Section_01 FLUIDS OVERVIEW.ppt

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PIONEERS IN TECHNOLOGY TRANSFER
Drilling Fluids Technology

Haward Technology Middle East 2
Section 1
Section 1
Drilling Fluid overview

Section 1
Drilling Fluid Overview
 Drilling fluids are generally the blood of all drilling
operation and the petroleum industry especially has
continued to make increasing use of these fluids, the
cost of which can account for over 20% of total drilling
cost.
 To minimize the cost as well as improve performance
and safety, other generic types of these fluids are
continuously being developed mainly to meet the
increasing challenges of:
• Stiff environmental regulations.
• Increasing use of advanced wells (horizontal wells).
• Deeper well drilling / completion especially in high
pressure high temperature (HP-HT) environment

Section 1
Drilling Fluid Cycle
 Well schematic
Drill bit
Drill color
Drill pipe
Casing
Open
hole
Pump the
fluid down
cutting

Section 1
A- Objective of drilling fluids
1. Control subsurface pressure.
2. Transport drilled cutting to surface.
3. Support and stabilize wellbore.
4. Support part of tubular weight.
5. Cool and lubricate bit and drill string
6. Transmit horse power to bit.
7. Provide medium for wireline logging.
8. Assist in formation evaluation

Section 1
9 Use to operate most new innovative down hole
drilling equipment( DHM. Turbines, MWD, LWD,
Rotary steerable drilling)

Section 1
Additional Benefits
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:
• Minimize Formation Damage
• Reduce Corrosion
• Minimize Lost Circulation
• Reduce Stuck Pipe
• Reduce Pressure Losses
• Improve Penetration Rates
• Reduce Environmental Impact
• Improve Safety

Section 1
 Minimize Formation Damage
A producing formation can be damaged by a poor
drilling fluid. Damage mechanisms Include formation
fines migration, solids invasion, and wettability
alterations. Identification of Potential damage
mechanisms and careful selection of a drilling fluid can
minimize damage.
Additional Benefits

Section 1
 Reduce Corrosion
Corrosion control can reduce drill string failure through
removal or neutralization of contaminating substances.
Specific corrosion control products may be added to a
drilling fluid; or the drilling fluid itself may be selected
on the basis of its inherent corrosion protection (see
Figure ).
Additional Benefits

Section 1
Electrochemical Corrosion Cell
(Development in a Fatigue Stress Crack)

Section 1
 Minimize Lost Circulation
Extensive loss of whole mud to a cavernous, vugular,
fissured, or coarsely permeable formation is expensive and
may lead to a blowout, stuck pipe, or formation damage.
Selection of a low density drilling fluid and/or addition of
sized bridging agents can reduce lost circulation
(see Figure ).
Electrochemical Corrosion Cell
(Development in a Fatigue Stress Crack)

Section 1
Types of Lost Circulation Zones
Found in Soft and Hard Rock Formations

Section 1
 Reduce Stuck Pipe
Pipe sticking can be caused by several factors:
• Poor Cuttings Removal
• Hole Sloughing
• Lost Circulation
• Differential Pressure Sticking
• Keyseating
• Two common types of pipe sticking are illustrated in
Next Figures .
Types of Lost Circulation Zones
Found in Soft and Hard Rock Formations

Section 1
Differential Pressure Sticking
LOW PRESSURE
FORMATION
STICKING
FORCE
WALL CAKE

Section 1
Keyseating
Dog-Leg Resulting in the Formation
of a Keyseat

Section 1
 Reduce Pressure Losses
Surface equipment pressure demands can be reduced
by designing a fluid to minimize pressure losses. The
reduction in pressure losses also permits greater
hydraulic efficiency at the bit and a lower equivalent
circulating density (ECD) (see Figure ).
Differential Pressure Sticking

Section 1
Pressure Losses in a Circulating Mud
System

Section 1
 Improve Penetration Rates
Proper fluid selection and control can improve the rate of
penetration (ROP). Benefits of improved penetration rates
are reduced drilling time and fewer hole problems because
of shorter open-hole exposure time. Generally, improved
penetration rates result in reduced costs. Operations such as
cementing, completion, and logging must be factored in to
determine true cost effectiveness of improved penetration
rates.
System

Section 1
 Reduce Environmental Impact
Fluid selection and engineering can reduce the potential
environmental impact of a drilling fluid. In the event of a
spill, reclamation and disposal costs, as well as pollution
associated problems are greatly reduced by proper fluid
selection and control.
System

Section 1
 Improve Safety
A drilling fluid should be engineered for safety. It should have
sufficient density to control the flow of formation fluids and
when circumstances merit, be able to tolerate toxic
contaminants such as hydrogen sulfide(H2S)
System

Section 1
 Characteristics of a Drilling Fluid
• Lubricity
• Velocity
• Viscosity
• Density
• Gel Strength
• Filtrate Control
• No chemical reaction
System

Section 1
Drilling Fluid Composition
The generic composition of mud is as follows:
 A continuous phase that can be either water or oil.
 A dispersed phase, which can be basically clay
(Bentonite) or other solids.
 Chemical additives to control fluid properties such as
weighting materials (barite), viscosity and loss control
additives.
 Drilling muds are expected to have physical and
chemical properties that enable them to be used under
a wide variety of well conditions.

Section 1
Principal Components of Drilling Fluids
Drilling fluid can be classified on the basis of principal
component, these component are:
• Water.
• Oil
• Gas

Section 1
In most of the case two and sometimes all three of those
fluids are present at the same time. When the principal
component is a liquid (water or oil) the term mud is
applied to the suspension of solids in the liquid
Water muds.
Oil muds.
Principal Components of Drilling Fluids

Section 1
Water Base Mud

Section 1
 Water as a drilling fluid ( Water Base Mud)
Water is the principle component of this type of
drilling fluid. With several dissolved polymers in
colloidal solution and various insoluble substance such
as (barite, clay, and cutting) in suspension.
Water Base Mud

Section 1
Water Phase
1. Fresh water (little or no salt contain).
2. Hard water, contain various salt of calcium,
magnesium, etc.
3. Sea or brackish water (contain high precent of salt.
4. Saturated salt water, water contain approximately >
260,000ppm sodium chloride.
Water Base Mud

Section 1
Solids phase
 Active solids.
 Inert solids.
Miscellaneous chemicals:-
a. Treating chemical
b. Filtration control agent.
Water Base Mud

Section 1
 Active solids phase
- Bentonite sodium montmnoillonite( most common
used in drilling operation.
- Sub Bentonite (calcium montmnoillonite).
- Native solids (drill cutting), contain hydratable
shale or non hydratable such as sand or dolomite.
- Salt water clay (attapullgite).
Water Base Mud

Section 1
 Inert solids
- Barite (as weight agent)
- Calcium carbonate (caco3)
Water Base Mud

Section 1
Water Base Mud
The presence of two liquids together results in an
emulsion.
• When oil is emulsified in water the term oil emulsion
mud is used.
• When water is emulsified in oil the term invert
emulsion is used to describe the nature of the fluid

Section 1
 Inert solids
- Barite (as weight agent)
- Calcium carbonate (caco3)
Water Base Mud

Section 1
Oil Base Mud (OBM)
 Oil base muds have oil as continuous liquid. The oil
most often selected is “diesel oil” although some “crude
oil” are acceptable. As water is always present, oil
should have an emulsifying agent. When water is added
purposely the oil mud is called invert emulsion mud.
Various thickening and suspending agents are added as
well as barite.

