1 introduction drillingfluids

Drilling Engineering – Fall 2012
Prepared by: Tan Nguyen
Drilling Engineering – PE 311
Chapter 2: Drilling Fluids
Introduction to Drilling Fluids

The principal functions of the drilling fluid are
1. Subsurface pressure control
2. Cuttings removal and transport
3. Suspension of solid particles
4. Sealing of permeable formations
5. Stabilizing the wellbore
6. Preventing formation damage
7. Cooling and lubricating the bit and drill string
8.Transmitting hydraulic horsepower to the bit
9.Facilitating the collection of formation data
10. Partial support of drill string and casing weights
11. Controlling corrosion
12. Assisting in cementing and completion
Principal Functions of Drilling Fluids

A column of drilling fluid exerts a hydrostatic pressure that, in field units, is equal to
P = 0.052 x ρ x TVD
where
P - hydrostatic pressure of fluid column in wellbore, psi;
ρ - mud weight in pounds per gallon (ppg)
TVD - True Vertical Depth, ft - during normal drilling operations, this corresponds to
the height of the fluid column in the wellbore.
Subsurface pressure control

Circulation of the drilling fluid causes cuttings to rise from the bottom of the hole to
the surface. Efficient cuttings removal requires circulating rates that are sufficient to
override the force of gravity acting upon the cuttings. Other factors affecting the
cuttings removal include drilling fluid density and rheology, annular velocity, hole
angle, and cuttings-slip velocity.
In most cases, the rig hydraulics program provides for an annular velocity sufficient
to result in a net upward movement of the cuttings. Annular velocity is determined by
the cross-sectional area of the annulus and the pump output.
Cuttings Removal and Transport

When the rig's mud pumps are shut down and circulation is halted (e.g., during
connections, trips or downtime), cuttings that have not been removed from the hole
must be held in suspension. Otherwise, they will fall to the bottom (or, in highly
deviated wells, to the low side) of the hole. The rate of fall of a particle through a
column of drilling fluid depends on the density of the particle and the fluid, the size of
the particle, the viscosity of the fluid, and the thixotropic (gel-strength) properties of
the fluid. The controlled gelling of the fluid prevents the solid particles from settling,
or at least reduces their rate of fall. High gel strengths also require higher pump
pressure to break circulation. In some cases, it may be necessary to circulate for
several hours before a trip in order to clean the hole of cuttings and to prevent fill in
the bottom of the hole from occurring during a round trip.
Suspension of Solid Particles

As the drill bit penetrates a permeable formation, the liquid portion of the drilling fluid
filters into the formation and the solids form a relatively impermeable "cake" on the
borehole wall. The quality of this filter cake governs the rate of filtrate loss to the
formation. Drilling fluid systems should be designed to deposit a thin, low
permeability filter cake on the formation to limit the invasion of mud filtrate. This
improves wellbore stability and prevents a number of drilling and production
problems. Potential problems related to thick filter cake and excessive filtration
include “tight” hole conditions, poor log quality, increased torque and drag, stuck
pipe, lost circulation and formation damage.
Bentonite is the best base material from which to build a tough, low-permeability
filter cake. Polymers are also used for this purpose.
Sealing of permeable formation

The borehole walls are normally competent immediately after the bit penetrates a
section. Wellbore stability is a complex balance of mechanical and chemical factors.
The chemical composition and mud properties must combine to provide a stable
wellbore until casing can be run and cemented. Regardless of the chemical
composition of the fluid and other factors, the weight of the mud must be within the
necessary range to balance the mechanical forces acting on the wellbore. The other
cause of borehole instability is a chemical reaction between the drilling fluid and the
formations drilled. In most cases, this instability is a result of water absorption by the
shale. Inhibitive fluids (calcium, sodium, potassium, and oil-base fluids) aid in
preventing formation swelling, but even more important is the placement of a quality
filter cake on the walls to keep fluid invasion to a minimum.
Stabilizing the Wellbore

Any reduction in a producing formation’s natural porosity or permeability is
considered to be formation damage. If a large volume of drilling-fluid filtrate invades
a formation, it may damage the formation and hinder hydrocarbon production.
There are several factors to consider when selecting a drilling fluid:
• Fluid compatibility with the producing reservoir
• Presence of hydratable or swelling formation clays
• Fractured formations
• The possible reduction of permeability by invasion of nonacid soluble materials
into the formation
Preventing Formation Damage

Friction at the bit, and between the drillstring and wellbore, generates a considerable
amount of heat. The circulating drilling fluid transports the heat away from these
frictional sites by absorbing it into the liquid phase of the fluid and carrying it away.
The laying down of a thin wall of "mud cake" on the wellbore aids in reducing torque
and drag. The amount of lubrication provided by a drilling fluid varies widely and
depends on the type and quantity of drill solids and weight material, and also on the
chemical composition of the system as expressed in terms of pH, salinity and
hardness. Indications of poor lubrication are high torque and drag, abnormal wear,
and heat checking of drillstring components.
Cooling and Lubricating the Bit

