Drilling fluids

WELCOME TO THE STUDENTS
7th Semester (Mining)
Bogura Polytechnic Institute, Bogura.
Md. Majedur Rahman
B. Sc (Hon’s), M. Sc in Geology & Mining, RU
Instructor (Tech)
Mining and Mine Survey Technology
Bogura Polytechnic Institute, BOGURA.
Presented By
Prepared by Md. Majedur Rahman, E-mail: majedu1r_ru6871@yahoo.comMay 29, 2020 1

Petroleum Well Design & Completion
Course Code No. 69372
Prepared by Md. Majedur Rahman, E-mail:
majedu1r_ru6871@yahoo.com
May 29, 2020 2

Chapter-03
Understand the drilling fluids
3.1 Define drilling fluids.
3.2 Describe the function of drilling fluids.
3.3 Describe different types of drilling fluids.
3.4 Selection of mud type.
3.5 Describe the solid control in drilling fluid.
3.6 Describe drilling fluid additives.
3.7 Explain mud problems and their remedial measures.
3.8 State mud flow properties.
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• The key to making the rotary drilling system work is the ability to circulate a
fluid continuously down through the drill pipe, out through the bit nozzles
and back to the surface.
• The drilling fluid can be air, foam (a combination of air and liquid) or a
liquid.
• Liquid drilling fluids are commonly called drilling mud.
• All drilling fluids, especially drilling mud, can have a wide range of chemical
and physical properties. These properties are specifically designed for
drilling conditions and the special problems that must be handled in drilling
a well.
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3.1 Define drilling fluids.

• Cooling and lubrication: As the bit drills into the rock formation, the
friction caused by the rotating bit against the rock generate heat. The heat
is dissipated by the circulating drilling fluid. The fluid also lubricates the
bit.
• Cuttings removal: An important function of the drilling fluid is to carry rock
cuttings removed by the bit to the surface. The drilling flows through
treating equipment where the cuttings are removed and the clean fluid is
again pumped down through the drill pipe string.
• Suspend cuttings: There are times when circulation has to be stopped. The
drilling fluid must have that gelling characteristics that will prevent drill
cuttings from settling down at the bit. This may caused the drill pipe to be
stuck.
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3.2 Describe the function of drilling fluids.

• Pressure control: The drilling mud can be the first line of defense against a
blowout or loss of well control caused by formation pressures.
• Data source: The cuttings that the drilling mud brings to the surface can tell
the geologist the type of formation being drilled.
• To wall the hole with impermeable filter cake: This will give a temporary
support to the wall of the borehole from collapsing during drilling.
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Function of Drilling Fluids
• To clean the bottom of the hole, remove the cutting and carry them to the
surface.
• To cool and lubricate the drill bit and string.
• To continuously build a well around the inside of the hole, this prevents the hole
from caving in.
• When HC accumulations are encountered, the well fluid must be heavy to exert
sufficient pressure to prevent the entrance of these into the well bore.
• To hole cuttings and weight material in suspension, when circulation is stopped.
• To support part of the weight of drill pipes and casing.
• To transmit hydraulic horsepower to the bit.
• To act as a medium for electrical well logging.
• To ensure maximum information about the information’s penetrated.
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Composition of drilling fluids
Various requirements are to be met by the quality and composition of the
drilling fluids in actual drilling, like the density of geological conditions and
the presence of a suitable raw material. All these factors led to the different
types of fluids. Main components of drilling fluids are as follows:
• Liquid base: water or oil
• Colloidal particles: Sufficient to provide for a sedimentational stability of
the system at rest due to its transformation into a gel and capable of
plugging up pores and fine fractures in rocks.
• Weighing material: To ensure pre-assigned density of the fluids.
• Chemical reagents: To regulate physic-mechanical and chemical properties
of the system and for protecting against adverse effects of the
environment.
• Miscellaneous: Thinners, lost circulation material, calcium removers,
corrosion inhibitors, deformers, emulsifiers, etc.
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3.3 Describe different types of drilling fluids.
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Basic Classification of Drilling Fluids /Different types of Mud
• Natural Mud’s
• Low pH caustic-quebracho mud
• High pH caustic-quebracho mud
• Phosphate treated muds
• Inhibited Muds
• Lime Muds
• Low lime muds
• Modified lime mud
• Sea-water Muds
• Saturated Salt Water Muds
• Gypsum Muds
• Oil Emulsion Muds
• Potassium Based Muds
• Oil Base Muds
• Low-solid Muds
• Non Dispersive Dextrid Muds
• Balance Activity Muds