Section 1
Gas Drilling Fluid
1. Dry air
2. Mist (in which droplets of water or mud are carried
in air stream)
3. Foam (in which air bubbles are surrounded by a film
of water containing a foam stabilizing substance, air
is the most common gas drilling fluid.

Section 1
Drilling Fluid Selection
 Selection of the best fluid to meet anticipated
conditions will minimize well cost and reduce the risk
of potential problems such as stuck pipe, loss of
circulation and kicks. Consideration must also be given
to obtaining adequate formation evaluation and
maximum productivity (Figure 2.1).

Section 1
Drilling Fluid Selection
Make up
water
Geology
Contamination
Hole
Problems
Application
Drilling
equipment
Drilling
Data
Production

Section 1
Types of Drilling Fluid
 There are several types of drilling fluids are currently
used world - wide. The selection of either type is
greatly depending up on the characteristics of the
prospect well.

Section 1
Types of Drilling Fluid
 Drilling fluids are commonly classified into three main
groups:
• Water base mud.
• Oil base mud.
• Gaseous drilling fluids.
Drilling fluids commonly used in the industry are
either, water base mud (WBM) or oil base mud (OBM).

Section 1
OBM WBM Pneumatic
Invert
Non-
inhibitive
Inhibitive
Lightly treated Native Ionic inhibition Incapsulation
Organic Inorganic Ca++ K+
Na++ NH4+
True Air Foam Gas

Section 1
Water Base Mud
 Water base muds are the most commonly used drilling
fluids. They are suitable for most applications, with
the exception of those carried out at high pressure and
temperature and where formations are highly sensitive
to water based muds.
 The term water base mud refers to any fluid having
water as the liquid continuous phase and in which
certain materials are held in suspension and other
material dissolved.

Section 1
Water base mud consist of four components:
1. Liquid water (which is continuous phase and is used to
provide initial viscosity)
2. Reactive fractions to provide further viscosity and
yield point
3. Inert fractions to provide required mud weight
4. Chemical additives to control mud properties.
Water Base Mud

Section 1
 Components (2) & (3) represent the solid fraction of
mud; the reactive fractions of mud are always low
gravity solids, while the inert fractions can be low or
high gravity solids.
 Clays (or low gravity reactive solids) are added to
water to provide the viscosity and yield point
properties necessary to lift the drill cuttings or to keep
them in suspension.
Water Base Mud

Section 1
There are three main types of clay:
1. Sodium montmorillonite (Wyoming bentonite).
2. Kaolinites.
3. Illites.
Water Base Mud

Section 1
 The most important and most commonly used clay is
sodium Montmorrillonite, because of its superior ability
to swell uniformly in fresh water upon shear
application resulting in a more homogenous clay-water
mixture.
Water Base Mud

Section 1
Claytype
Degree of swelling and
plasticity
Montmorillonite
High swelling.
High plasticity
Illites.
Intermediate swelling.
Intermediate plasticity
Kaolinites.
Low swelling.
Low plasticity
Water Base Mud

Section 1
Different type of water may be used as the continuous
phase in water base mud.
The selection of the type used is controlled by the
following factor:
 Availability:
Availability of water depends on location; fresh water,
which may be abundant in one area, may not available
in others.
Water Base Mud

Section 1
 Type of geologic formation
Continued use of fresh water may result in formation
damage and severe hole enlargement problems. Fresh
water filtrate causes in-situ clay particles in the
productive zones to swell and possibly to migrate. This
lead to plugging of the pore throats causing significant
permanent reduction in permeability.
Water Base Mud

Section 1
The Common Type of Water Base Mud
used in Drilling
1. Spud mud
Spud mud are fluids used to initiate drilling operation.
These fluids have maximum hole cleaning
characteristics and should be capable of being built
quickly. They are often required to support
unconsolidated formations.

Section 1
2. Low solids polymer
• This type system uses various materials to extend
the yield of the clays resulting in a significantly
lower total solids content.
• This type system uses polymers to reduce the
concentration of clay to improve the rate of
penetration, improve the bit life.
used in Drilling

Section 1
3. Lignosulfonate Muds
This is the most widely used inhibitive water based
mud and was specifically designed for the following
main functions:
• Rheological stability,
• Excellent shale inhibition
• Tolerance to contaminants, such as gypsum, salt,
cements, and drilled solids
used in Drilling

Section 1
4. Lime mud & gypsum mud
Calcium treated mud are often used in areas where
shale hydration and swelling results in significant bore
hole instability (i.e sloughin and heaving) increased
levels of soluble calcium are maintained in these
fluids to provide an inhibitive to minimize shale
swelling.
used in Drilling

Section 1
5. Polymer mud
The basic component of polymer base drilling fluids is
a high molecular weight, water soluble viscosifying
polymer.
Advantage:
They provide low solids fluid. More exhibit shear
thinning low properties.
Disadvantage:
Temperature limitations
used in Drilling

Section 1
6. Potassium Chloride / Polymer Muds (kcl)
KCL polymer mud is suitable for drilling shale sections
due to its superior sloughing - inhibiting properties
resulting from the use of KCL and the inhibiting
polymer.
Inhibition by KCL is attributed to the replacement of
the sodium ions in shales by potassium ions, which are
more tightly held.
The advantages of this mud include:
• High shear thinning behavior facilitating solids
removal through the shale shaker Improved
borehole stability
used in Drilling

Section 1
7. Salt saturated mud system
Saltwater muds are those muds having salt (NaCl)
concentrations above 10,000 ppm or 1% salt. The salt
concentration can vary from 10,000 ppm up to
315,000 ppm. The salt concentration, present in any
drilling fluid, must come from the following:
Drilling salt string or massive salt.
• Salt water flows.
• Salt added purposely to the system.
• Salt from the make-up or treating water.
used in Drilling

Section 1
Oil Based Mud
 These are emulsion muds with oil as the continuous
phase and water as the dispersed phase in the form of
small, homogonous in size and uniformly dispersed
droplets. To emulsify the water in the oil, there must
sufficient chemical emulsifier to completely form a
film around each water droplet. If there is not
sufficient emulsifier, the emulsion will be unstable. In
term of stability, the smaller the droplets, the more
stable the emulsion. Large droplets will coalesce more
easily than smaller droplets.