During circulation, the rate of fluid flow should be regulated so that the mud pumps
deliver the optimal amount of hydraulic energy to clean the hole ahead of the bit.
Hydraulic energy also provides power for mud motors to rotate the bit and for
Measurement While Drilling (MWD) and Logging While Drilling (LWD) tools.
Hydraulics programs are based on sizing the bit nozzles to maximize the hydraulic
horsepower or impact force imparted to the bottom of the well.
Transmitting Hydraulic Horsepower to the Bit

The drilling fluid program and formation evaluation program are closely related. As
drilling proceeds, for example, mud loggers monitor mud returns and drilled cuttings
for signs of oil and gas. They examine the cuttings for mineral composition,
paleontology and visual signs of hydrocarbons. This information is recorded on a
mud log that shows lithology, penetration rate, gas detection and oil-stained
cuttings, plus other important geological and drilling parameters. Measurement-
While-Drilling (MWD) and Logging-While-Drilling (LWD) procedures are likewise
influenced by the mud program, as is the selection of wireline logging tools for post-
drilling evaluation.
Facilitating the Collection of Formation Data

With average well depths increasing, the weight supported by the surface wellhead
equipment is becoming an increasingly crucial factor in drilling. Both drillpipe and
casing are buoyed by a force equal to the weight of the drilling fluid that they
displace. When the drilling fluid density is increased, the total weight supported by
the surface equipment is reduced considerably.
Partial support of Drill String and Casing Weights

The drilling fluid must produce a wellbore into which casing can be run and
cemented effectively, and which does not impede completion operations. During
casing runs, the mud must remain fluid and minimize pressure surges so that
fracture-induced lost circulation does not occur. The mud should have a thin, slick
filter cake. To cement casing properly, the mud must be completely displaced by the
spacers, flushes and cement. Effective mud displacement requires that the hole be
near-gauge and that the mud have low viscosity and low, non-progressive gel
strengths. Completion operations such as perforating and gravel packing also
require a near-gauge wellbore and may be affected by mud characteristics
Assistance in Cementing and Completion

Various materials may be added at the surface to change or modify the characteristics of the
mud. For example:
1.Weighting agents (usually barite) are added to increase the density of the mud, which helps to
control subsurface pressures and build the wallcake.
2.Viscosifying agents (clays, polymers, and emulsified liquids) are added to thicken the mud
and increase its hole-cleaning ability.
3.Dispersants or deflocculants may be added to thin the mud, which helps to reduce surge,
swab, and circulating-pressure problems.
Mud Ingredients

4. Clays, polymers, starches, dispersants, and asphaltic materials may be added to reduce
filtration of the mud through the borehole wall. This reduces formation damage, differential
sticking, and problems in log interpretation.
5. Salts are sometimes added to protect downhole formations or to protect the mud against
future contamination, as well as to increase density.
6. Other mud additives may include lubricants, corrosion inhibitors, chemicals that tie up
calcium ions, and flocculants to aid in the removal of cuttings at the surface.
7. Caustic soda is often added to increase the pH of the mud, which improves the
performance of dispersants and reduces corrosion.
8. Preservatives, bactericides, emulsifiers, and temperature extenders may all be added to
make other additives work better.
Mud Ingredients

A water-base fluid is one that uses water for the liquid phase and commercial clays
for viscosity. The continuous phase may be fresh water, brackish water, seawater,
or concentrated brines containing any soluble salt. The commercial clays used may
be bentonite, attapulgite, sepiolite, or polymer. The use of other components such
as thinners, filtration-control additives, lubricants, or inhibiting salts in formulating a
particular drilling fluid is determined by the type of system required to drill the
formations safely and economically. Some of the major systems include fresh-water
fluids, brackish or seawater fluids, saturated salt fluids, inhibited fluids, gyp fluids,
lime fluids, potassium fluids, polymer-based fluids, and brines used in drilling,
completion or workover operations (including single-salt, potassium chloride, sodium
chloride, calcium chloride, and two and three-salt brines).
Drilling Fluid Classifications
Water-Based Drilling Fluids

In many areas, diesels were used to formulate and maintain OBMs. Crude oils had
sometimes been used instead of diesel but posed tougher safety problems. Thus,
today, mineral oils and new synthetic fluids replace diesel and crude due to their
lower toxicity.
Advantages of OBMs:
1. Shale stability: OBMs are most suited for drilling water sensitive shales. The
whole mud results non reactive towards shales.
2. ROP: allowing to drill faster than WBMs, still providing excellent shale stability
3. High Temperature: can drill where bottom hole temperature exceeds WBMs
tolerances; can handle up to 550 0
F.
Oil-Based Drilling Fluids

4. Lubricity: OBMs has a thin filter cake and the friction between the pipe and the
wellbore is minimized, thus reducing the risk of differential sticking.
5. Low pore pressure formation: Mud weight of OBMs can be maintained less than
that of water (as low as 7.5 PPG)
6. Corrosion control: corrosion of pipe is controlled Since oil is the external phase.
7. Re-use: OBMs are well-suited to be used over and over again. They can be
stored for long periods of time since bacterial growth is suppressed.

