# The Drilling Fluid Function Biology Essay

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The function of drilling fluids is a key note in carrying out a successful drilling operation on any well. Some of the important function includes controlling formation pressure, preventing formation damage, preserved well-bore stability, transporting cuttings to the surface, suspending cuttings, lubricating and cooling drill bit, corrosion control, and facilitate cementing and completion.

## 2.1.1 Controlling formation pressure

Drilling operations are carried out in periods which consist of drilling into the formation (2-12 hours depending on the availability of man power on site), followed by casing and cementing process to secure and strengthen the drill formation in order to prevent collapsing [1]. However, before casing and cementing can be carried out, a gap between the drill string and the formation is form during drilling as shown in the figure 2.1. Formation is defined as 'a mappable layer of rock' [2, p200]. These layers of rocks consist of different solids of varying porosity and permeability in which traces of water, oil or gas can be found [3]. The exposed formation is subjected to formation pressure acting against its wall in which are to be controlled. Failure to control this pressure would result breaking of shale that would lead to formation liquid flowing into the well bore, loss of circulation, and worst case scenario a blowout [3].

## Gap

Figure 2.1: Change in pressure due to hydrostatic pressure

In order to prevent this, drilling fluid is applied during the drilling process to seal of the exposed formation by providing enough fluid force that would exerting against the formation which known as hydrostatic pressure. Hydrostatic pressure is calculated based on the applied mud weight at a given depth [4, p365], as shown in the equation below:

Hydrostatic pressure (psi) = Height (ft) X Density (ppg) X 0.052

Besides the drilling fluids mud weight, its flow properties also help control the formation pressure. Today, with stated of the art drilling equipment such as Schlumberger VPWD Verified Pressure While Drilling Service that provide real time information regarding the dynamic pressure condition down hole [5]. This would help the mud engineer to make needed changes to the mud density in order to maintain the needed dynamic pressure in the well-bore to control the formation pressure.

## 2.1.2 preventing formation damage

Formation damage can occur at any given moment during the overall oil and gas recovery process which includes during drilling as well as during production [6]. That is why it is expressed by Amaefule et al. (1988), as an expensive headache. In most cases, it is irreversible as stated by Porter (1989), therefore the best option is to avoid it at all cost. The most common cause of formation damage during drilling are due invasion of fluid and solid into the formation due to the usage of an unsuitable drilling fluid. As a typical formation is made of rocks that have different porosity and permeability, these characteristics are to be understood before a working mud can be formulated. The most common test carried out is known as return permeability in which is a test to measure the pore size and permeability rate of a studied rock core sample that is obtained from the future drilling site. A permeameter is used for this test to simulate the drilling fluid invasion into the core by subjecting drilling fluid against the core outflow and at the same time, differential pressure is applied at the opposite direction [7]. With the obtained measurement, the pore size and permeability rate of the formation is known in which can help formulated a working drilling fluid by selecting the rite amount of fine solids to prevent solids plugging or even excessive usage of surfactants to prevent wettability reversal and emulsion blockage [8]. Besides that, the formulated drilling fluid should also have the needed hydrostatic pressure, as over pressure would cause the fluid to penetrate through the formation pore, thus damaging the formation.

## 2.1.3 preserved well-bore stability

Well-bore instability is known to be a common problem faced during drilling [9]. It is an undesired condition of a well hole that is unable to maintain its structural integrity during drilling due to either mechanical or chemical effects. There are three common types of well-bore instability as shown in figure 2, which are formation breakdown, borehole enlargement, and squeezing. Drilling fluid plays an important role in preserving the stability of well-bore before casing can be run and cemented to secure the well-bore. The mud forms a mud cake which secures the well bore exposed formation in placed.

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Figure 2.2: Types of well-bore instability problem

The mud weigh should be able to provide the necessary mechanical forces acting on the wellbore. Well swelling as a result of chemical reaction between drilling fluid and formation cause well-bore instability. Inhibitive mud such as OBM and SBM, are used to avoided adsorption of water into the shale. Besides that, OBM and SBM are known to form quality filter cake on formation wall that keep fluid invasion to a minimum [10].