Section 1
 The water droplets help support weight materials and
reduction of fluid loss in invert muds. In addition, the
droplet size contributes to the viscosity and gel
strength.
 When oil (continuous phase) is added, the emulsion
may have either positive or negative effects depending
upon the manner in which they become wetted.
Oil Based Mud

Section 1
Oil-base muds have economic advantages when used in
the following applications:
1. To drill troublesome shales.
2. To drill deep high temperature holes.
3. To drill and core pay zones.
4. To drill anhydrite and potash zones etc.
5. As a directional drilling fluid.
Oil Based Mud

Section 1
6. As a slim hole drilling fluid.
7. To drill hydrogen sulphide and carbon dioxide bearing
formations.
8. To free stuck pipe.
9. For corrosion control.
Oil Based Mud

Section 1
Oil Based Mud
The oil phase in the drilling mud, however, present some
disadvantages namely:
 Pollution control problems.
 Gas solubility in diesel makes it more difficult to
detect gas kicks.
 Lack of reliable electrical log information.
 Initial make-up cost.

Section 1
The main component of the OBM is called “base oil” which
may be:
1. Crude Oil
This was the first to be used but is seldom used now
because of environmental restriction
Oil Based Mud

Section 1
2. Diesel Oil
Less expensive and still used in some cases,
Particularly when regulations require oil mud cuttings
to be processed at a disposal or treatment site.
Oil Based Mud

Section 1
Oil Based Mud
3. Low aromatic Mineral Oil
In early 1980s, efforts were made to reduce the
environmental impact of OBM by substituting these oils
for diesel in offshore operations.

Section 1
4. Synthetic Oils
Synthetic-base muds were developed as
environmentally friendly alternative to conventional
petroleum-derived oil-base muds.
Oil Based Mud

Section 1
Mud Characteristics
A–Velocity:
Rate at which mud circulates through the hole,
average annular velocity ranges between 100 – 150 ft /
min . velocity is dependent on pump capacity , pump
speed , borehole size and drill pipe size.

Section 1
 Fluid velocity inside the pipe:
Vp = 0.408*Q
D2
Vp = fluid velocity in the pipe, ft/sec
Q = Volumetric flow rate, gal/min
D = inside diameter of pipe
Mud Characteristics

Section 1
 Fluid velocity inside the Annulus:
Vp = 0.408*Q
D2 2- D12
Vp = fluid velocity in the pipe, ft/sec
Q = Volumetric flow rate, gal/min
D2 = hole diameter, inch.
D1 = outside diameter of drill pipe or drill color, inch.
Mud Characteristics

Section 1
B- Density:
Is weight per unit volume of mud and has a buoyant
effect upon the particles (solids).
An increase in mud density gives rise to an increase in
carrying capacity .
Mud Characteristics

Section 1
Mud Characteristics
C–Viscosity:
Resistance to flow measured as a timed rate of flow.
Viscosity depends on the concentration, quality, and
dispersal of the suspended solids

Section 1
 Viscosity: the resistance to flow.
 Low viscosity:
Removes greater percentage of all particles size,
medium and large.
 High viscosity:
Removes greater percentage of large particles size,
but less small particles because the small particles stay
in the mud.
Mud Characteristics

Section 1
Behavior & Flow Performance of Drilling Fluid
 Fluid Rheology
Rheology is derived from the Greek words rheo,
meaning flow, and logy, meaning science. It can be
defined as the science of the deformation and flow of
solids, liquid, and gases.

Section 1
 The term rheology refer to the use of the shear stress,
shear rate, and time relationship of drilling fluids. The
shear rate is determined by the flow rate of the fluid
through a particular geometrical configuration.
Resistance of the fluid to the applied rate of shear is
called the shear stress, which is analogous to the pump
pressure.

Section 1
 The accurate description of the fluid rheological
properties is fundamental to specific applications such
as:
1. The prediction of pressure drops and equivalent
circulation density in the well bore.
2. The design of optimum hydraulics for effective
well bore cleanup and stability.
3. Determination of optimum operating conditions
such as pumping rate and circulation pressure for
fluid displacement and solids placement.
4. The suspension and transport of solids.

Section 1
 Rheological characterization of drilling / completion
fluids
It is essential to use a minimum of 6-speeds in a
viscometer to characterize drilling and completion
fluids. A common multi-speed viscometer is the six-
speed Fann model 35A. The operating speeds are 600,
300, 200, 100, 6 and 3 rpm. At the rig site the
rheological properties of drilling fluids are measured at
ambient pressure and at elevated temperature, usually
120 or 150° F.

Section 1
 FLOW CHARACTERISTICS
This flow is primarily the relationship between flow
rate and pressure drop and the effect of these on the
flow characteristics of the drilling fluid.
 There are two different kinds of flow regime:

Section 1
 Laminar Flow
This occurs at very low velocities, flow is orderly,
viscous and the fluid elements follow in “streamlines”.
Velocity and pressure of the fluid are a function of
viscous properties of the fluid.

Section 1
 Turbulent Flow
In the turbulent flow the fluid elements move in
countless eddies, swirls or disorderly at high velocities.
It depends on the inertia properties of the fluid in
motion and flow equations are empirical.

Section 1
 Fluid Classification
Newtonian Fluid:
Fluids in which the shear stress is directly proportional
to the shear rate are called - Newtonian. Water, brine,
oil are examples of Newtonian Fluids. The viscosity of
a Newtonian fluids, i.e. ratio of the shear stress to
shear rate is constant for any given temperature and
pressure.

Section 1
 Newtonian fluid is: τ= μ (γ)
τ = shear stress
μ = viscosity
γ = shear rate

Section 1
Non- Newtonian Fluid:
The viscosities of most drilling fluids change with shear
rate and thus they do not behave as Newtonian fluids. A
fluid with a viscosity dependent on shear rate is called
Non- Newtonian.

Section 1
It is desirable for drilling fluid to have a very low
viscosity around the bit for better penetration rate and
bottom hole cleaning, a relatively low viscosity in the
pipe to minimize pressure losses in the drilling string and
higher viscosity in the annulus for hole cleaning.

Section 1
A fluid whose viscosity decreases as the shear rate
increases also-called shear thinning fluid meets these
requirements.
A large number of rheological models (at least 15 models)
have been proposed which relate the shear stress to
shear rate.

