Drilling Engineering 1

Drilling Fluids
Functions & Types

Dr.Eng. Ibrahim Ali Farea

October 20 , 2018
 Drilling fluids is one of the most important elements of any drilling operation. The

mud has a number of functions which must all be optimized to ensure safety and
minimum hole problems.

Failure of the mud to meet its design functions can prove extremely costly in

terms of materials and time, and can also jeopardize the successful completion of
the well and may even result in major problems such as stuck pipe, kicks or blowouts.

A complete and comprehensive mud plan must be included in the well planning

process. History has proven that an incomplete mud plan will cost the operator many
hours of rig time and may mean the difference between a productive or a
nonproductive well.
 Drilling fluids are designed and formulated to perform three major functions, and other
Minor functions of a drilling fluid include:
1. Subsurface pressure control.
2. Transport the cuttings up the borehole to the surface. Major functions.
3. Support and Stabilize the wellbore.

4. Cooling and lubricating the rotating bit and drill string.

5. Transmitting hydraulic horsepower to the bit.
Minor functions.
6. Facilitating the collection of formation data (logging,…).
7. Partial support of drill string and casing weight.
8. Clean under the bit.

In addition to the essential functions of a drilling fluid, there are other benefits to be
gained from proper selection and control, such as to:
9. Minimize formation damage.
10. Minimize corrosion of the drillstring, casing, and tubing.
11. Suspension of solid particles.
Additional Benefits.
12. Minimize torque, drag, and pipe sticking.
13. Improve drilling rate.
  Subsurface pressure control

To control sub-surface pressures by providing hydrostatic pressure greater than the

formation pressure. This property depends on the mud weight which, in turn, depends
on the type of solids added to the fluid making up the mud and the density of the
continuous phase.

Drilling intervals that have abnormally high formation pressures require that the
mud system be able to provide sufficient pressures to equal or exceed the formation
pressure, the hydrostatic pressure of the mud system achieves this purpose. Insufficient
pressure control can cause hole heaving, kicks, and blowouts.
  Transport cuttings up the borehole to the surface

The drilling fluid should be able to remove cuttings from beneath the drilling bit,
transport them up the annulus, and release the cuttings at the surface using solids-
control equipment without losing other beneficial materials.
The removal of cuttings depends on the viscous properties called: ―Yield Point―

which influences the carrying capacity of the flowing mud.

The flow rate of mud is also critical in cleaning the
hole. In most cases, the rig hydraulics program provides VA – Mud annular velocity

for an annular velocity sufficient to result in a net

Vs – Cutting slip velocity
upward movement of the cuttings. Annular velocity (VA)
is determined by the cross-sectional area of the annulus
Q 24.5Q
and the pump output. VA  
Anncapacity Dh2  ODP2

d p   p   f 
0.667 ρp - Density of particle, ppg
Vs  174.7 ρf - Density of drilling fluid, ppg
 0f .333  e0.333 µe – Effective viscosity of fluid, cp
dp – equivalent diameter of drill cutting, in

The fluid velocity in the annulus (Annular velocity VA) must exceed the downward
falling rate, or slip velocity (Vs) of the cuttings.
  Support and Stabilize the wellbore

The bit removes lateral support of the drilled wellbore and is immediately replaced
by the drilling fluid–hydrostatic pressure until the casing is set with cement. The stability
of uncased sections of the borehole is achieved by a thin, low-permeability filter cake
formed by the mud on the walls of the hole. Also, the cake seals pores and other openings
in formations caused by the bit, thereby minimizing liquid loss into permeable formations.

Fluid-Loss Control help for minimizing the swelling stresses caused by the

reaction of the mud with the shale formation. This reaction can cause hole erosion
or caving resulting in an instable wellbore. Minimization of wellbore instability is provided
by the ― Inhibition‖ character of the drilling mud.
 Cooling and Lubricating the Rotating Bit and Drillstring
The Friction at the bit, and between the drillstring and wellbore, generates a
considerable amount of heat. The circulating drilling fluid transports the heat away from
these frictional sites by absorbing it into the liquid phase of the fluid and carrying it to the
surface.