## 2.1.4 Transporting Cutting to the Surface

During drilling, small pieces of rock get cut away by the drill bit teeth which are referred to as drill cuttings. It very important that these drill cuttings be removed from the well-bore by transporting it to the surface. Failure to remove this cutting may lead to problem such as clogging of the well bore bottom, preventing logging tools to reach the bottom, and as well as stuck pipe. Besides that, cutting that remains in the well-bore, prevents the drill bit from cutting the uncut formation as the depth of the drill bit reduces with presents of cutting on the bottom of the well-bore. Drilling fluids that flow out of the drill bit, help transport the formed cuttings to the surface. Rotation of pipe and well-hole angle contributed to making removal of drill cutting more difficult. The efficiency of removal of cutting depends on the annular velocity and the slip velocity. Annular velocity is the rate at which the drilling fluid moves upwards in the annulus. It contributes to the ability of well-hole cleaning. The slip velocity is known as the rate at which the cutting tries to settle through moving fluid. The density, size and shaped of the formed cutting plays a role in increasing the slip velocity. The annular velocity should be higher than the slip velocity in order to increase the removal rate of the drill cuttings. Annular velocity is determined by the cross-sectional are of the annulus and the pump output [3].

## 2.1.4 suspending cuttings

When the drill rig's mud pumps are shut down and circulation is at halt, cuttings that remain in the well-bore must remain in a suspension manner. The supplied drilling fluid must be able suspend the cutting to prevent it from settling to the bottom in which would cause a reduction in mud density, which in worst case scenario may cause a potential blow out [3]. Drilling fluids are known to be fluids that thicken at low or zero shear rates and becomes less viscous at high shear rate which is due to its thixotropic. The relative thixotropic taken a various interval is known as gel strength [11]. The gel strength of the drilling fluid indicates its ability to suspend drill cuttings for a given period of time under static condition.

## 2.1.5 lubricating and cooling drill bit

Drill bit is used as a cutting tool during drilling. During this process, huge amount of heat is generated due to friction contact between drill string and drill bit against the wall. Besides that, as the depth of the formation increased, the temperature increases in which heat takes a toll of the drill bit and drill string. This heat must be removed to prevent any damage to the main drilling components. The drilling fluid that flow out of the drill bit and begins to circulated along the drill string, removes the heat from both components. Besides that, drilling fluid also acts as a lubricating agent during drilling. Torque and drag are generated and varies according to the type of well-bore been drilled. A good mud system reduces the amount of torque and drag the drilling components is subjected too which as a result allows maximum rotational and reduces the wear and tear of the drilling component [12].

## 2.1.6 corrosion control

In 1935th, F.N. Speller identified corrosion as a problem during drilling despite the fact that corrosion problem accord before 1930s [13]. Presents of oxygen (O2), carbon dioxide (CO2), hydrogen sulphide (H2S), and salts are the major contributes to corrosion in the drilling industry [11]. A well mud system that consist of chemical scavengers and corrosion inhibitors help to control corrosion during drilling. The pH of the mud also help to control corrosion which various accordingly as some drill location as some drill location requires a high pH mud system to control corrosion while another may require a low pH mud [13]. Increasing the mud density when it is practical, helps prevent further influx of gases from the formation during drilling [11].

## 2.1.7 facilitate cementing and completion

Casing and cementing are carried out at the end of every drilling period to prevent the well bore from collapsing and seals off the exposed formation. Casings are typically steel pipes. The casing is run through the well followed by pumping of cement through the casing in which will flow out of the casing and into the gapped between the casing and the formation to secure the casing at placed as well as to isolate oil, gas and waters zones within the well-bore [14]. Drilling fluid is pump into the well to clean the hole before casing and cementing are carried out. Figure 2.3 shows the step carried out in casing and cementing. After the casing has been cemented in placed, the next drilling period begins followed by pumping of drilling fluid at the end of the drilling period before running casing and cementing. This procedure is repeated till the desired well depth is reach. As soon as the last casing and cementing works are carried out, a decision is made in regards id the drill well will become a producer oil and gas.

Figure 2.3: Cementing Casing and Drill out.

If so, completions works are carried out by perforating, gravel packing, and installing a production tree. During this process, a special type of drilling mud which referred as completion fluids are pump into the well and remain till completion process are finish. These fluids are used to enhanced cake quality, stabilize the well-bore, prevent blow up, and clean up well-bore [15].

