The two most common types of drilling fluid used are water based mud and oil based mud. Water-based muds (WBM) are those drilling fluids in which the continuous phase of the system is water (salt water or fresh water) and Oil-based muds (OBM) are those in which the continuous phase is oil. WBM’s are the most commonly used muds world-wide. However, drilling fluids may be broadly classified as liquids or gases (Figure 1). Although pure gas or gas-liquid mixtures are used they are not as common as the liquid based systems. The use of air as a drilling fluid is limited to areas where formations are competent and impermeable (e.g. West Virginia). The advantages of drilling with air in the circulating system are: higher penetration rates; better hole cleaning; and less formation damage. However, there are also two important disadvantages: air cannot support the sides of the borehole and air cannot exert enough pressure to prevent formation fluids entering the borehole. Gas-liquid mixtures (foam) are most often used where the formation pressures are so low that massive losses occur when even water is used as the drilling fluid. This can occur in mature fields where depletion of reservoir fluids has resulted in low pore pressure.
Water based muds are relatively inexpensive because of the ready supply of the fluid from which they are made – water. Water-based muds consist of a mixture of solids, liquids and chemicals. Some solids (clays) react with the water and chemicals in the mud and are called active solids. The activity of these solids must be controlled in order to allow the mud to function properly. The solids which do not react within the mud are called inactive or inert solids (e.g. Barite). The other inactive solids are generated by the drilling process. Fresh water is used as the base for most of these muds, but in offshore drilling operations salt water is more readily available. Figure 2 shows the typical composition of a water-based mud.
The main disadvantage of using water based muds is that the water in these muds causes instability in shales. Shale is composed primarily of clays and instability is largely caused by hydration of the clays by mud containing water. Shales are the most common rock types encountered while drilling for oil and gas and give rise to more problems per meter drilled than any other type of formation. Estimates of worldwide, nonproductive costs associated with shale problems are put at $500 to $600 million annually (1997). In addition, the inferior wellbore quality often encountered in shales may make logging and completion operations difficult or impossible.
Over the years, ways have been sought to limit (or inhibit) interaction between WBMs and water-sensitive formations. So, for example the late 1960s, studies of mud-shale reactions resulted in the introduction of a WBM that combines potassium chloride (KCl) with a polymer called partially-hydrolyzed polyacrylamide – KCI-PHPA mud. PHPA helps stabilize shale by coating it with a protective layer of
polymer. The role of KCI will be discussed later.
The introduction of KCI-PHPA mud reduced the frequency and severity of shale instability problems so that deviated wells in highly water-reactive formations could be drilled, although still at a high cost and with considerable difficulty. Since then, there have been numerous variations on this theme, as well as other types of WBM aimed at inhibiting shale.
In the 1970s, the industry turned increasingly towards oil-based mud, OBM as a means of controlling reactive shales. Oil-based muds are similar in composition to water-based except that the continuous phase is oil. In an invert oil emulsion mud (IOEM) water may make up a large percentage of the volume, but oil is still he continuous phase. (The water is dispersed throughout the system as droplets). Figure 3 shows the typical composition of OBM’s.
OBM’s do not contain free water that can react with the clays in the shale. OBM not only provides excellent wellbore stability but also good lubrication, temperature stability, a reduced risk of differential sticking and low formation damage potential. Oil-based muds therefore result in fewer drilling problems and cause less formation damage than WBM’s and they are therefore very popular in certain areas. Oil muds are however more expensive and require more careful handling (pollution control) than WBM’s. Full-oil muds have a very low water content (<5%) whereas invert oil emulsion muds (IOEM’s) may have anywhere between 5% and 50% water content.
The use of OBM would probably have continued to expand through the late 1980s and into the 1990s but for the realization that, even with low-toxicity mineral base-oil, the disposal of drilled cuttings contaminated by OBM can have a lasting environmental impact. In many areas this awareness led to legislation prohibiting or limiting the discharge of these wastes. This, in turn, has stimulated intense activity to find environmentally acceptable alternatives and has boosted WBM research.
To develop alternative nontoxic muds that match the performance of OBM requires an understanding of the reactions that occur between complex, often poorly characterized mud systems and equally complex, highly variable shale formations.
In recent years the base oil in OBMs has been replaced by synthetic fluids such as esters and ethers. Oil based muds do contain some water but this water is in a discontinuous form and is distributed as discrete entities throughout the continuous phase. The water is therefore not free to react with clays in Shale or in the productive formations.
Institute of Petroleum Engineering, Heriot-Watt University