 Partial support of drill string and casing weights

With average well depths increasing, the weight supported by the surface wellhead

equipment is becoming an increasingly crucial factor in drilling. Both drillpipe and casing
are buoyed by a force equal to the weight of the drilling fluid that they displace.
When the drilling fluid density is increased, the total weight supported by the surface
equipment is reduced considerably.

MW
BF  1  Where:
65.5 BF = Mud buoyancy factor, dimensionless
MW = mud weight, Ib/gal
65.5 = (Steel density) or weight of a gallon of steel, Ib/gal.
 Transmitting hydraulic horsepower to the bit.

The hydraulic force is transmitted to the rotating bit when the fluid is ejected through
the bit nozzles at a very high velocity. This force moves the rock fragments or cuttings
away from the drilled formation beneath the bit.

In directional-drilling operations, the hydraulic force powers the downhole hydraulic

motor and turns electric-power generators (turbines) for Measurement-While Drilling
(MWD) and Logging-While Drilling (LWD) drll-string equipment.

Hydraulics programs are based on sizing the bit nozzles to maximize the hydraulic
horsepower or impact force imparted to the bottom of the well.

 Minimizing corrosion of the drill string, casing.

When the well is being drilled in formation containing toxic gases such as hydrogen

sulfide (H2S). These gases not only pose healthy and safety problem to personnel but also
present dangers to metal components from hydrogen embroilment and stress cracking.

The mud system can use additives such as scavengers to remove these
contaminations. In addition, oil muds will minimize corrosion problem.
  Clean under the bit

The removal of cuttings from below the bit is one of the most important functions of a
drilling fluid. Cuttings removal is controlled by factors such as the chip hold-down effect
of the mud, cross flow of the fluid, density & velocity of the fluid, and density & size of the
cuttings.

The chip hold-down effect phenomenon occurs

when the bit breaks a chip from the formation. This chip will
resist removal and movement from below the bit due to the
difference in the hydrostatic pressure of the mud and the
formation pressure. In order to remove this chip, fluids must
penetrate beneath the chip.

This feature has been accomplished successfully

with mud that exhibit a high "spurt loss, initial filtration" by
helping equalize pressures above and below the chip.

Chip removal from below the bit

 Assist in the Gathering of Subsurface Geological Data and Formation Evaluation
The gathering and interpretation of surface geological data from drilled cuttings,
cores and electrical logs is used to determine the commercial value of the zones
penetrated. Invasion of these zones by the fluid or its filtrate, may mask or interfere with
the interpretation of the data retrieved and/or prevent full commercial recovery of
hydrocarbon.

The drilling fluid has an impact on the electrical and acoustical properties of a rock.
Because these properties are what logging tools measure, it is imperative that the
correct selection of wireline logging tool or logging-while-drilling (LWD) tool for a given
drilling fluid be made.

Or, lacking that, then the correct drilling fluid must be used for a given logging tool.

In addition, the drilling fluid should facilitate retrieval of information by means of

cuttings analysis.
  Minimizing torque, drag, and pipe sticking
Excessive torque and drag are problems commonly encountered in drilling
operations that can be addressed by selecting the proper mud system and additives.
Torque is the force required to rotate the drillstring. Excess torque can be cause
drillstring twistoff.

Drag is the incremental force above the string weight required to move the pipe
vertically. High drag force can cause pipe parting.

The mud system can reduce torque and drag problems. If the problems occur as a
result of formation hydration and swelling, certain chemicals or mud type will inhibit
the formation. As a minimum effect, lubricants can be used to reduce the friction
coefficient along the walls of the wellbore.

The laying down of a thin wall of ―Filter cake" on the wellbore aids in reducing
torque and drag. Indications of poor lubrication are high torque and drag, abnormal
wear, and heat checking of drillstring components.

