06 drilling fluids

Shell Special Intensive Training Programme
Oyeneyin, M.B. Page 1 of 18 ©Univation
6 DRILLING FLUIDS AND APPLICATIONS
6.1 Introduction
Drilling fluids are generally the "blood" of all drilling operations 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 operating costs.
To minimise 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:
• Deeper well drilling/completion especially in high temperature and
pressure environment.
• Increasing use of advanced wells (ERD, multilateral and horizontal wells)
• Stiff environmental regulations
Historically, either water based muds (WBMs) or Oilbased muds(OBMs) have
been used for drilling especially in the North Sea and other operational areas
of the world. The performance of many water-based muds makes them to be
particularly deficient in drilling deep, high angle, extended reach wells or in
high temperatures and pressures. Oilbased muds are therefore being used in
large numbers to overcome these deficiencies. As the operating companies
make aggressive moves towards the exploration/ development in the deeper
waters, the use of OBMs has increased tremendously. Although wells drilled
with OBMs produce lower waste volumes, the Environmental Protection
Agencies worldwide and in particular the HSE in the UK have stiff guidelines
on the release of free oil and drill cuttings discharges and wastes are usually
not allowed to be discharged on site. This has led to the development of a
variety of potentially low-toxicity, biodegradable synthetic based muds(SBMs)
and a variety of pseudo-oil based muds(POBM) which theoretically offer better
pollution prevention potential over oilbased muds.
These systems definition of the optimum operating conditions for completing
oilwells nowadays depend largely on the understanding of the complex fluid
mechanics of drilling/completion fluids. A good knowledge of the fluid

rheological behaviour is fundamental to this understanding most especially
with respect to:
• The formulation of the fluid recipe
• Accurate prediction of pressure drops
• Design for optimum hydraulics for effective hole cleaning and stability, fluid
displacement strategies for cement-mud displacement, etc.
6.2 Functions of Drilling Fluids
Basically, drilling fluids are used to :
1. Remove cuttings from the bottom of the hole and carry them to the surface
2. Release any carried sand and cuttings at the surface
3. Hold cuttings and any weight materials in suspension during circulation
interruption
4. Cool and lubricate the bit and drillstring
5. Wall the borehole wall with an impermeable filter cake
6. Control formation pressure
7. Support part of the weight of drillpipe and casing
8. Reduce to a minimum any adverse effects upon the formation adjacent to
the hole
9. Insure maximum information about the formations to be penetrated
10.Transmit hydraulic horsepower to the bit
11.Prevent and control corrosion of drillstring and other wellbore facilities

6.3 Properties of Drilling Fluids
In performing the above listed functions drilling fluids must not:
• generate secondary reaction which can lead to precipitation.
• Must not react with the formation
• must maintain stability of properties under the operating conditions of
temperature and pressure
• must 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
behavioural characteristics. Nevertheless, the key properties of the drilling
fluid are:
1. Mud Density -'This is measured normally with a mud balance.
2. Rheological properties:Apparent Viscosity, Plastic Viscosity, Yield Point,
Gel Strength, Flow behaviour index (n), Consistency(k).
-Properties are derived from measurements carried out with viscometers
Six speed Fann 35 viscometer is the most common. 12-speed versions
are now being introduced for in-depth rheological characterisation. Details
of computational techniques are presented in section 4. The Marsh
Funnel also provides a quatitative information on the fluid viscosity. The
relative new Fann 70 allows for fluid analysis under pressure and high
temperature.
3. Fluid Loss: Both filtrate (in millilitres) and cake thickness(in 1164") are
measured using the Filter Press. There are static and dynamic filter
presses for static and dynamic filtration.
4. Solids Content: Sand content can be measured by the sand content kit
while the retort kit can evaluate all solids in the system plus the liquid
fractions.

5. pH - This is measured using the pH meter or the litmus paper. pH<7 is
acidic and pH>7 is basic.
6. Resistivity -This is measured using the resistivity meter.
There are other measurements/analysis carried out on drilling fluids, but the
above are the relatively basic ones.
6.4 Drilling Fluid Composition
Drilling fluids can be either gas, liquid slurry or foam. The liquid slurry is called
drilling mud and is the most commonly used drilling fluid. Gas drilling fluids are
hardly used but for some special applications. They are used in combination
with the liquid a foam fluids especially for underbalanced drilling.
The Drilling Mud
The mud is basically made up of:
1. A continuous phase which can be either water, oil and is the base fluid
2. A dispersed phase which ca-n be basically clay(bentonite) or other
solids(asphalt, etc)
3. Chemical additives to control fluid properties such as weighting materials
(Barytes), viscosity and loss control additives.
From the point of view of mud logging, drilling muds offer the best advantage
especially with respect to cuttings recovery and well control.
There are basically three major types of drilling fluids nowadays. These are:
A. Water based drilling fluids
These are a mixture of solids, liquids and chemicals. These are active solids
like bentonite added to water with the water as the continuous phase. .
Bentonite acts mainly as the dispersed phase providing the main gel structure.
Chemical additives are added in various proportions to control the fluid
properties. These chemical additives are commonly used for the control of pH,
viscosity, weight, fluid loss, etc.