Section 1
 A Review of Rheological Models
Non - Newtonian fluid flow behaviors is characterized
by a number of rheological models. Three models
widely used for drilling fluids are listed in next Table

Section 1
Bingham-Plastic Power-Law Herschel-Bulkley
τ=YP +PV (γ) τ= K (γ) n τ= τ0 + K (γ) n

Section 1
Where
τ-shear stress
PV-Bingham Plastic viscosity
YP-Bingham yield point
n-flow behaviour index
γ0-shear rate intercept
γ-shear stress
τ0-true yield stress

Section 1
 Bingham Plastic Model
Bingham plastic model is one of the simplest non-
Newtonian models used for describing drilling fluids
and can described mathematically as follows:

Section 1
The two parameters PV and YP are used extensively in
the drilling fluids industry due to relative ease in
calculating these parameters. Plastic viscosity is used as
an indicator of the size, shape distribution and quantity
of solids, and the viscosity of the liquid phase. The
Bingham yield point is a measure of electrical attractive
forces in the drilling fluids.

Section 1
 Plastic Viscosity
Plastic Viscosity depends on mud solids. The primary
concern is the solids phase in the mud. An increase in
plastic viscosity could be due to an increase in the
percentage by volume of solids.
The solids present in the drilling fluids are classified
into active and inert solids. These in turn are
subdivided into desirable and undesirable solids.

Section 1
 Removal and lowering of the solids concentration in
the drilling fluids can be done by:
1. Dilution
2. Displacement
3. Mechanical solids control

Section 1
 Yield Point
Yield point is another part of resistance to flow in a
drilling fluid. This is a measure of the electrical-
chemical or attractive forces in a given mud under
flowing conditions.

Section 1
 High yield point is normally caused by:
1. The neutralization of the negative charges of the
clay particles resulting in increase in flocculation
and yield point by the introduction of soluble salts,
cement, anhydrides.
2. Increasing the attraction between particles by the
introduction of the inert solids into the system
resulting in increased yield point.
3. drilled hydratable shale or clays into the system.
4. over treatment with chemicals increasing the
attractive forces.

Section 1
 Reduction of yield point will also decrease the
apparent viscosity. Yield point can be controlled by:
1. Addition of chemicals such as lignin, complex
phosphate lignosulphonates.
2. Water can be used to lower the yield point but
unless the concentration of the solids is very high,
The yield point can be increased using good
commercial viscosities or by anything causing the
flocculation of the mud.

Section 1
 Apparent/ Effective viscosity
An effective viscosity at given shear rate is defined as
the ratio of shear stress to the shear rate.
μe= μa=τ/γ

Section 1
Gel strength
Gel strength can be progressive (strong) or fragile (weak)
type of gel. A progressive gel is one that may start low
initially, but increase with time. This type of gel is strong
or firm and hard to break. A fragile gel may start with
high initial gel and increase slightly with time and is very
easily broken.

Section 1
Two readings are generally taken from the Fann V.G.
viscometer, one at 10 seconds (initial gel strength) and
one at 10 minutes (ten minutes gel strength). When the
difference between initial and ten minutes gel is high
progressive gels are present. They are an indication of
solids build-up. If the difference is small fresh gels have
occurred and indicate flocculation.

Section 1
 Power Law Model:
The power low model is used to describe the flow of
shear thinning or pseudoplastic drilling fluids. This
model describes a fluid in which shear stress versus
shear rate is a straight line when plotted on a log - log
graph
A power law fluid can be defined by the following
constitutive equation: -
τ= K (γ) n

Section 1
 Consistency Index (K)
The coefficient K is a constant and is called
Consistency Index. It indicates the pumpability of the
fluid. The higher the value of K the higher the viscosity
of the fluid. K can be calculated from the following
equation: -
K = 100τ300
γn300

Section 1
 Power Index (n)
The power index n is also a constant representing
characteristics of a particular fluid. It indicates the
degree of non-Newtonian characteristics. As n
decreases, the fluid becomes shear thinning or pseudo-
plastic. n can be calculated by the following equation
when two viscometer values are available:-
 n = 0.5 log τ300
τ3

Section 1
 Herschel-Bulkley Model (Modified power law)
The rheological behaviour of the Herschel-Bulkley
model at low shear rate often falls below Bingham
plastic model and above Power Law.
The Herschel-Bulkley model is rapidly gaining in
importance in industry as a more accurate description
of drilling fluid than the two traditional models,
normally Bingham plastic and power law models.

Section 1
 The reason for this is that the Herschel-Bulkley model
is a three-parameters model and thereby offers
greater flexibility when calibrated against viscometer
data. The Herschel-Bulkley model can be described
mathematically as follows
τ= τ0 + K (γ) n

Section 1
 If the exponent n is equal to one, the above equation
reduce to Bingham plastic model, if the yield stress τ0
is zero, the above equation reduces to the power law
model. If n=1 and τ0= 0 the above equation described a
Newtonian fluid with a viscosity of K.

Section 1
Fundamental Properties of Drilling Fluids
In performing the above listed functions drilling fluid
must:
• Not generate secondary reaction, which can lead to
precipitation.
• Not react with the formation.
• Not damage the formation either through plugging by
solids, bacterial deterioration, etc.
• The properties of the fluids depend largely on the
fluid composition and flow behavior characteristics.

Section 1
 Density
Density is defined as mass per unit volume. It is
convenient to express density as pound per square inch
per foot because the pressure exerted by a static mud
column depends on both density and depth. In order to
prevent inflow of formation fluids into the wellbore
the pressure exerted by the mud column must be
greater than the pore pressure of the formation.

Section 1
2 Filtration Properties
 The drilling mud must seal off permeable formations
with a thin low permeability filter cake. As the
pressure of the mud must be greater than the pore
pressure, the fluid would be continuously lost to the
formation if this cake were not in place.
 To form a filter cake the mud must contain particles
that are slightly smaller than the pore openings in the
formation, these are called bridging particles. These
particles get carried deep into the pore spaces and get
lodged; this allows a build up of progressively, smaller
particles to occur until the pore space gets blocked
right back to the surface.

Section 1
 Rheological Properties
The reological properties of the mud are defined as:
 Apparent viscosity.
 Plastic viscosity.
 Yield point.
 Gel strength.
 Flow index.
 Consistency Index.
Properties are derived from measurements carried out
with viscometers. Six- speed fann 35 viscometer is the
most common. 12- Speeds are now being introduced
for in-depth rheological characterization.

Section 1
 Solids Content
The sand content kit can measure sand content while
the retort kit can evaluated all solids in the system
plus the liquid fraction.

