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.

types of drilling fluids

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.

drilling 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

As fluid is circulated through the drillstring, across the bit and up the annulus of the wellbore the power of the mud pumps will be expended in frictional pressure losses. The efficiency of the drilling process can be significantly enhanced if approximately. 65% of this power is expended at the bit. The pressure losses in he system are a function of the geometry of the system and the mud properties such as viscosity, yield point and mud weight. The distribution of these pressure losses can be controlled by altering the size of the nozzles in the bit and the flowrate through the system.

Data from adjacent wells will be useful in predicting borehole stability problems that can occur in troublesome formations (eg unstable shales, highly permeable zones, lost circulation, overpressured zones)
Shale instability is one of the most common problems in drilling operations. This instability may be caused by either one or both of the following two mechanisms:
1. The pressure differential between the bottomhole pressure in the borehole and      the pore pressures in the shales and/or,
2. Hydration of the clay within the shale by mud filtrate containing water.

The instability caused by the pressure differential between the borehole and the pore pressure can be overcome by increasing the mudweight. The hydration of the clays can only be overcome by using non water-based muds, or partially addressed by treating the mud with chemicals which will reduce the ability of the water in the mud to hydrate the clays in the formation. These muds are known as inhibited muds.

The hydrostatic pressure exerted by the mud colom must be high enough to prevent an influx of formation fluids into the wellbore. However, the pressure in the wellbore must not be too high or it may cause the formation to fracture and this will result in the loss of expensive mud into the formation. The flow of mud into the formation whilst drilling is known as lost circulation. This is because a certain proportion of the mud is not returning to surface but flowing into the formation.


The primary function of drilling fluid is to ensure that the rock cuttings generated by the drilllbit are continuously removed from the wellbore. If these cuttings are not removed from the bit face the drilling efficiency will decrease. It these cuttings are not transported up the annulus between the drillstring and wellbore efficiently the drillstring will become stuck in the wellbore. The mud must be designed such that it can:
1. Carry the cuttings to surface while circulating
2. Suspend the cuttings while not circulating
3. Drop the cuttings out of suspension at surface.

The rheological properties of the mud must be carefully engineered to fulfil these requirements. The carrying capacity of the mud depends on the annular velocity, density and viscosity of the mud. The ability to suspend the cuttings depends on the gelling (thixotropic) properties of the mud. This gel forms when circulation is stopped and the mud is static. The drilled solids are removed from the mud at surface by mechanical devices such as shale shakers, desanders and desilters. It is not economically feasible to remove all the drilled solids before re-circulating the mud. However, if the drilled solids are not removed the mud may require a lot of chemical treatment and dilution to control the rheological properties of the mud.

Drilling fluid or drilling mud is a critical component in the rotary drilling process. Its primary functions are to remove the drilled cuttings from the borehole whilst drilling and to prevent fluids from flowing from the formations being drilled, into the borehole. It has however many other functions and these will be discussed below. Since it is such an integral part of the drilling process, many of the problems encountered during the drilling of a well can be directly, or indirectly, attributed to the drilling fluids and therefore these fluids must be carefully selected and/or designed to fulfil their role in the drilling process.

The cost of the mud can be as high as 10-15% of the total cost of the well. Although this may seem expensive, the consequences of not maintaining good mud properties may result in drilling problems which will take a great deal of time and therefore cost to resolve. In view of the high cost of not maintaining good mud properties an operating company will usually hire a service company to provide a drilling fluid specialist (mud engineer) on the rig to formulate, continuously monitor and, if necessary, treat the mud.

Their are a variety of additives which may be added to cement.. These additives may be delivered to the rigsite as liquid or dry additives. The amount of additive is generally quoted as a percentage of the cement powder used. Since each sack of cement weighs 94 lbs, the amount of additive can be quoted in weight (lbs) rather than volume. This can then be related to the number of sacks of additive. The number of sacks of additive can be calculated from:

Number of sacks of additive = No. sxs Cement x % Additive
Weight of additive = No. sxs of Additive x 94(lb/sk)

The amount of additive is always based on the volume of cement to be used.

The mixwater required to hydrate the cement powder will be prepared and stored in specially cleaned mud tanks. The amount of mixwater required for the operation will depend on the type of cement powder used. The volume of mixwater required for the cement slurry can be calculated from:

Mixwater Vol. = Mixwater per sack x No. sxs

Although cement and other dry chemicals are delivered to the rig site in bulk tanks the amount of dry cement powder is generally quoted in terms of the number of sacks (sxs) of cement required. Each sack of cement is equivalent to 1 cu. ft of cement.

The number of sacks of cement required for the cement operation will depend on the amount of slurry required for the operation (calculated above) and the amount of cement slurry that can be produced from a sack of cement. The amount of cement slurry that can be produced from a sack of cement, known as the yield of the cement, will depend on the type of cement powder (API classification) and the amount of mix water mixed with the cement powder. The latter will also depend on the type of cement and will vary with pressure and temperature. The number of sacks of cement required for the operation can be calculated from the following.

No. of Sacks = Total Volume of Slurry/Yield of Cement