## 2.2 classification of drilling fluid

Drilling fluid or mostly referred as drilling mud, are commonly classified according to their based fluid such as gas, liquid, and oil [16].

## 2.2.1 Gas-based Mud (GBM)

Schlumberger classifies their GBM as pneumatic drilling fluid [17]. GBM are mainly used for drilling zones that exhibits low reservoir-pressure, potential lost in circulation, and in unbalances drilling condition [11]. Besides that, it is also used to penetrated hard-rock drilling sites [16]. GBM is well known for its rate of penetration, ability to increase drill bit life span, and has less impact on the formation. There are four common types of GBM which are dry air, mist, foam, and gasified mud. Dry air mud is known to have a higher rate of penetration among the other GBM. Mist type of GBM are used in formation that produced small amount of water that dry air mud has a limitation with. Mist drilling fluids are introduced through water injecting into airstream. The foam type GBM occurs when water and foaming surfactants are injected into the airstream. This GBM has similar properties as dry air mud. The last type of GBM is gasified mud. This drilling fluid is generated by injecting either air or nitrogen simultaneously with the circulated mud slurry into the drill during. It is primary used for weak formation condition. Despites all the good traits GBM has, it hardly been applied in during drilling as it potential to cause a down hole fire in case dealing with dry air or natural gas, which is why is it hard been used [11].

## 2.2.2 Water-based Mud (WBM)

WBM are drilling fluids in which it's continuous phased is made out of water [11]. It is known that most drilling fluids been used are WBM [18]. The early usages if WBM as a drilling fluid dates back to early Chou Dynasty where the early Chinese exploration rigs as shown in figure 2.4, introduced water to aid in the drilling process and remove produced cuttings [13]. There are various types of WBM been used today which depends on its formulated mud composition based on its water phased, viscosity builders, and rheological control agents [18].

Figure 2.4: Early Chinese drilling rig.

But in general, WBM are either made out of fresh or salt water [19]. Fresh water WBM is commonly used for onshore rigs. However, it is also used in offshore exploration that requires high weight mud. WBM mud system used for offshore rigs, are made out of seawater due to its availability. Traces of dissolved salts found in seawater requires the formulated WBM using seawater to be added with more additives to obtained desired flow properties as well as for better filtered control. WBM are known to have some limitation such as a higher rate in causing corrosion, formation damage, and so on. With this, new generation WBM were introduced by several companies who developed such a WBM that had the same inhibition properties as an OBM drilling fluid. Novel chemistry are applied into this new generation WBM which included sodium silicates, membrane-efficient WBM, and highly inhibiting encapsulating polymers [20].

## 2.2.3 oil-based mud (OBM)

OBM drilling fluids are made out of base oil such as diesel, kerosene, fuel oil, selected crude oil, and mineral oils. The development of OBM drilling fluid was to overcome the limitation faced by WBM. It was believed that, OBM originated when crude oil was used in well completion as its first usage as a drilling fluid is not known. Companies such as Exxon which back in 1935 was known as Humble Oil & Refining Company, was one of the early companies to developed OBM. It was not until 1942, where OBM was introduced as a commercial drilling fluid when George L. Miller formed the Oil Based Drilling Fluids Company in Los Angeles California [com]. The commercial OBM produced at that time, had traces of water which formed due reasons such as neutralization of organic acid which leaded to thickening of OBM. This brought about the development of more effective emulsifiers to prevent such a problem from occurring [com]. OBM are applied in drilling operation that deals with high angle well which requires good lubricating system. Besides that, OBM is used to drill water-sensitive formation, in corrosion sieve sites, and places where requires a mud system that is thermally stable [18]. The major disadvantage of OBM is high toxicity levels.

## 2.2.4 synthetic-based mud (SBM)

Due to increase in environmental restriction on the usages of OBM, a new type of drilling fluid was developed which would have the same technical performances criteria as an OBM but has less impact on the environment. This brought about the development of SBM drilling fluids which kick off in 1985 where major mud companies started research into fully biodegradable base fluid [20]. Vegetable oil and fish oil was the first base oil used in the research development stage to fine the base oil for SBM. However, this base oil did not deliver the required tactical performances. This brought about the introduction of esters which lead to a five year of intensive testing an where the final working SBM mud system was applied in February 1990, in the north sea. Today, the based oil used for SBM includes alpha olefins, internal olefins, and poly-alpha olefins. SBM exhibits good traits in deep-water drilling and deviated hole drilling condition.