Different types of drilling fluids:
1. Water-base mud
This fluid is the mud in which water is the continuous phase. This is the most
common drilling mud used in oil drilling.
2. Oil-based mud
This drilling mud is made up of oil as the continuous phase. Diesel oil is widely used
to provide the oil phase. This type of mud is commonly used in swelling shale
formation. With water-based mud the shale will absorb the water and it swells
that may cause stuck pipe.
3. Air and foam
There are drilling conditions under which a liquid drilling fluid is not eh most
desirable circulating medium. Air or foam is used in drilling some wells when these
special conditions exist.
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4. Synthetic Based Mud (SBM)
This category of drilling mud are quite similar to the OBM, but less harmful in
terms of its toxicity and environmental impact. They are mainly composed of
olefins, esters and sometimes paraffins. In terms of its application, SBM have
a low kinetic viscosity and thus could be use under low pressure conditions
5. Emulsion Drilling Mud (EDM)
These are a group of drilling mud that have emulsion-based phases. It is
composed of two (2) phase; the outer and inner phases respectively. The
outer phase consists of salt water (brine) whereas the inner phase
component consists of oil. In terms of its application and uses, surfactants
are applied to make the two phases miscible due to the opposing emulsion
effect. They are also very cheap and environmentally friendly to apply, with
comparison to OBM, but more expensive when compared to WBM.
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6. Invert Emulsion Mud (IEM)
This category is quite similar to the EDM in terms of its chemical
composition, cost, environmental impacts and applications, but differs
in the phase distribution. Just as the name implies, it is the inverse
composed form of the EDM. It also has two (2) phases, but the outer
phase consists of oil while the inner phase consists of salt water (brine).
In terms of their application, they have a light viscosity and suitable for
high temperature and be easily degraded by micro-organisms.
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3.4 Selection of mud type.
Selection Factors And Properties Of Drilling Fluids
• Factors To Consider While Choosing A Drilling Fluid
The choice of a drilling fluid type or system usually starts with selecting
a drilling fluid (mud) family according to the nature of the rock
formation and considering its financial implications as well as
environmental impacts. This is because drilling fluids may cover for 5%
to 15% of total drilling cost but could lead to a 100% of drilling
problems (Bloys et.al., 1994).
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In choosing a drilling fluid, emphases are based on the following factors;
• Well design
• Formation pressure
• Rock mechanics
• Chemistry of the formation
• Limiting negative impacts on the producing formation
• Environmental issues and regulations
• Logistics
• Cost
It is important to note that the ability to simulate down-hole conditions and
optimize fluid design will always contribute to a reduction in non-productive
time.
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• Properties Of Drilling Fluids And Well Control Effects
To address these considerable factors, a drilling fluid should consist of about five (5)
basic properties, namely; rheology, fluid loss, chemical properties, solid contents
and density. For any type of drilling fluid, all five properties may be influenced with
chemicals and other additives (Bloys et.al., 1994).
• i. Rheology: This is a property of fluid that talks about viscosity. A high viscous
fluid may be able to carry drill cuttings to the surface freely alongside other
weighting agents in the mud.
• ii. Density: Requires enough hydrostatic pressure to avoid the drilled borehole
from caving in, thereby keeping the formation fluid from entering the borehole.
Drill muds with high density than the cuttings density makes cleaning of wellbore
easier and faster.
• iii. Fluid Circulation Loss: A good drilling fluid should be able to have a low-
permeability effect so as to be able to seal the pores between the formation and
wellbore.
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• iv. Solid Content: Solids could be high gravity (HGS) e.g. barite and other
weighting materials or low gravity (LGS) e.g. clays, polymers and bridging
materials. Drilling fluids with high solid contents (i.e. LGS) usually increase plastic
viscosity and gel strength because they have more thicker filter cakes and slow
drilling rates than low solid content fluids (i.e. HGS).
• v. Chemical Properties: This is a major property of drilling fluids that affects
performance and wellbore stability. It monitors salt formations, pH and corrosion
effects of a drilling fluid.
By modifying some of these properties and factors, for example the viscosity and
mud weight, the negative effects resulting from kick during drilling prevents
formation fluid from entering back in the wellbore.
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3.5 Describe the solid control in drilling fluid.
Solids control is a technique used in a drilling rig to separate the solids in the
drilling fluids that are crushed by the drill bits and carried out of the well
surface. Normally, a solid control system contains five stages: the mud tank,
shale shaker, vacuum degasser, desander, desilter, and centrifuge. The shale
shaker is used to separate big solids with diameter above 75μm, the
desander addresses solids from 45-74μm, and the desilter segregates solids
between 15-44μm. Sometimes the desander and desilter are combined as
one high efficiency mud cleaner. When air enters the drilling fluids, a vacuum
degasser is used to separate the air. When there is no air in the mud, the
degasser works as a big agitator. All these stages are mounted on the top of
the mud tank. After separating the solids, the clean mud can be pumped into
the borehole again.
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Recent advances in solids control include the creation of a closed loop system
which allows for increased environmental control and reduction in the
potential for spills of drilling fluids. Several US states have either passed or are
considering the implementation of closed loop systems, particularly for hydro-