The mud should be tailored so that it forms a thin, tough and non-sticky filter cake,
to prevent pipe sticking.
 Preventing formation damage
Any reduction in a producing formation’s natural porosity or permeability is considered
to be formation damage. If a large volume of drilling-fluid filtrate invades a formation, it
may damage the formation and hinder hydrocarbon production.
There are several factors to consider when
selecting a drilling fluid:
• Fluid compatibility with the producing reservoir.
• Presence of hydratable or swelling formation clays.
• The possible reduction of permeability by invasion of
nonacid soluble materials into the formation.
 Improve drilling rate
The drilling rate is affected by various properties of the mud system. High-viscosity
muds reduce the cross flow velocity beneath the bit, which inhibits cuttings removal.
Lower water losses and high solids content retard equalization of pressure around
the drilled chip, thereby requiring regrinding prior to removal.
The appropriate mud selection to optimize drill rates can reduce the drilling time.
However, caution must be exercised so other problems do not occur ( formation damage,
hole instability, or stuck pipe).
  Suspension of solid particles
When the rig's mud pumps are shut down and circulation is halted (during
connections, trips or downtime), cuttings that have not been removed from the hole must
be held in suspension. Otherwise, they will fall to the bottom (or, in highly deviated wells,
to the low side) of the hole.
The rate of fall of a particle through a column of drilling fluid depends on the
density of the particle and the fluid, the size of the particle, the viscosity of the fluid,
and the thixotropic (gel-strength) properties of the fluid.
The controlled gelling of the fluid prevents the solid particles from settling, or at
least reduces their rate of fall.
High gel strengths also require higher pump pressure to break circulation. In
some cases, it may be necessary to circulate for several hours before a trip in order to
clean the hole of cuttings and to prevent fill in the bottom of the hole from occurring during
a round trip.
 Physicochemical Functions
The drilling-fluid system should remain stable when exposed to contaminants and
hostile downhole conditions. Among the common natural contaminants are reactive drill
solids, corrosive acid gases (H2S, CO2), saltwater flows, cement, anhydrates, and gypsum.
 A drilling fluid can be classified by the nature of its continuous fluid phase. There are
three types of drilling fluids:

Drilling Fluids

Oil-Based Water- Based Pneumatic Fluids

mud mud
Dry Gas
Full Oil mud Non-Inhibitive
Mist
Emulsion or Inhibitive
Mineral mud
Foam (mostly Gas)
Polymer
Gasified Mud
Non-Petroleum Hydrocarbon (mostly water)
(Pseudo mud)
 The majority of wells are drilled with water-based drilling fluids. Water is the continuous
phase, but it may contain oil (but not necessarily) as the discontinuous phase.

The base fluid may be , , or ,

whichever is and or is .

Water-based drilling fluids range from to to the

They are divided into three major sub-classifications:

 Non-inhibitive drilling fluid.

 Inhibitive drilling fluid.
 Polymer
 Non-Inhibitive Fluids

The term non-inhibitive refers to the lack or absence of specific ions (sodium,

calcium, and potassium) that are present in inhibitive fluids. Non-Inhibitive fluid

systems do not use chemical dispersants (thinners) or inhibitive ions.

Non-Inhibitive fluid generally comprised of native clays or commercial bentonite with

some caustic soda or lime. Means that the clay particles are free to find their own
dispersed equilibrium in the water phase. Non-inhibitive fluids are often with low solids
concentrations and relative low-density weights.

Non-inhibitive fluids are generally used as spud muds. Native solids are allowed to
disperse into the system until rheological properties can no longer be controlled by water
dilution. Proper solids control equipment, alkalinities, and bentonite concentrations must
be monitored closely for a low-solids non-dispersed mud to function effectively.
Four common mud systems that can be classified as Non-inhibited mud are:

 Clear Water / Spud mud.  Bentonite-Water Muds.

 Native Muds.  Lignite-Lignosulfonate (Deflocculated) Muds.
 Inhibitive Fluids
2. Inhibitive Fluids – Inhibitive drilling fluids are designed to reduce chemical

reactions between the drilling fluid and the formation. For this reason, inhibitive fluids are
used for drilling hydratable-clay zones (Hydration reduces the structural stability of the borehole, allowing it
to fall, or slough, into the wellbore) and sands containing hydratable clays. Those which
appreciably retard clay swelling and, achieve inhibition through the presence of cations;
typically, Sodium (Na+), Calcium (Ca++) and Potassium (K+).
Generally, K+ or Ca++, or a combination of the two, provide the greatest inhibition to
clay dispersion. Suppresses the breakdown of the clays by charge association (reduces the
amount of water attached to the clay structure) and or encapsulation (retarding the rate at which

formation clays hydrate).