## 2.3 Properties of Drilling Fluids

The cost in formulating and producing a working drilling fluid is relatively small. However the success in completion of drilling and its overall cost fully depends on a working drilling fluid. Applying a drilling fluid that is unable to perform under the desired well operating condition would damage the reservoir which would result in

## 2.3.1 density

Drilling fluid density, are in most cases referred to as mud weight. It is commonly expressed in pound per gallon (ppg). The first stage in formulating a working mud begins by determining the desired mud weight to be formulate in which would provide the necessary hydrostatic pressure to control formation pressure. The density of the mud is monitored regularly throughout drilling operations. A mud balances is commonly used to measure mud density as shown in figure 2.5.

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Figure 2.5: Mud balances apparatus

Any changes in mud density, requires immediately weight up to prevent the worst outcome of a blowout. Weight up is carried out by using powdered high density solids or dissolved salts [19]. Besides that, the mud density also determines the efficiency of cutting removal.

## 2.3.2 flow properties

Flow properties of a working mud system, ensures the success in drilling operation. The flow properties are observed in terms of viscosity. Viscosity, relates to the resistances to deformation that is been exhibited by a given fluid. A working mud system flow properties must be able to carry out an efficient well-bore cleaning by applying the needed viscosity and annular flow velocity to transport cuttings to the surface [18]. This is carried out by circulating high viscosity drilling fluids at low flow rates, and circulating low viscosity drilling fluids at high flow rates. Drilling fluid are characterised as shear thinning as its apparent viscosity is known to decreases with respect to increase in the subjected shear rates. The flow properties of a drilling fluid, is also used to determine the gel strength of the working mud system. The gel strength determines the mud ability to suspend drill cuttings when drilling operation is stops. This mud properties, prevents cutting from settling to the bottom of the drill hole. Inorganic and organic additives are used to promote gel strength of a working mud system [18]. Flow properties are commonly studied with the used of mesh funnel or viscometer.

## 2.3.3 Fitration properties

It is common for drilling fluid to flow into the formation as borehole pressure is generally higher that formation pressure. To prevent this, drilling mud generates filtrated when subjected to dynamic and static pressure conditions [18]. This filtrated tend to form a thin layer of mud known as mud cake, which block out the formation pore. The mud system must contained solid particles that its size is slightly smaller than the pore opening in the formation [com]. When drilling in zones that are made out of highly pores formation, large solids of various size and shapes are added into the working mud system to block out the exposed pore in which would reduce the rate of fluid loss [18]. The filtration properties of drilling fluids are commonly affected by the change in temperature. Increase in temperature cause the increases in fluid loss and reduces the muds filtrated viscosity. Besides that, changes in the mud electrochemical equilibrium is shown when temperature increases, which effects the flocculation and aggregation of the drilling fluid. To control fluid loss, additives such as colloidal solids and organic polymers are added to the formulated mud to reduce the loss in filtrated [18]. It is well known that excessive filtrated loss is costly and may lead to various problems during drilling. To prevent this, information from offsets well located near the drill zones are obtained. A formulated mud to meet the obtained data is subjected to lab testing. An API filter press is used to conduct static filtration test, and High Temperature High Pressure (HTHP) filter press is used to conduct dynamic filtration test. Results obtained would determine if the formulated mud exhibits the required filtrated properties for the future drill site.

## 2.3.4 water chemistry

These mud properties are applied for drilling fluid that is made out of water either in its continuous phased or it's dispersed phased. The applied water may either be fresh water, or sea water, or even saturated salt solution. The common pH reading of a drilling fluid falls between the ranges of 6 to 13, which depends on the types of the mud system [18].

## 2.3.6 lubricity

One of an important criteria a drilling fluid should have its application as a lubricating agent for the drilling apparatus. These mud properties are highly needed when drilling directional and crooked well.

## 2.3.7 corrosivity

As mention earlier, corrosion related problem is known to cause drill pipe failures. Drilling mud such as OBM and SBM exhibit corrosion control properties in which its application is widely recommended in drilling areas that are subjected to corrosion related problem. The type of corrosion inhibitive been used is also important as it might affect the overall properties of the mud which is commonly happens in WBM.