fracturing operations.
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3.6 Describe drilling fluid additives.
Clays, polymers, weighting agents, fluidloss-control additives, dispersants or
thinners, inorganic chemicals, lost-circulation materials, and surfactants are
the most common types of additives used in water-based muds. Weighting
Agents.
Water-based drilling fluids consist of a mixture of solids, liquids, and chemicals,
with water being the continuous phase. Solids may be active or inactive. The active
(hydrophilic) solids such as hydratable clays react with the water phase, dissolving
chemicals and making the mud viscous. The inert (hydrophobic) solids such as sand
and shale do not react with the water and chemicals to any significant degree.
Basically, the inert solids, which vary in specific gravity, make it difficult to analyze
and control the solids in the drilling fluid (i.e., inert solids produce undesirable
effects).
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• Weighting Agents. The most important weighting additive in drilling fluids is barium
sulfate (BaSO4). Barite is a dense mineral comprising barium sulfate. The specific gravity
of barite is at least 4.20 g/cm3 to meet API specifications for producing mud densities
from 9 to 19 lbm/gal. However, a variety of materials have been used as weighting agents
for drilling fluids including siderite (3.08 g/cm3), calcium carbonate (2.7–2.8 g/cm3),
hematite (5.05 g/cm3), ilmetite (4.6 g/cm3), and galena (7.5 g/cm3).
• Fluid-Loss-Control Additives. Clays, dispersants, and polymers such as starch are widely
used as fluid-loss control additives. Sodium montmorillonite (bentonite) is the primary
fluid-loss-control additive in most water based drilling fluids. The colloidal-sized sodium-
bentonite particles are very thin and sheet like or plate like with a large surface area, and
they form a compressible filter cake. Inhibitive mud systems inhibit the hydration of
bentonite and greatly diminish its effectiveness. Therefore, bentonite should be
prehydrated in fresh water before being added to these systems. The larger and thicker
particles of sodium montmorillonite do not exhibit the same fluid-loss-control
characteristics.
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• Thinners or Dispersants. Although the original purpose in applying certain
substances called thinners was to reduce flow resistance and gel development
(related to viscosity reduction), the modern use of dispersants or thinners is to
improve fluid-loss control and reduce filter cake thickness. The term dispersant is
frequently used incorrectly to refer to deflocculants. Dispersants are chemical
materials that reduce the tendency of the mud to coagulate into a mass of
particles or “floc cells” (i.e., the thickening of the drilling mud resulting from
edge-to-edge and edge-to-face association of clay platelets). In addition, some
dispersants contribute to fluid-loss control by plugging or bridging tiny openings
in the filter cake. For this reason, some dispersants such as lignosulfonate (a
highly anionic polymer) are more effective than others as fluid-loss reducers
(IMCO 1981).
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• Lost-Circulation Materials. In mud parlance, losses of whole drilling fluid to
subsurface formation are called lost circulation. Circulation in a drilling well can
be lost into highly permeable sandstones, natural or induced formation fractures,
and cavernous zones; such a loss is generally induced by excessive drilling-fluid
pressures. Drilling mud flowing into the formation implies a lack of mud returning
to the surface after being pumped down a well.
• Various Other Additives. There are a plethora of other additives for drilling fluids.
Some are used for pH control—that is, for chemical-reaction control (inhibit or
enhance) and drill-string-corrosion mitigation. There are bactericides used in
starch-laden fl uids (salt muds in particular) to kill bacteria. There are various
contaminate reducers such as sodium acid polyphosphate (SAPP) used while
drilling cement to bind up calcium from the cement cuttings. There are corrosion
inhibitors, especially H2S scavengers. There are defoamers to knock out foaming
and foaming agents to enhance foaming. There are lubricants for torque-and-
drag reduction as well as pipe-freeing agents for when a drill string is stuck.
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3.7 Explain mud problems and their remedial measures.
Many drilling problems are due to conditions or situations that occur after drilling
begins and for which the drilling fluid was not designed. Some of these problems
can be solved by adding materials to the drilling fluid to adjust its properties. Other
cases, it may be necessary to replace the drilling fluid being used with another fluid
system. The most common changes is the mud weight or density. Weighting
material is added when high-pressure formations are expected.
Some of the problems are:
1. Lost circulation
Lost circulation can occur in several types of formations, including high permeable
formations, fractured formations and cavernous zones. Lost circulation materials
can be added to the mud to bridge or deposit a mat where the drilling fluid being
lost to the formation. These materials include cane and wood fibres, cellophane
flakes and even padi husks were used in oil drilling in Sumatra.
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2. Stuck pipe
Stuck pipe can occur after drilling has been halted for a rig breakdown, while
running a directional survey or when conducting other nondrilling operation. The
drill pipe may stick to the wall of the hole due to the formation of filter cake or a
layer of wet mud solids on the wall of the hole in the formation.
3. Heaving or sloughing hole
This occurs when shales enter the well bore after the section has been penetrated
by the bit. To solve this problem, drilling is suspended the hole is conditioned (by
letting the mud in circulation for a period of time)
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3.8 State mud flow properties.
Mud
Density
Viscosity and gel strength
Filtration and wall building
Sand content
Liquid and solid ratio
Mud Filtrate
Determination of pH
Alkalinity and lime content
Chlorides
Hardness
Sulphates
Resistivity
Salinity
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Important Mud properties:

