Drilling Fluid Basics

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.

Functions and Properties of Drilling Fluid Or Drilling Mud

The primary functions of a drilling fluid or drilling mud are:
• Remove cuttings from the Wellbore
• Prevent Formation Fluids Flowing into the Wellbore
• Maintain Wellbore Stability
• Cool and Lubricate the Bit
• Transmit Hydraulic Horsepower to Bit
The drilling fluid must be selected and or designed so that the physical and chemical properties of the fluid allow these functions to be fulfilled. However, when selecting the fluid, consideration must also be given to:
• The environmental impact of using the fluid
• The cost of the fluid
• The impact of the fluid on production from the pay zone
The main functions of drilling fluid and the properties which are associated with fulfilling these functions are summarised in Table below :

Function and Physical Properties of Drilling Fluid

Table Function and Physical Properties of Drilling Fluid

Drilling Fluid Or Drilling Mud Function Remove cuttings from the Wellbore

The primary function of drilling fluid is to ensure that the rock cuttings generated by the drill bit 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 drill string and wellbore efficiently the drill string will become stuck in the well bore. The mud must be designed such that it can:
• Carry the cuttings to surface while circulating
• Suspend the cuttings while not circulating
• 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. For a thorough treatment of the rheology of drilling fluid refer to the chapter on Drilling Hydraulics.

Drilling Fluid Or Drilling Mud Function Prevent Formation Fluids Flowing into the Wellbore

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 well bore 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 pressure in the wellbore will be equal to:
P = 0.052 x MW x TVD
P = hydrostatic pressure (psi)
MW = mud density of the mud or mud weight (ppg)
TVD = true vertical depth of point of interest = vertical height of mud column
The density of the mud may be expressed in either of the following units: To obtain the following Units of density multiply the Units in the first
colom by:
S.G.                      psi/ft                   ppg
S.G.                      1.0                       0.433                  8.33
psi/ft                   2.31                    1.0                        19.23
ppg                       0.12                   0.052                   1.0

Table Conversion of Commonly used Units of Density Of Drilling Fluid or Drilling Mud

A mud weight of 12 ppg is equivalent to a mudweight of 12 x 0.052 = 0.624 psi/ft
A mud weight of 1.4 S.G. is equivalent to a mudweight of 1.4 x 0.433 = 0.606 psi/ft
The mud weight must be selected so that it exceeds the pore pressures but does not exceed the fracture pressures of the formations being penetrated. Barite, and in some cases Haemitite, is added to viscosified mud as a weighting material. These minerals are used because of their high density:
Mineral                Density (S.G.)
Silica (Sand)       2.5
Ca CO3                  2.5
Barite                    4.2
Haemitite            5.6
The relatively high density of Barite and Haemitite means that a much lower volume of these minerals needs to be added to the mud to increase the overall density of the mud. This will mean that the impact of this weighting material on the rheological properties of the mud will be minimised. When drilling through permeable formations (e.g. sand) the mud will seep into the formation. This is not the same as the large losses of fluid which occurs in fractured formations, discussed above. As the fluid seeps into the formation a filter cake will be deposited on the wall of the borehole. Some fluid will however continue to filter through the filter cake into the formation. The mud and the filtrate can damage the productive formations in a number of ways. The loss of mud can result in the deposition of solid particles or hydration of clays in the pore space. The loss of filtrate can also result in the hydration of clays. This will result in a reduction in the permeability of the formation. In addition to damaging the productivity of the formations the filter cake can become so thick, it may cause stuck pipe. The ideal filter cake is therefore thin and impermeable.

Drilling Fluid Or Drilling Mud Function to Maintain Well bore Stability

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:
• the pressure differential between the bottom hole pressure in the borehole and the pore pressures in the shales and/or,
• 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 mud weight. 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.

Drilling Fluid Or Drilling Mud Function to Cool and Lubricate the Bit

The rock cutting process will, in particular with PDC bits, generate a great deal of heat at the bit. Unless the bit is cooled, it will overheat and quickly wear out. The circulation of the drilling fluid will cool the bit down and help lubricate the
cutting process.

Drilling FluidOr Drilling Mud Function to Transmit Hydraulic Horsepower to Bit

As fluid is circulated through the drill string, 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 the 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. This optimisation process is discussed at length in the chapter on Drilling Hydraulics. It is possible that in order to meet all of these requirements, and drill the well as efficiently as possible, more than one type of mud is used (e.g. water-based mud may be used down to the 13 3/8″ casing shoe, and then replaced by an oil-based mud to drill the producing formation). Some mud properties are difficult to predict in advance, so the mud programme has to be flexible to allow alterations and adjustments to be made as the hole is being drilled, (e.g. unexpected hole problems may cause the pH to be increased, or the viscosity to be reduced, at a certain point).

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