Section 1
 pH Value
The acidity or alkalinity of any solution is normally
described by the use of pH value.
It follows that the addition of materials that increase
the concentration of hydrogen cations results in a
decrease in the PH values. The addition of material
that decreases the concentration of hydrogen cations
(i.e. increase hydroxyl groups) would result in an
increase in the pH value of the solution.
 PH is measured by the use of litmus paper or by the
use of a pH meter.

Section 1
Water Base Mud
1. Spud mud
Spud mud are fluids used to initiate drilling operation.
These fluids have maximum hole cleaning
characteristics and should be capable of being built
quickly. They are often required to support
unconsolidated formations.

Section 1
Water Base Mud
Mixing procedure:
 Take calculate amount of water into the mud pits.
 Treat hardness level below 400ppm with soda ash.
Avoid over treatment.
 Add caustic soda to obtain required pH.
 Add bentonite and apply sufficient shearing to obtain
maximum yield and gels.
 Add med ben in ratio of 5:1

Section 1
Water Base Mud
Formulation
Fresh water spud mud:
Bentonite 15-20 ppb (pound per barrel)
Causitc soda 0.75-1 ppb
Soda ash 0.2-0.3 ppb (as required to ca++)
Med ben 1 bag for 5 every bag bentonite
Med is not used on chloride up 3,000 mg/l

Section 1
Water Base Mud
 Salt water spud mud
Attapulgite 25-30 ppb
Caustic soda 0.75-1.0 ppb
Lime 0.5 ppb
Soda ash As required to reduce ca++

Section 1
2. Low solids polymer mud
 This type system uses various materials to extend the
yield of the clays resulting in a significantly lower total
solids content.
 This type system uses polymers to reduce the
concentration of clay to improve the rate of
penetration, improve the bit life

Section 1
Formulation
Bentonite 15-17 ppb
Caustic soda 0.5- 0.75 ppb
Soda ash as required to reduce hardness below 300 mg/l
Polymer 1.0-1.5 ppb
Cmc-Lv 1.0-1.5 ppb
Cmc-Hv 0.5-1.5 ppb

Section 1
Example
Build up 1000 BBL
TO MIX LOW SOLIDS POLYMER FOR 1000BBL AS FOLLOWS:
 Bentonite (Bentonite=25kg/sx=25*2.2=55 lb)
 Bentonite =17lb/bbl*1000 bbl /55 lb/sx= 310 sack (sx)
 Caustic soda(=25kg/sx=25*2.2=55 lb)
 Caustic soda = 0.5*1000/55=9 SX
 Polymer (polymer =25kg/sx=25*2.2=55 lb)
 Polymer = 1.5*1000/55= 27 SX
 Cmc-Lv (Cmc-Lv =25kg/sx=25*2.2=55 lb)
 Cmc-Lv = 1.5*1000/55= 27 SX
 Cmc-HV (Cmc-Lv =25kg/sx=25*2.2=55 lb)
 Cmc-HV = 0.5*1000/55= 18 SX

Section 1
3. Lignosulfonate muds
In 1955 Roy Dawson introduced the Lignosulphonate
system to the oil field drilling industry and in June 1956,
the first application was used successfully in west
Hackberry field, Louisiana.
This is the most widely used inhibitive water based mud
and was specifically designed for the following main
functions:

Section 1
 Rheological stability, both during dynamic and static
conditions during trips and logging operations.
 Excellent shale inhibition, in gauge hole through active
and dispersive shale sections.
 Tolerance to contaminants, such as gypsum, salt,
cements, and drilled solids
 Lignosulfonate muds are used in deep wells that need
heavy muds and have high bottom hole temperatures.
Lignosulfonate keeps viscosity low even when the
solids content is high from adding barite, and is
effective when bottom hole temperatures are as high
as 350° F.

Section 1
 Lignosulfonate and soluble Lignite compounds are also
excellent emulsifiers when oil is added to a water base
mud.
 The amount of Lignosulfonate added to a mud depends
partly on whether the water in the system is hard or
soft; the amount can range from about 0.5-10 lb/bbl.

Section 1
 Lignosulphonate coats the particles and keeps them
apart
Flocculated clay Lignosulphonat
e

Section 1
Lignosulphonate Formulation
 Fresh water Lignosulphonate polymer mud:
material concentration
Bentonite 12 -18 ppb
Kibligin 2- 4 ppb
Caustic soda 0.5 - 0.75
Cmc- L v 1.5-3.0 ppb
Celluose -sLv 1-1.5 ppb
Celluose - R 0.5 -1.5 ppb

Section 1
Chrome lignite Chrome Lignosulfonate:
Bentonite 8 -10 ppb
Caustic soda 0.5 – 1.0 ppb
Ralgin 2.0 -4.0 ppb
Celluose -sLv 1-1.5 ppb
polymer 2.0 -3.0 ppb
Celluose -R 1.0 – 2.0 ppb
KIBLIGIN 6.0 – 8.0 ppb
Lignochrome 3.0 -4.0 ppb

Section 1
3. KCL Polymer Mud
 KCL polymer mud is suitable for drilling shale sections
due to its superior sloughing - inhibiting properties
resulting from the use of KCL and the inhibiting
polymer.
 Inhibition by KCL is attributed to the replacement of
the sodium ions in shales by potassium ions, which are
more tightly held.
 The advantages of this mud include:
 High shear thinning behavior facilitating solids removal
through the shale shaker
 Improved borehole stability

Section 1
Characteristics of the KCL MUD
 Normally when kcl is used in clay base mud a
flocculated mud system is run. Polymers or
prehydrated bentonite are used as vicosifers in these
system.
 Kcl mud will exhibit slow increase in chloride.
 Clay base Kcl mud exhibit high gel strength and yield
point.
 Kcl fluids are generally shear thinning.
 High filtration rate are common to kcl mud and
polymer additives used to reduce filtration rates.

Section 1
Mixing procedures
 Treat out the ca++ of the water to 300 - 400 mg/l.
 Add required of the kcl to make up water (3%-15%).
 Mix in separate tank prehydrated bentonite (20 -
25ppb) for the capacity of the separator tank which
will be
(6-8 ppb).
 Bleed off the prehydrated bentonite slowly into the
brine system (water +kcl).
 Adjust pH to 9-10 with potassium hydroxide.
 Add required amount of polymers (i.e, polymer, cell-
R,…)
 Increase density by adding weighting material.

Section 1
Maintenance of KCL Polymer
 Solids control equipment is vital (desiliter. Desander,).
 Monitor (k+) level and maintain the % of kcl continously
in the system.
 MBT need to be kept from 6-8 ppb.
 Use cellouse and xc-polymer for maximum rheology
control.
 Fluid loss to be maintained below 5 cc or less using
polymer, cmc-Lv, cell-sLv.
 Potassium hydroxide or caustic soda used for Ph
control.
 Defomer used to control the foam into the system.