For example,
• Caustic soda is used to control pH and can be classified as an active solid
• Barite is used to increase mud weight; This is an inactive solid
• CMC (Carboxy-methyl-Cellulose) a polymer is used to control fluid loss;
This is an active additive
• Lignite can be used to control mud viscosity; This is an active additive.
There are also Loss Control Materials (LCM) to prevent and control the total
loss of whole mud into the formation. Examples are nut plug, byrofibre, Mica,
etc and are inactive materials.
The chemical additives normally provide the generic names for the different
water based muds. Examples are
1. Inhibitive Mud - These are calcium based muds used to control swelling
and hydration of clays and sensitive shales. Highly suitable for drilling
formations containing gypsum and hydrites as well as dirty sands(sands
with high clay content).
2. Dispersed - Lignosulphonate Muds - Such muds can be made up of water,
bentonite, caustic soda, CMC polymer and Lignosulphonate. They have
good viscosity control, high solids tolerance and good fluid loss control.
They are suitable for use when:
• High mud weight is needed > 14ppg
• Drilling under moderately high temperature
• High contamination is expected
• Low fluid loss is required
3. KC1/Polymer Muds: These are non-dispersed muds used to drill water
sensitive, sloughing shales. Typical compositions can be as follows :

Water or brine; potassium chloride; Caustic soda; CMC- Lubricants;
bentonite and possibly HEC.
4. Salt, Saturated Muds - These are brine based fluids in which the
continuous phase is either Sodium chloride, Calcium Chloride, Calcium
Bromide, Zinc Bromide, etc. They are good for drilling through salt sections
where fresh water mud contamination is a major threat.
B. Oil Based Muds
These are similar in composition as Water based muds except that the
continuous phase is oil. There are three types
1. Pure oil based muds
2. Water-in oil - emulsions with oil as continuous phase and water as
dispersed phase
3. Invert muds I.e. oil-in water emulsions with water as continuous phase and
oil as dispersed phase.
These muds are generally more expensive and require more stringent
pollution control. Their use is generally restricted to conditions where WBM
are dangerous, technically impossible or uneconomical to use. These include
high pressure and high pressure applications as well as conditions where the
formation such as shale, is highly sensitive to water based muds. They are
particularly popular for drilling advanced wells such as extended reach wells,
multilateral and horizontal wells.
Typical composition can be:
• Diesel as base oil
• Calcium or sodium chloride
• Water in dispersed phase
• Bentonite

• Typical additives
• LCM
• Barytes, etc.
C . Synthetic Based Muds
Because of the environmental effect of oilbased muds, many drilled cuttings
have to be processed to clean out the oil before dumping to Meet control
regulations. This makes its use rather expensive. To reduce cost and
minimise pollution, new synthetic oils are now being developed and used to
make synthetic based muds(SBMs). The SBMs are classified according to
molecular structure of the synthetic base fluids which can be esters, ethers,
etc. They have drilling and operational properties similar to OBMs but have
the advance of being more “environmentally friendly".
Likewise, so-called pseudo oil based muds are also being developed which
are mainly water based systems but possess the merits of oilbased muds
especially in terms of stability at high temperature and high pressure.
6.5 Drilling Fluids Classifications
Drilling/completion fluids are predominantly non-Newtonian, the flow
behaviours of which are very complex and varied depending on the type and
composition of the fluids. Therefore appropriate knowledge of, prediction and
control of the fluids rheology are essential to successful fluids optimisation.
Generally, drilling and completion fluids are known to possess the following
visco-elastic properties for a variety of oilfield operations:
• Effective or apparent viscosity
• Plastic viscosity
• Yield point
• Gel Strength

• Flow behaviour index
• Consistency index
The accurate description of these fluids rheological properties is fundamental
to specific applications such as:
• The prediction of pressure drops and equivalent circulation density in the
wellbore The design for optimum hydraulics for effective wellbore cleanup
and stability Determination of optimum operating conditions such as
pumping rate and circulation pressure for fluid displacement and solids
placement.
• The suspension and transport of solids including cuttings and milled swarfs
• Design for the concentration and type of chemical additives for optimum
fluids formulation.
The operating window of fluid rheology should therefore:
• enable effective solids removal including cuttings, swarfs and debris
• minimise pressure losses
• prevent hole erosion
• enable fluids and solids placement /displacement.
Accurate prediction of the flow behaviour and flow model is the key to
adjusting the rheological properties for specific applications.
Fluids are generally classified in accordance with their relative rheological
models
6.5.1 Fluid Rheological Models
In general, the Bingham plastic and Power Law models represent the popular
models used for defining drilling/completion fluid rheological properties. These
models are separately expressed as:

1. Bingham Plastic Model
Most bentonite-water mixtures fall into this category
The behaviour is defined mathematically by the following equation
τ = τy + µp∗γ
In field units,
τ = Shear stress, lb/100ft2
: τy = Bingham yield point, lb/100ft2
:
µp = Plastic viscosity, cp; γ= Shear rate, sec
2. Power Law Model
Most polymer based muds fall into category and it is defined mathematically
as:
τ = n
K γ*
However, more specialised models are now available to characterise the
different types of more complex fluids now in use within the oil industry. These
are the Herschel-Bulkley(HB) model, Cassons model as well as the Robertson
and Stiff model.
3. The Herschel-Bulkley model
This is a more generalised classification and majorities of modern mud
recipes fall into this category. It is expressed mathematically as:
n
y K γττ *
+=
4. Casson’s Model:
2
1*
10
2
1
γτ KK +=
5. Robertson and Stiff model:
( )B
CA += γτ
where

τ = Shear stress
τy =Yield point
µp = Plastic viscosity
γ= shear rate
n = Flow behaviour index
K =consistency index
Α,Β,Χ,Κ0 and Κ1 are flow constants.
Generally,
Plastic viscosity (cp)
300600 θθµ −=p
where
θ600, 300 = dial readings at speeds 600rpm and 300 rpms respectively.
Bingham yield point (lbs/100ft2
)
py µθτ −= 300
Apparent Viscosity at each rotary speed,
cp)gives100byd(multipliepoise,
γ
τµ =s
Get Strength (lb/l00 ft2
)
This is based on the maximum dial deflection on viscometer when turned at
low speed which is 3rpm speed for a 6-speed Fann 35 or 0.9rpm for a
12speed Fann35. The Gel strength results are presented as 10sec. Gel and a
10 minute. Gel.
Fig. 6.1 shows an illustration of the profiles.

6.6 Drilling Fluid Design
The design of drilling fluids for optimum results involves the specification of :
1. Type of drilling fluid to use
This depends largely on the type of formation to be drilled and the expected
downhole operating conditions including the potential hazards to be
encountered. These will invariably dictate the actual type and composition of
the fluid in terms of chemical additives.
2. Specification of Fluid Density
One of the primary functions of the drilling fluid is the control of formation
through the imposition of hydrostatic pressure on the formation. Thus, the
mud must be of sufficient density to meet this basic function
Therefore
0.052*ρm*D=pR +POB
PR = Reservoir or pore pressure, psi
POB = Overbalance (Usually about 200psi is enough but could be as high as
500psi depending on the conditions)

It is important that the imposed pressure must not be more than the maximum
allowable which must be a factor less that the formation breakdown pressure.
From the above, the mud density required can be computed as follows
ρm = (PR +POB )/(0.052 * D)
3. Fluid Rheological Properties
The main rheological properties are apparent viscosity, plastic Viscosity, gel
strength, yield, n and K. The drilling mud must have good suspension and
carrying capacities. Therefore optimum combination of these properties are
required. These properties are adjustable to suit specific requirements
whereas the mud density is largely dependent on the formation pore pressure.
4. Other properties
Other relevant properties are as specified in Section 2.2 above and can be
adjusted to requirements.
6.6.1 Choice of Drilling Fluids
The main factors governing the choice and composition of drilling fluids are
mainly
• Types of formations to be drilled
• Range of temperature
• Formation pressure and rock strength which dictate the mud weight and
fluid type
• Formation evaluation technique which might require change from oil based
to water based mud; e,g. Resitivity logs.
• Water quality e.g Offshore where sea water may be used resulting in the
use of unsaturated salt water muds!
• Environmental considerations.
• Borehole problems