An oil-base drilling fluid is one in which the continuous phase is oil. The terms oil-
base mud and inverted or invert-emulsion mud sometimes are used to distinguish
among the different types of oil-base drilling fluids. Traditionally, an oil-base mud is
a fluid with 0 to 5% by volume of water, while an invert-emulsion mud contains more
than 5% by volume of water. However, since most oil muds contain some emulsified
water, have oil as the liquid phase, and (if properly formulated) have an oil filtrate,
we do not distinguish among them in this discussion. Synthetic muds may include
esters, olefins, and paraffin.

Air drilling is used primarily in hard-rock areas, and in special cases to prevent
formation damage while drilling into production zones or to circumvent severe lost-
circulation problems. Air drilling includes dry air drilling, mist or foam drilling, and
aerated-mud drilling. In dry air drilling, dry air or gas is injected into the standpipe at
a volume and rate sufficient to achieve the annular velocities needed to clean the
hole of cuttings. Mist drilling is used when water or oil sands are encountered that
produce more fluid than can be dried up using dry air drilling. A mixture of foaming
agent and water is injected into the air stream, producing a foam that separates the
cuttings and helps remove fluid from the hole. In aerated mud drilling, both mud and
air are pumped into the standpipe at the same time. Aerated muds are used when it
is impossible to drill with air alone because of water sands and/or lost-circulation
situations.
Pneumatic Fluids (Air, Gas, Mist, Foams, Gasified Muds)

Pneumatic Fluids (Air, Gas, Mist, Foams, Gasified Muds)

The physical properties of a drilling fluid, particularly its density and rheological
properties, are monitored to assist in optimizing the drilling process. These physical
properties contribute to several important aspects of successful drilling, including:
• Providing pressure control to prevent an influx of formation fluid
• Providing energy at the bit to maximize Rate of Penetration (ROP)
• Providing wellbore stability through pressured or mechanically stressed zones
• Suspending cuttings and weight material during static periods
• Permitting separation of drilled solids and gas at surface
• Removing cuttings from the well
Drilling Fluid Properties

The concepts of shear rate and shear stress apply to all fluid flow, and can be
describe in term of two fluid layers (A and B) moving past each other when a force
(F) has been applied.
Viscosity

When a fluid is flowing, a force exists in the fluid that opposes the flow. This force is
known as the shear stress. It can be thought of as a frictional force that arises
when one layer of fluid slides by another. Since it is easier for shear to occur
between layers of fluid than between the outer most layer of fluid and the wall of a
pipe, the fluid in contact with the wall does not flow. The rate at which one layer is
moving past the next layer is the shear rate. The shear rate is therefore a velocity
gradient. The formula for the shear rate is
Viscosity

In the most general sense, viscosity describes a substance’s resistance to flow.
Hence a high-viscosity drilling mud may be characterized as "thick," while a low-
viscosity mud may be described as "thin."
Viscosity (µ), by definition, is the ratio of shear stress (τ) to shear rate (γ):
Unit: PaS, NS/m2
, kg/ms, cp, dyneS/cm2
, lbfS/100ft2
Viscosity

The simplest class of fluids is called Newtonian. The base fluids (freshwater,
seawater, diesel oil, mineral oils and synthetics) of most drilling fluids are
Newtonian. In these fluids, the shear stress is directly proportional to the shear rate.
The points lie on a straight line passing through the origin (0,0) of the graph on
rectangular coordinates. The viscosity of a Newtonian fluid is the slope of this shear
stress/shear rate line. The yield stress (stress required to initiate flow) of a
Newtonian fluid will always be zero. When the shear rate is doubled, the shear
stress is also doubled. When the circulation rate for this fluid is doubled, the
pressure required to pump the fluid will be squared (e.g. 2 times the circulation rate
requires 4 times the pressure).
Fluid Types
Newtonian Fluids

The shear stress at various shear rates
must be measured in order to
characterize the flow properties of a
fluid. Only one measurement is
necessary since the shear stress is
directly proportional to the shear rate
for a Newtonian fluid. From this
measurement the shear stress at any
other shear rate can be calculated from
the equation:
Fluid Types
Newtonian Fluids