Properties of Drilling Mud (after N.L. Baroid / N.L. Industries, Inc.)
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Property Influences Desirable Limit Control
Density
(Weight)
Drilling rate
Hole stability
Less than about 1.080 kg/m3 (9.0
lb/gal)
(Mud balance)
Dilute with water or remove solids to
decrease
Add barium to increase
Viscosity Cuttings transport
Cuttings settlement
Circulation pressures
34-40 sec/dm3
(32-38 sec/qt)
(Marsh funnel and measuring cup)
Add water, phosphates or lignites to thin
Add bentonite or polymers to thicken
Filtration Wall cake thickness Very thin (Less than 0.2 cm {1/16
in})
Control density and viscosity of mud
polymers
Sand content Wall cake thickness
Abrasion to equipment
Drilling rate
Less than 2% by volume Add water to lower viscosity
Good mud pit design
Use desander
pH
(Acidity or alkalinity)
Mud properties
Filtration control
Hole stability
Corrosion of equipment
8.5 to 9.5
(Neutral is 7.0)
Increase with sodium carbonate
Decrease with sodium bicarbonate
Calcium
content1 (Hard water)
Mud properties Less than 100 ppm calcium Pretreat mixing water with sodium
bicarbonate
1For other salts, dilute salt content with fresh water or use organic polymers in the drilling fluid

Any Questions
May 29, 2020 27

THANKS TO ALL
May 29, 2020 28

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