Section 1
Basic formulation for kcl polymer mud
 Inhibition (kcl) 3-5% normally up to 15%
 Viscosities xc-polymer 0.5 - 0.75 ppb
cellulose -R 0.5 -1.0 ppb
cmc-Hv 1 - 1.5 ppb
prehydrate Bentonite 6 - 8 ppb
or / calcipolate 1.0 ppb
 Filtration
polymer 3.0 - 4.0 ppb
cell - sLv 1.0 - 1.5 ppb
cmc - LV 1.0 - 3.0 ppb

Section 1
Calculations
 KCL ppm = (cl x 2.1 x %purity)
 K+ ppm = kcl ppm x 0.52
 Kcl (lb/bbl) = K+ ppm /1496
 Kcl % = Kcl (lb/bbl) /3.5

Section 1
Example
 Mixing kcl polymer mud @10.5 ppg (8% kcl)
 Water 0.85 bbl
 Kcl 28 ppb
 Bentonite 6 ppb
 Xc-polymer 0.5-1.0ppb
 Cellulose - R 1.0 ppb
 Polymer 4.0 ppb
 Cellulose - sLv 1.5 ppb
 Caco3 110 ppb

Section 1
4. Salt saturated polymer mud
Saltwater muds are those muds having salt (NaCl)
concentrations above 10,000 ppm or 1% salt. The salt
concentration can vary from 10,000 ppm up to 315,000
ppm. The salt concentration, present in any drilling fluid,
must come from the following:
• Drilling salt string or massive salt.
• Salt water flows.
• Salt added purposely to the system.
• Salt from the make- up or treating water.

Section 1
4. Salt saturated polymer mud
 Saturated salt water muds are generally limited to
drilling operations encountering salt formations and to
work over operations.
 Saturated salt mud are prepared by adding Nacl to
water for solution and then adding appropriate
viscosifiers and fluid control agent.

Section 1
Characteristics
 Normally utilize a saturated or near saturated (Nacl
brine base) also we can use Kcl.
 Require good mixing conditions or circulation time to
develop good suspension properties.
 Exhibit high gel strength and yield point.
 Starch or polymer begin to degrade @ temperature
above 250oF , polymer and strach for filtration control
and rheology.

Section 1
Characteristics
 Higher alkalinities are less corrosive and where pf=1.0
or greater.
 Deformer help to reduce foaming problem, these
material more effective when added to the brine
before mixing other materials.
 Starch fermentation is generally not problem if the
system saturated with salt. To ensure against
fermentation, a suitable starch preservatives may be
added.
 Solids content should be corrected for soluble salts.

Section 1
Maintenance
 Install the finest possible mesh screen on shaker and
mud cleaner to discard maximum generated drilled
solids.
 Control fluid loss using starch.
 Dilute the mud using salt saturated system while
adding Barite maintain to the required density during
drilling.
 A small amount of fluid loss reducer can be used in
combination with starch to control fluid loss.

Section 1
Maintenance
 Use small amount of caustic soda to adjust pH in range
8-8.5.
 Use small amount of deformer in the event of
foaming.
 Use small amount of starch & Xc polymer to adjust the
properties.

Section 1
Treatment
Using weighted salt saturated mud following steps are
necessary to be taken to maintain a minimum possible
over all mud viscosity, gel and provision of saturation
point of water salinity to perform effectively during
drilling salt formations and the shale.

Section 1
Treatment
 Salinity should be maintained over 180,000mg/l of
chloride (315,000) of sodium chloride to avoid hole
enlargement.
 Mud dilution to be maintained only using the prepared
salt saturated solution with or without starch (upon
fluid loss control)
 Fluid loss and initial properties can be controler using
starch.
 Cellulose R & Xc polymer in range of 0.75-1 can be
added in the make up of salt saturated system.

Section 1
Un-Weighted Salt Saturated Muds
Formulation
Nacl 120-125ppb
Caustic soda 0.25 -0.5
Attapulgite 8-10ppb
Starch 6-8 ppb
Cellulose R 0.5 -1.5ppb
Soda ash as needed for ca++(300-400)

Section 1
Weighted Salt Saturated Muds
Formulation
Nacl 120-125ppb
Caustic soda 0.25 -0.5
Attapulgite 1.0-3.0ppb
Starch 6-8 ppb
Cellulose R 0.5 -1.0ppb
Soda ash as needed for ca++(300-400)
Barite to increase the mud weight
 Bentonite may used for make up only for gel,YP.

Section 1
Lime mud & gypsum mud
Calcium treated mud are often used in areas where shale
hydration and swelling results in significant bore hole
instability (i.e sloughin and heaving) increased levels of
soluble calcium are maintained in these fluids to provide
an inhibitive to minimize shale swelling.

Section 1
Theory of calcium treated mud
When calcium is added to water Bentonite, there is a
base “exchange” from sodium base to calcium base clay.
The calcium replace the bonding ion sodium, because of
greater bonding energy. Viscosity decrease from partial
dehydration of the clay. The sodium clay has a thick
envelope of water around the particles. The thickness
decrease when calcium replaces sodium

Section 1
Effect of Chemical Upon Pre Hydrate Clay
Calcium inhibitive mud are most often made from the
lightly treated native mud used in top hole drilling. The
conversion or “breakover” is performed viscosity will
increase initially by adding the break over chemical. This
is followed by decrease of viscosity. This increase and
decrease is called the viscosity “Hump”.
Next figure shows increase the viscosity from
flocculation by the calcium then decreasing the viscosity
from the base exchange.

Section 1
 Viscosity effect of calcium muds
viscosity
Filtrate calcium (ppm)
100 200 300 400 500 600 700
100
80
40
20
High
solids
Low
solids

Section 1
The increase of viscosity during conversion depends upon
total solids, Bentonite content, pervious chemical
treatment.
Next figure shows the viscosity rise or Hump under
different condition:
• With high solids and bentonite content.
• With moderate solids and bentonite content.
• With low solids and bentonite content.

Section 1
Viscosity Effect of Treating Different Mud
viscosity
Addition of chemical
1
2
3
High solids
Moderate solid
Low solids

Section 1
Lime treated mud
 Lime mud are calcium treated mud utilizing lime as
the source of soluble calcium.
 Their composition consist of caustic soda, dispersant,
lime and fluid loss control.
 Three types of lime mud were devolved
1. Low lime, low alkalinity.
2. Conventional lime.
3. High lime, high alkalinity.

