas or a liquid, where gases are highly compressible and its volume being dependent upon pressure and temperature. Liquids, on the other hand, are only slightly compressible, and their volume being only slightly dependent upon temperature. We shall be dealing with only liquids in this text. Since drilling muds are commonly referred to as drilling fluids, the term “fluid” will be used throughout the text. The effects of temperature and pressure on a volume of drilling fluid will be ignored. A cube of water measuring 1 foot along each edge weighs 62.4 lbs. The density or “specific weight” is then 62.4 lb/ft 3. Specific weight divided by the gravitational constant is known as “mass density” or just density. This same cube of water exerts a hydrostatic pressure of 62.4 lbs distributed evenly over its bottom surface of 1 ft2 or 0.433 psi (62.4lbs 144 in2).

Hydrostatic pressure of a column of fluid is thus determined by:

Hp      =    (Dv – Fl) x MD x g where: Hp  = hydrostatic pressure.

Dv = vertical depth. Fl = flowline depth. MD  = fluid density. g   = gravitational constant.

Note that this is dependent upon vertical depth and fluid density. In oilfield units the fluid density will be the “mud density”, with a conversion factor 0.0519. The conversion factor is derived from: There are 7.48 gallons in 1 cu/ft and 144 sq inches in 1 sq/ft because:    lb/gal x 7.48 gal/ft3  x 1/144 ft2/in2  = psi/ft and: 7.48/144 = psi/ft/lb/gal therefore: 0.0519 = psi/ft/lb/gal. A drilling fluid of 8.34 lb/gal exerts a pressure of; 8.34 x 0.0519 = 0.4328 psi/ft. In SI units the conversion factor is 0.0098, therefore: Hp (kPa) = MD (kg/m3) x Dv(m) x 0.0098

Drilling Fluid Additives: Many substances, both reactive and inert, are added to drilling fluids to perform specialized functions. The most common functions are:

Alkalinity and pH Control: Designed to control the degree of acidity or alkalinity of the drilling fluid. Most common are lime, caustic soda and bicarbonate of soda.

Bactericides: Used to reduce the bacteria count. Paraformaldehyde, caustic soda, lime and starch preservatives are the most common.

Calcium Reducers: These are used to prevent, reduce and overcome the contamination effects of calcium sulfates (anhydrite and gypsum). The most common are caustic soda, soda ash, bicarbonate of soda and certain polyphosphates

Corrosion Inhibitors: Used to control the effects of oxygen and hydrogen sulfide corrosion. Hydrated lime and amine salts are often added to check this type of corrosion. Oil-based muds have excellent corrosion inhibition properties.

Defoamers: These are used to reduce the foaming action in salt and saturated saltwater mud systems, by reducing the surface tension.

Emulsifiers: Added to a mud system to create a homogeneous mixture of two liquids (oil and water). The most common are modified lignosulfonates, fatty acids and amine derivatives.

Filtrate Reducers: These are used to reduce the amount of water lost to the formations. The most common are bentonite clays, CMC (sodium carboxymethylcellulose) and pre-gelatinized starch.

Flocculants: These are used to cause the colloidal particles in suspension to form into bunches, causing solids to settle out. The most common are salt, hydrated lime, gypsum and sodium tetraphosphates.

Foaming Agents: Most commonly used in air drilling operations. They act as surfactants, to foam in the presence of water.

Lost Circulation Materials: These inert solids are used to plug large openings in the formations, to prevent the loss of whole drilling fluid. Nut plug (nut shells), and mica flakes are commonly used.

Lubricants: These are used to reduce torque at the bit by reducing the coefficient of friction. Certain oils and soaps are commonly used.

Pipe-Freeing Agents: Used as spotting fluids in areas of stuck pipe to reduce friction, increase lubricity and inhibit formation hydration. Commonly used are oils, detergents, surfactants and soaps.

Shale-Control Inhibitors: These are used to control the hydration, caving and disintegration of clay/ shale formations. Commonly used are gypsum, sodium silicate and calcium lignosulfonates.

Surfactants: These are used to reduce the interfacial tension between contacting surfaces (oil/water, water/solids, water/air, etc.).

Weighting Agents: Used to provide a weighted fluid higher than the fluids specific gravity. Materials are barite, hematite, calcium carbonate and galena.

Drilling Fluid Classification Systems: Non-Dispersed System: This mud system consists of spud muds, “natural” muds, and other lightly treated systems. Generally used in the shallower portions of a well.

Dispersed Mud Systems: These mud systems are “dispersed” with deflocculants and filtrate reducers. Normally used on deeper wells or where problems with viscosity occur. The main dispersed mud is a “lignosulfonate” system, though other products are used. Lignite and other chemicals are added to maintain specific mud properties.

Calcium-Treated Mud Systems: This mud system uses calcium and magnesium to inhibit the hydration of formation clays/shales. Hydrated lime, gypsum and calcium chloride are the main components of this type of system.

Polymer Mud Systems: Polymers are long-chained, high molecular-weight compounds, which are used to increase the viscosity, flocculate clays, reduce filtrate and stabilize the borehole. Bio-polymers and cross-linked polymers, which have good shear-thinning properties, are also used.

Low Solids Mud System: This type of mud system controls the solids content and type. Total solids should not be higher than 6% to 10%. Clay content should not be greater than 3%. Drilled solids to bentonite ratio should be less than 2:1.

Saturated Salt Mud Systems: A saturated salt system will have a chloride content of 189,000 ppm. In saltwater systems, the chloride content can range from 6,000 to 189,000 ppm. Those at the lower end are normally called “seawater” systems.