When a fluid contains clays or colloidal particles, these particles tend to “bump” into
one another, increasing the shear stress or force necessary to maintain a given flow
rate. If these particles are long compared to their thickness, the particle interference
will be large when they are randomly oriented in the flow stream. However, as the
shear rate is increased, the particles will “line up” in the flow stream and the effect of
particle interaction is decreased. This causes the velocity profile in a pipe to be
different from that of water. In the center of the pipe, where the shear rate is low, the
particle interference is high and the fluid tends to flow more like a solid mass. The
velocity profile is flattened. This flattening of the velocity profile increases the sweep
efficiency of a fluid in displacing another fluid and also increases the ability of a fluid
to carry larger particles.
Fluid Types
Non-Newtonian Fluids

A rheological model is a description of the relationship between the shear stress
and shear rate. Newton’s law of viscosity is the rheological model describing the
flow behavior of Newtonian fluids. It is also called the Newtonian model. However,
since most drilling fluids are non-Newtonian fluids, this model does not describe
their flow behavior. In fact, since no single rheological model can precisely describe
the flow characteristics of all drilling fluids, many models have been developed to
describe the flow behavior of non-Newtonian fluids. Bingham Plastic, Power Law
and Modified Power Law models are discussed. The use of these models requires
measurements of shear stress at two or more shear rates. From these
measurements, the shear stress at any other shear rate can be calculated.
Fluid Types
Non-Newtonian Fluids

Fluid Types
Rotational Viscometer

The Bingham Plastic model has been used most often to describe the flow
characteristics of drilling fluids. It is one of the older rheological models currently in
use. This model describes a fluid in which a finite force is required to initiate flow
(yield point) and which then exhibits a constant viscosity with increasing shear rate
(plastic viscosity).
Fluid Types
Bingham Plastic Fluids

The two-speed viscometer was designed to measure the Bingham Plastic
rheological values for yield point and plastic viscosity. A flow curve for a typical
drilling fluid taken on the two-speed Fann VG meter is illustrated in Figure below.
The slope of the straight line portion of this consistency curve is plastic viscosity.
Fluid Types

Most drilling fluids are not true Bingham Plastic fluids. For the typical mud, if a
consistency curve for a drilling fluid is made with rotational viscometer data, a non-
linear curve is formed that does not pass through the origin, as shown in Flow
diagram of Newtonian and typical mud. The development of gel strengths causes
the y-intercept to occur at a point above the origin due to the minimum force
required to break gels and start flow. Plug flow, a condition wherein a gelled fluid
flows as a “plug” with a flat viscosity profile, is initiated as this force is increased. As
the shear rate increases, there is a transition from plug to viscous flow. In the
viscous flow region, equal increments of shear rate will produce equal increments of
shear stress, and the system assumes the flow pattern of a Newtonian fluid.
Fluid Types

Fluid Types

The Power Law model attempts to solve the shortcomings of the Bingham Plastic
model at low shear rates. The Power Law model is more complicated than the
Bingham Plastic model in that it does not assume a linear relationship between
shear stress and shear rate. However, like Newtonian fluids, the plots of shear
stress vs. shear rate for Power Law fluids go through the origin.
Fluid Types
Power Law Model

This model describes a fluid in which the shear stress increases as a function of the
shear rate mathematically raised to some power. Mathematically, the Power Law
model is expressed as
τ = Kγn
Where:
τ = Shear stress
K = Consistency index
γ = Shear rate
n = Power Law index
Fluid Types
Power Law Model

Plotted on a log-log graph, a Power Law fluid shear stress/shear rate relationship
forms a straight line in the log-log plot. The “slope” of this line is “n” and “K’ is the
intercept of this line. The Power Law index “n” indicates a fluid’s degree of non-
Newtonian behavior over a given shear rate range.
Fluid Types
Power Law Model

n = Power Law index or exponent
K = Power Law consistency index or fluid index (dyne sec–n/cm2)
θ1 = Mud viscometer reading at lower shear rate
θ2 = Mud viscometer reading at higher shear rate
ω1 = Mud viscometer RPM at lower shear rate
ω2 = Mud viscometer RPM at higher shear rate
Fluid Types
Power Law Model

A rotational viscometer containing a non-Newtonaian fluid gives a dial reading of 12
at a rotor speed of 300 rpm and a dial reading of 20 at a rotor speed of 600 rpm.
Determine the rheological model of this fluid in two cases: Bingham model and
Power Law model
Fluid Types
Example

A rotational viscometer containing a non-Newtonaian fluid gives a dial reading of 12
at a rotor speed of 300 rpm and a dial reading of 20 at a rotor speed of 600 rpm.
Determine the rheological model of this fluid in two cases: Bingham model and
Power Law model:
Bingham model:
Power Law model:
Fluid Types
Example

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