Section 1
Lime treated mud
 All three types are similar and very only in alkaline and
lime concentration.
 High and convention lime are often used when
contamination or drilling mud making formation with
weight mud were problem.
 Low lime mud are often used were high temperature
effect upon High and convention lime system
presented stability problem.

Section 1
Method of Converting to Lime Mud
 The most converting made from low Ph, low solids
content.
 Viscosities should be between 30-40 sec/qt.
 If solids are high, water should be added to prevent
excessive thickening during the breakover.
 Most conversation are made in one circulation by
adding caustic soda, dispersant and lime, fluid loss
control is always adding on separate circulation.

Section 1
Gypsum Treated Mud
 Gypsum mud use calcium sulfate to achieve inhibition.
 The same chemical which were used in lime mud.
 Used to drilling shale problem and massive anhydrite
section
 They have normal pH range in 9.5-10.5 and ca++ 600-
1200ppm in the filtrate.

Section 1
Preparation of Gypsum Mud
 Water is added prior to or drilling the breakover
operation. The amount of water required can be
estimated by pilot testing.
 Viscosities should be between 30-40 sec/qt.
 Most conversation are made in one circulation by
adding caustic soda, dispersant and lime, fluid loss
control is always adding on separate circulation.

Section 1
Low Solids Polymer

Section 1
Low Solids Polymer
Functions :-
 Increase ROP.
 Reduce loss of circulation.
 For normal formation pressures.
 Areas of no sloughing or heaving shales.
 Contains less than 5% by volume l.g.s.
 Low solids ( fresh and salt )with polymer and additives
 Polymer of high molecular weight.

Section 1
Low Solids Polymer
 Polymer of solids ( flocculant ) to settle them (flocs).
 Use of solids control equipment).
 Stream of water for low solids and low mud weight.
 Med - ben to be used of 5:1 (bentonite : med - ben).
 Use soda ash to treat ca++ and / or hardness.
 Use caustic for pH control.
 Add % of diesel to assist lowering MW and as a
lubricant , slicken hole.

Section 1
Low Solids Polymer
 If necessary sweep hole with high viscosity Gel slurry
prior to trips or connections to clean annulus.
 Diesel to be added to reduce solids , increase ROP ,
lower MW , reduce torque .
 Increase stabilization , shear thin , hole clean , low
ECD , low HP , small inventory , formation protection ,
require more dilution.

Section 1
Low Solids Polymer
LOW SOLIDS NON- DISPERSED MUD:
 The lower the solids the higher the ROP.
 Polymers are viscosities and fluid loss control agents.
 Dispersants increase the muds tolerance for solids.
 Yp is the ability of mud to lift cuttings and suspend
barite.
 Low weight non- dispersed ( invert rheology), YP MORE
THAN PV .

Section 1
Low Solids Polymer
 The more inverted the rheology the lower the,( n).
 Solids build up can thicken the non- dispersed mud to
point where additions of dispersants become
necessary.
 Because organic dispersants are absent, and colloidal
solids concentrations are low, minimum solids and non
disp mud exhibit higher water loss.

Section 1
Product Application of Drilling Fluids
 Next slids show all the product using in drilling fluids.
Viscosity product.
Weighting agent product.
Fluid loss control product.
Salt products.
Oil base product
Deflocculated products.

Section 1
 ATTAPULGITE
Viscosifier for use in salt water muds.
 BARITE (Barium Sulfate Used as a primary weighing
agent.

Section 1
 BENTONITE Sodium Montmorillonite
Used as primary viscosities in fresh water
mud.

Section 1
 CAL. CARBONATE(Ca Co3)
Powdered limestone, Acid soluble low gravity weighing
(Fine grad)
materials fro increasing density up to 12.0ppg in
workover and drilling fluids.

Section 1
 HEMATITE
(Iron Oxide)
Used as weighting materials with specific gravity of
5.0gr/cc. Applicable in all types of drillings fluids.

Section 1
GUAR GUM
Description
Off-white powder which is rapid mixing high viscosity
polymer for use in fresh water and sea water spud muds

Section 1
APPLICATION
 Used as weighting materials with specific Connection
too insure that all cuttings are removed from the
annulus while drilling surface hole with water. It is
particularly useful in off-shore and it can be added
directly to sea water.

Section 1
DRILLSTAB (ASPHLAT)
Description
Blown asphalt powder
APPLICATION
Oil soluble, water dispersible fluids loss control agent.
Used to seal micron fractures in shale.

Section 1
 BIOPOLYMER
Description
Xanthum Gum Biopolymer
APPLICATION
High molecular weight linear polysaccharide. Used for
obtaining very high viscosity & gel strengths without
needing a clay-base.

Section 1
 Calcipolate
Description
Blend of HEC polymer and Calcium Carbonate.
APPLICATION
1. Acid soluble viscosities and fluid loss control agent
for brine workover fluids.

Section 1
 PAC-R
Description
High Molecular Weight Polyanionic Cellulose polymer.
APPLICATION
Very high purity cellulosic polymer fluids loss control.
Also achieves high viscosities, Lessening Bentonite
requirements. Can be used in all water base drilling
fluids at high temperature.

Section 1
 PAC-SLV
Description
Low molecular weight Polyanionic Cellulose
APPLICATION
An extremely effective non viscosifying fluid loss
reducing agent. Tolerates higher temperatures to over
300 F.

Section 1
 CMC-HV
Description
Sodium Carboxyl /Methyl Cellulose, High Viscosity
APPLICATION
Provides higher viscosity's with lesser concentration.
Reduces fluids lose of water base muds. Losses its
effectiveness in presence of high chlorides.

Section 1
 CMC-LV
Description
Sodium Carboxyl /Methyl Cellulose, Low Viscosity.
APPLICATION
Fluid loss control agent which does not greatly affect
the rheology of the drilling fluid.

Section 1
 XCD POLYMER
Description
High quality xanthum gum biopolymer
APPLICATION
Polysaccharide imparts maximum shear thinning
behavior while perform viscosity and control fluids loss
at any Ph or salinity and hardness. Exhibits max.
Viscosity at cross link system.

Section 1
 BENEX
Description
Bentonite Extender
APPLICATION
Used to increase the yield of Bentonite to form ultra
low solids mud and also in clear water drilling.

Section 1
POLYMER
Description
Modified polysaccharide
APPLICATION
Filtration control agent which can be used in any type of
water base mud.

Section 1
 STARCH
Description
Pre-gelatinized Starch
APPLICATION
Used as a fluids loss control agent. Subject to
degradation and should be used in conjunction with
starch preservative.

Section 1
 PHPA
Description
High molecular weight polyacrylamide.
APPLICATION
With its extremely high molecular weight
and unique absorption properties acts as
an highly affective encapsulating agent.