6.7 Effect of High Pressure and High Temperature on Drilling
Fluid Properties
High pressure and high temperature are known to have major effects on
especially the drilling fluids.
Temperature Effects
Generally, water based drilling muds are known to be highly unstable in HP-
HT wells with viscosity reducing with increase in temperature; Baryte sag
and secondary reactions and breakdown of polymer systems have been
known to occur.
Increase in temperature is also known to lead to a decrease in mud weight
especially for oilbased muds with density at surface being lower at depth
than at the surface. This no doubt will have major effect on the bottom hole
circulation pressure, as the equivalent density would be lower than expected
which can result in a potential influx of formation fluid into the wellbore.
The effect on fluid loss on the other hand is not well known except that the
possibility of mud instability can lead to the presence of more 'more' 'free
water' which can result in higher filtrate loss. However, the reduced annular
pressure may minimise this loss.
Pressure does not appear to have any major effect on the fluid rheological
properties but density has been known to decrease with increase in pressure.
For oil based muds, temperature has been known to lead to a decrease in
viscosity while pressure causes an increase in viscosity.
Barite sag i.e. the settling of solids onto the low side wall of a deviated hole or
to the sump of a vertical hole. Potential avalanche of solids settling will lead to
inconsistency with respect to mud weight. Attempting to viscosity the mud
may lead to a higher Equivalent mud density which may result in fractures and
potential lost circulation problem.

Effect of Pressure
Increase in pressure generally appears to have an increase in equivalent mud
density with depth but probably to a lesser degree.
Effect on rheology however is not well defined. While thermal expansion
appears to affect the rheological properties, the mud compressibility does not
seem to be affected by rheology. However at low shear rate, some mixed
effects have been observed with viscosity increasing with increase in
pressure.
Thus, adequate correction for the fluid properties must be effected when
drilling HP-HT wells.
Suggested Control
1. To avoid HP-HT problems, it is essential to understand the response of
the chosen mud to HP-HT. This includes prediction of down hole mud
weight and rheology. This will guide the choice of fluid properties at
surface and the mixing formula.
2. Efforts should be made to make the low shear rate rheology as high as
possible to suit existing hole conditions.
3. Fluid properties must continuously be monitored and treatment by
thinners should be avoided where possible to avoid potential hole
problems.
4. Use of small/ medium size range of weighting materials 'm small
concentrations may help in minimising barite sag.
5. Excessive mud circulation at low flow rate should be avoided if possible
and circulation bottoms-up at each predefined point to reduce heavy
mud presence in the annulus should be encouraged.
6. Optimum hydraulics are crucial to a successful drilling of HP/HT wells
to avoid problems
6.8 Drilling Hydraulics

Pressure Drop Equations for non-Newtonian Fluids
A. Power-Law Fluid
The model equation for Power Law is:
n
n
K
n
K
γ
τ
γ
γ
τ
τ
γτ
=
=
=
1
2
1
2
log
log
For pipe Flow
Apparent Viscosity, µa
n
n
n
a
n
v
Kd







 +
= −
−
0416.0
13
96 )1(
)1(
µ
Reynolds Number
Re =
( )
n
n
n
d
K
v








+
−
13
0416.089100 2
ρ
Pressure Drop Equation
FlowTurbulentFor-
8.25
vLf
p
FlowLaminarFor-
144000
0416.0
1
3
2
1
d
d
nLKv
p n
n
n
ρ
=∆












+
=∆ +
Annular Flow

Apparent Viscosity
( )
( )
n
n
n
a
n
v
ddK







 +−
= −
−
0208.0
12
144 1
1
12
µ
Reynolds Number
Re =
( )
( )
n
n
n
dd
K
v








+
−−
12
0208.0000,109 12
2
ρ
Pressure Drop Equations
( )
( )
FlowTurbulent-
1.21
vLf
p
FlowLaminar-
144000
0208.0
1
2
12
2
1
12
dd
dd
nLKv
p n
n
n
−
=∆
−












+
=∆ +
ρ
B. Herschel-Bulkley Fluids
( )
n
n
K
γ
ττ
γττ 0
0
-
K =+=
Approximately possible to use same power law equations.
C. Bingham Plastic Fluids
γµττ py +=
Pipe Flow Equations
Apparent Viscosity
c
y
pa
v
dτ
µµ
66.6
+=

Reynolds Number
Re =
µ
ρvd928
FlowTurbulent-
8.25
vfL
p
FlowLaminar-
2251500
2
2
d
d
L
d
vL
p
yp
ρ
τµ
=∆
+=∆
Annular Flow
Apparent Viscosity
( )
v
ddy
pa
125 −
+=
τ
µµ
Reynolds Number
Re =
a
vd
µ
ρ928
( )
( )
FlowTurbulent-
1.21
vfL
p
FlowLaminar-
200)(1000
12
2
12
2
22
dd
dd
L
dd
vL
p
yp
−
=∆
−
+
−
=∆
ρ
τµ
Fo all cases, the flow equations are:
A. pipe flow
q=2.45*d2
*v
B. Annular Flow
( ) avddq **45.2 2
1
2
2 −=

PUMP HORSEPOWER REQUIREMENTS
Mechanical Efficiency,
Input
pq
Input
Output
m
∆
==η
Input HP Requirements =
m
pq
η1714
∆

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