The common mud systems that can be classified as inhibited mud are:

1. Calcium-Based Muds: 2. Salt-Based Muds: 3. Potassium-Based Muds:

 Lime Muds  Saturated Salt Muds o KOH-Lignite Systems
 Gyp Muds  Saltwater Muds o KOH-Lime Muds
 Brackish-Water Muds o KCl-Polymer (KCl-PHPA) Muds
o KCl - Cationic Polymer Muds
 Polymer Fluids
Those which rely on macromolecules, either with or without clay interactions to provide
mud properties, and are very diversified in their application. These fluids can be inhibitive
or non-inhibitive depending upon whether an inhibitive cation is used. Polymers can be
used to viscosity fluids, control filtration properties, or encapsulate solids. The thermal
stability of polymer systems can range upwards to 400°F.
In spite of their diversity, polymer fluids have limitations: Solids are a major
threat to successfully running a cost-effective polymer mud system.

Polymers function in several ways. Some polymers actually hydrate and swell in
much the same manner as conventional clay materials. By doing this they thicken the
water phase, making the escape of this water into the formation or into the clay structure
more difficult, thereby preventing swelling. Large high molecular-weight polymers will
bond onto clay surfaces and literally surround and isolate the clay/shale particle. This is
referred to as encapsulation.
The common mud systems that can be classified as Polymer Fluids are:
 Low-Solids PHPA Muds.  THERMA-DRIL.  PYRO-DRIL.
 A primary use of oil-based fluids is to drill troublesome shale and to improve hole
stability. Oil-based fluids use crude or refined oils as the continuous phase. These mud
may have water emulsified in the oil. Two types of oil-based fluids are commonly used:

 An oil mud has less than 5% water.

 Diesel and mineral oil OBFs—also called ―invert emulsions‖ has a water concentration
greater than 5%.

The OBM are generally used for specific purposes, such as:
• Useful in drilling high angle/horizontal wells because of their superior lubricating
properties and low friction values between the steel and formation which result in
reduced torque and drag.
• Ability to prevent hydration of clays.
• Minimizing formation damage, and native-state coring.
• Resistant to contaminants such as anhydrite, salt, and CO2 and H2S acid gases.
 Cost is a major concern when selecting oil-based muds. Initially, the cost per barrel of
an oil-based mud is very high compared to a conventional water-based mud system.
However, because oil muds can be reconditioned and reused, the costs on a multi-well
program may be comparable to using water-based fluids.

Today, with increasing environmental concerns, the use of oil-based muds is either
prohibited or severely restricted in many areas. In some areas, drilling with oil-based fluids
requires mud and cuttings to be contained and hauled to an approved disposal site. The
costs of containment, hauling, and disposal can greatly increase the cost of using oil-
based fluids.

SBFs. Synthetic-based drilling fluids were developed to provide the highly regarded
drilling-performance characteristics of conventional OBFs while significantly reducing the
toxicity of the base fluid.
 Pneumatic (air/gas based) fluids are used for drilling depleted zones or areas where
abnormally low formation pressures may be encountered. An advantage of pneumatic
fluids over liquid mud systems can be seen in increased penetration rates. Cuttings are
literally blown off the cutting ahead of the bit as a result of the considerable pressure
differential. The high pressure differential also allows formation fluids from permeable
zones to flow into the wellbore.
Air/gas based fluids are ineffective in areas (1) where large volumes of formation
fluids are encountered (A large influx of formation fluids requires converting the
pneumatic fluid to a liquid-based system). As a result, the chances of losing circulation or
damaging a productive zone are greatly increased. Another consideration when selecting
pneumatic fluids is (2) well depth. They are not recommended for wells below about
10,000 ft because the volume of air required to lift cuttings from the bottom of the hole can
become greater than the surface equipment can deliver.

Both air and gas drilling are subject to downhole ignition and explosion risks. Sometimes,
nitrogen—either from cryogenic sources or generated using membrane systems— is
substituted for the pneumatic fluid.