Section 1
Cont for PHPA
This result in the inhibition of the dispersion of the drill
cuttings in sensitive shale formation. An initial treatment
of 0.5 to 0.75 ppb is recommended and level of 0.5 ppb
should be maintained in the mud filtrate.

Section 1
Cont for PHPA
 PHPA (Powder)
Description
It is partially hydrolyzed polyacrylamide-Polyacrylate
Copolymer of anionic Character & high molecular
Weight. Stable to temperatures Exceeding 400 F, it is
efficient

Section 1
Cont for PHPA
APPLICATION
Maintains hole stability by preventing shale swelling and
erosion. It is highly efficient in LCL Mud system where it
coats the drill cuttings and acts by encapsulating active
shale plates to form an impervious protective layer on
both walls and the cuttings and this inhibiting.

Section 1
Cont for PHPA
 DISPERSE (CLS)
Description
Chrome Lighosulfonate
APPLICATION
Dispersant and deflocculant agents for all water base
mud, also acts as a emulsifier and aids in controlling F.
Loss.

Section 1
Cont for PHPA
DISPERSE FCL
Description
Ferrochrome Lighosulfonate
APPLICATION
dispersant and inhibitor where temperature exceeds 280
F. Contains ferro ions thus realize shale stability. It
reduce fluid loss and is an excellent rheology stabilizer at
high temperature.

Section 1
Cont for PHPA
 S.A.P.P
Description
Sodium Acid pyrophosphate
APPLICATION
A Ca++ sequesting agent for high Ph cement
contamination in fresh water muds at low
temperature.

Section 1
Cont for PHPA
 T.S.P.P.
Description
Tetra sodium pyrophosphate
APPLICATION
Used for Ca++ contamination at low temperature. Not
effecting pH.

Section 1
Cont for PHPA
 CACO3 (Fine)
Description
Calcium Carbonate
APPLICATION
Used as bridging agent and/or LCM in
Workover and completion fluids. It is acid
Soluble and grain size is 50-75u micron.

Section 1
Cont for PHPA
 CACO3 (Medium)
Description
Calcium Carbonate
APPLICATION
An acid soluble bridging agent and LCM
for W.O. and completion fluids with 75-
100 u. micron.

Section 1
Cont for PHPA
 NUTSHELL (F.M.C.)
Description
Crushed Nut Shells.
APPLICATION
Used as lost circulation material. Available in fine,
medium, or coarse grades.

Section 1
Cont for PHPA
 NLMICA (F.M.C.)
Description
Ground Mica
APPLICATION
Used as lost circulation material. Available in fine,
medium, or coarse grades.

Section 1
Cont for PHPA
 FIBWOOD
Description
Shredded Wood Fiber
APPLICATION
Used as lost circulation material.

Section 1
Cont for PHPA
 ALUMINIUM STEARATE
Description
ALUMINIUM STEARATE
APPLICATION
Defoamer Mixed in diesel oil for use in water based
muds.

Section 1
Cont for PHPA
CALCIUM CHLORIDE
Description
CaCl2
APPLICATION
Calcium salt used to control salinity of water phase in oil
muds. also used for brine Solution in completion fluids.

Section 1
Cont for PHPA
 CASTIC SODA
Description
NaOH
APPLICATION
Provides pH control in all water base
mud systems.

Section 1
Cont for PHPA
 LIME
Description
Ca(OH)2
APPLICATION
Source of calcium to build lime muds. also
Used as sequestering agent for carbonate
Alkalinity control.

Section 1
Cont for PHPA
POTASSIUM CHLORIDE
Description
KCl
APPLICATION
Potassium salt used in KCl polymer system.
provides excellent inhibition in most types of
Shales.

Section 1
Cont for PHPA
 POTASSIUM HYDROXIDE
Description
KOH
APPLICATION
A source of hydroxyl ions for pH control in potassium
base mud

Section 1
Cont for PHPA
 SODA ASH
Description
Na2CO3
APPLICATION
To remove free calcium in low pH muds.

Section 1
Cont for PHPA
 SODIUM BICARBONATE
Description
Na2Co3
APPLICATION
To remove free calcium in high pH muds.

Section 1
Cont for PHPA
 SODIUM CHLORIDE
Description
NaCl
APPLICATION
For building salt muds and/or completion brines.

Section 1
Cont for PHPA
 STARCH PRESERVATIVE
Description
Para formaldehyde
APPLICATION
Prevents bacterial degradation of ferment-able
material. Used in Conjunction with untreated starch.

Section 1
Cont for PHPA
 NLHYDSULPHELEM
Description
ZnCO3
APPLICATION
Used as scavenger for H2S.

Section 1
Cont for PHPA
 ZINC CHLORIDE
Description
ZnCl
APPLICATION
Water soluble weighting agent used to prepare heavy
clear brines.

Section 1
Cont for PHPA
 DD (Drilling detergent)
Description
Solution of anionic Surfactants
APPLICATION
Drilling mud detergent reduces bit balling, torque and
drag; can also used as a demulsified

Section 1
Cont for PHPA
 (Carrbo Tec)
Description
Modified calcium salts of higher organic acid.
Application
Primary emulsifier of invert oil emulsion it stabilizes
the emulsion, aids suspension properties.

Section 1
Cont for PHPA
 (Carrbo Mul)
Description
Oil soluble surfactant
Application
Secondary emulsifier and oil wetting agent

Section 1
Cont for PHPA
 (Carrbo trol)
Description
Organophyllic lignitic colloide
Application
Fluid lose control agent and secondary emulsifier in oil
base mud.

Section 1
Cont for PHPA
 (Carrbo gel)
Description
Organophylic clay
Application
Viscosifier and gelling agent.

Section 1
Cont for PHPA
 OILYIELD
Description
Organically treated smectite Clay
Application
High performance viscosifying clay for invert oil
emulsion. Also it is used to increase viscosity of diesel

Section 1
Cont for PHPA
 OILTHIN
Description
Polymeric surfactant
Application
Oil mud conditioner. Reduces gel strength and
viscosity.

Section 1
Cont for PHPA
 WETTAGENT
Description
Phospolicide surfactant
Application
Oil wetting agent to eliminate water wetting of solids.

Section 1
Cont for PHPA
 RHEOMODE
Description
Modified Fatty acid
Application
Rheology modifier using in VERT and real oil - mud
systems.

Section 1
Cont for PHPA
 PIPEFREE BREAKER
Description
Application
Used with diesel as soak solution to free differentially
stuck pipe (S).

Section 1
Cont for PHPA
 TORQUE REDUCER
Description
Application
Reduces torque and the risk of stuck pipe in water
based drilling.

Section 1
End of this
Section

Section_01 FLUIDS OVERVIEW.ppt

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