Chapter 1. Drilling Muds
According to the American Petroleum Institute (API), a drilling fluid is defined as a circulating fluid, used in rotary drilling to perform any or all of the various functions required in drilling operations.
Drilling fluids are mixtures of natural and synthetic chemical compounds used to cool and lubricate the drill bit, clean the hole bottom, carry cuttings to the surface, control formation pressures, and improve the function of the drill string and tools in the hole. They are divided into two general types: waterbased drilling muds (WBMs) and oil-based drilling muds (OBMs). The type of fluid base that is used depends on drilling and formation needs, as well as the requirements for disposing of the fluid after it is no longer needed. Drilling muds are a special class of drilling fluids used to drill most deep wells. The term mud is used because of the thick consistency of the formulation.
Drilling fluids serve several fundamental functions (Brazzel, 2009; Melbouci and Sau, 2008):
ā¢ Control of downhole formation pressures,
ā¢ Overcoming the fluid pressure of the formation,
ā¢ Avoiding damage to the producing formation,
ā¢ Removal of cuttings generated by the drill bit from the borehole, and
ā¢ Cooling and lubricating the drill bit.
In order to perform their fundamental functions, drilling fluids should possess several desirable characteristics, which greatly enhance the efficiency of the drilling operation.
These include desired rheological properties (plastic viscosity, yield value, low-end rheology, and gel strengths), fluid loss prevention, stability under various temperature and pressure operating conditions, stability against contaminating fluids, such as salt water, calcium sulfate, cement, and potassium contaminated fluids (Melbouci and Sau, 2008).
The drilling fluid should also have penetration enhancement characteristics that wet the drill string and keep the cutting surfaces of the drill bit clean (whether it is a roller cone or other configuration).
Wetting ability is at least in part a function of the surface tension of the fluid. The fluid should also have a high degree of lubricity and to minimize friction between the drill string and the wall of the borehole to minimize of differential sticking. In this situation, the hydrostatic pressure of the drilling fluid column must be sufficiently higher than the formation pressure so that the drill string is forced against the wall of the borehole and stuck.
It should also prevent the solids of the formation, primarily shales and clays, from swelling, so reducing the incidence of drill sticking, undergauge holes etc.
Classification of Muds
The classification of drilling muds is based on their fluid phase alkalinity, dispersion, and the type of chemicals used in their formulation. The classification according to (Lyons, 1996) is reproduced in Table 1.1.
Table 1.1 Classification of Drilling Muds
dDispersed systems
|
nNondispersed systems
|
|
Class | Description |
---|
Fresh water mudsd | pH from 7ā9.5, include spud muds, bentonite-containing muds, phosphate-containing muds, organic thinned muds (red muds, lignite muds, lignosulfonate muds), organic colloid muds |
Inhibited mudsd | Water-based drilling muds that repress hydration of clays (lime muds, gypsum muds, sea water muds, saturated salt water muds) |
Low-solids mudsn | Contain less than 3ā6% of solids. Most contain an organic polymer |
Emulsions | Oil in water and water in oil (reversed phase, with more than 5% water) |
OBMs | Contain less than 5% water; mixture of diesel fuel and asphalt |
Drilling muds are usually classified as either WBMs or OBMs, depending upon the continuous phase of the mud. However, WBMs may contain oil and OBMs may contain water (Guichard et al., 2008).
OBMs generally use hydrocarbon oil as the main liquid component, with other materials such as clays or colloidal asphalts being added to provide the desired viscosity together with emulsifiers, polymers, and other additives including weighting agents. Water may also be present, but in an amount not usually greater than 50% by volume of the entire composition. If more than about 5% of water is present, the mud is often referred to as an invert emulsion, i.e., a water-in-oil emulsion.
WBMs conventionally contain viscosifiers, fluid loss control agents, weighting agents, lubricants, emulsifiers, corrosion inhibitors, salts, and pH control agents. Water makes up the continuous phase of the mud, and is usually present as at least 50 volume percent of the entire composition. Oil is also usually present in small amounts, but will typically not exceed the amount of the water, so that the mud will retain its character as a water-continuous-phase material.
Potassium muds are the most widely accepted water mud system for drilling water sensitive shales. K+ ions attach to clay surfaces and lend stability to the shale that is exposed to drilling fluids by the bit. The ions also help to hold the cuttings together, minimizing its dispersion into finer particles. Potassium chloride, KCl is the most widely used source of potassium, with others being potassium acetate, potassium carbonate, potassium lignite, potassium hydroxide, and potassium salt of partially hydrolyzed polyacrylamide (PHPA).
For rheological control, different types of polymers are used, such as xanthan gum and PHPA. For fluid loss control, mixtures of starch and polyanionic cellulose (PAC) are often used. Carboxymethyl starch, hydroxypropyl starch, carboxymethyl cellulose (CMC), and sodium polyacrylate are also ...