These muds can be prepared with fresh or salt water, then sodium chloride or other salts (potassium, etc.) are added. Attapulgite clay, CMC or starch is added to maintain viscosity.

Oil-Based Mud Systems: There are two types of systems: 1) invert emulsion, where water is the dispersed phase and oil the continuous phase (water-in-oil mud), and 2) emulsion muds, where oil is the dispersed phase and water is the continuous phase (oil-in-water mud). Emulsifiers are added to control the rheological properties (water increases viscosity, oil decreases viscosity).

Air, Mist, Foam-Based Mud Systems: These “lower than hydrostatic pressure” systems are of four types: 1) dry air or gas is injected into the borehole to remove cuttings and can be used until appreciable amounts of water are encountered, 2) mist drilling is then used, which involves injecting a foaming agent into the air stream, 3) foam drilling is used when large amounts of water is encountered, which uses chemical detergents and polymers to form the foam, and 4) aerated fluids is a mud system injected with air to reduce the hydrostatic pressure.

Workover Mud Systems: Also called completion fluids, these are specialized systems designed to 1) minimize formation damage, 2) be compatible with acidizing and fracturing fluids, and 3) reduce clay/shale hydration. They are usually highly treated brines and blended salt fluids.

Make-up of a Drilling Fluid: In its most basic form a drilling fluid is composed of a liquid (either water or oil) and some sort of viscosifying agent. If nothing else is added, whenever the hydrostatic pressure is greater than the formation pore pressure (and the formation is porous and permeable) a portion of the fluid will be flushed into the formation. Since excessive filtrate can cause borehole problems, some sort of filtration control additive is generally added. In order to provide enough hydrostatic pressure to balance abnormal pore pressures, the density of the drilling fluid is increased by adding a weight material (generally barite).

In summary, a drilling fluid consists of: The Base Liquid, Water – fresh or saline, Oil – diesel or crude, Mineral Oil or other synthetic fluids Dispersed Solids, Colloidal particles, which are suspended particles of various sizes Dissolved Solids and Usually salts, and their effects on colloids most is important. All drilling fluids have essentially the same properties, only the magnitude varies. These properties include density, viscosity, gel strength, filter cake, water loss, and electrical resistance.

Normal Drilling Fluids: Though this type of drilling fluid is easy to describe, it is hard to define and even more difficult to find. In the field, a normal fluid generally means there is little effort expended to control the range of properties. As such, it is simple to make and control. General rules include:

  • It is used where no unexpected conditions occur
  • The mud will stabilize, so its properties are in the range required to control hole conditions
  • The chief problem is viscosity control

Formations usually drilled with this type of mud are shales and sands. Since viscosity is the major problem, the amount and condition of the colloidal clay is important. To do this, two general types of treatment are used:

Water soluble polyphosphates

  1. they reduce viscosity
  2. can be used alone or with tannins
  3. if filter cake and filtration control is required - add colloidal clay to system

Caustic Soda and Tannins

  1. they also reduce viscosity
  2. used under more severe conditions than phosphate treatment

Special Drilling Fluids: These drilling fluids are made to combat particular abnormal hole conditions or to accomplish specific objectives. These are:

  1. Special Objectives
    • faster penetration rates
    • greater protection to producing zones
  2. Abnormal Hole Conditions
    • long salt sections
    • high formation pressures

1 Comment

  1. Contamination of Water-Based Drilling Fluids: Hydraulics and hole cleaning optimization depends on the drilling fluid and its ability to carry out its required functions. This ability can be severely compromised by the presence of contaminants. A contaminant is any type of material that has a detrimental effect on the physical or chemical characteristics of a drilling fluid. What constitutes a contaminant in one type of drilling fluid may not necessarily be a contaminant in another. A contaminant can be a solid, liquid or gas, although solids are by far the most prevalent. Excessive solids, whether they are additives or come from the formation, lead to unfavorable rheological properties and slow the drilling rate. Most other contaminants are chemical in nature and require chemical treatment to restore fluid properties. While there are specific treatments for each contaminant, it is not always possible to remove the contaminant from the system. Some contaminants can be predicted and treated in advance of problems occurring. These “predictable” contaminants might include cement, make-up water, and sometimes salt, gypsum and acid gases such as hydrogen sulfide and carbon dioxide. Pretreatment can be advantageous as long as it is not excessive and does not adversely affect mud properties. Other contaminants may be unexpected and unpredictable, and their concentrations may increase only gradually.
    Eventually, the contaminant shows its effect by altering the fluid properties. This change in fluid properties often occurs at times when deflocculants are expended at high downhole temperatures. It is essential to keep accurate records of drilling fluid properties to ensure that any gradual buildup of a contaminant is monitored and detected. It should be noted that water chemistry is more straightforward than the chemistry of drilling fluids. Organic materials not only interfere with the accuracy of titrations, but they also interfere with the treatment. For example, the addition of calcium ion to remove carbonates may result in the formation of calcium salts of organic acids (reaction between Ca++ and lignite) and calcium silicates. Both of these reactions are undesirable, but unavoidable. Treating contaminants, therefore, should be preceded by pilot testing and then, treating should be done with caution, particularly when high density fluids are involved. Since changes in physical mud properties such as increased rheology and fluid loss due to flocculation are similar regardless of which chemical contaminant is present, the changes in physical properties indicate only that a contaminant exists. An analysis of the changes in chemical properties is necessary to identify the contaminant. The salt or chlorides concentration of the mud is monitored as an indicator of contamination. The salt contamination may come from water used to make mud, salt beds or from saline formation waters.

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