Drilling Engineering – PE 311

1

• Drilling Engineering PE 311
• Chapter 2 Drilling Fluids
• Introduction to Drilling Fluids

2
Principal Functions of 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
• Transmitting hydraulic horsepower to the bit
• Facilitating the collection of formation data
• 10. Partial support of drill string and casing
  weights
• 11. Controlling corrosion
• 12. Assisting in cementing and completion

3
Principal Functions of Drilling Fluids
Subsurface pressure control

• A column of drilling fluid exerts a hydrostatic
  pressure that, in field units, is equal to
• P 0.052 x r x TVD        
• where
• P - hydrostatic pressure of fluid column in
  wellbore, psi
• r - 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.

4
Principal Functions of Drilling Fluids
Cuttings Removal and Transport

• 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.
•  

5
Principal Functions of Drilling Fluids
Suspension of Solid Particles

• 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.

6
Principal Functions of Drilling Fluids
Sealing of permeable formation

• 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.

7
Principal Functions of Drilling Fluids
Stabilizing the Wellbore

• 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.

8
Principal Functions of Drilling Fluids
Preventing Formation Damage

• Any reduction in a producing formations 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

9
Principal Functions of Drilling Fluids
Cooling and Lubricating the Bit

• 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.

10
Principal Functions of Drilling Fluids
Transmitting Hydraulic Horsepower to 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.

11
Principal Functions of Drilling Fluids
Facilitating the Collection of Formation Data

• 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.

12
Principal Functions of Drilling Fluids
Partial support of Drill String and Casing Weights

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

13
Principal Functions of Drilling Fluids
Assistance in Cementing and Completion

• 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

14
Mud Ingredients

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

15
Mud Ingredients

• 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.
• Salts are sometimes added to protect downhole
  formations or to protect the mud against future
  contamination, as well as to increase density.
• 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.
• Caustic soda is often added to increase the pH of
  the mud, which improves the performance of
  dispersants and reduces corrosion.
• Preservatives, bactericides, emulsifiers, and
  temperature extenders may all be added to make
  other additives work better.

16
Drilling Fluid Classifications
Water-Based Drilling Fluids

• 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).

17
Drilling Fluid Classifications
Oil-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 0F.

18
Drilling Fluid Classifications
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.

19
Drilling Fluid Classifications
Oil-Based Drilling Fluids

• 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.

20
Drilling Fluid Classifications
Pneumatic Fluids (Air, Gas, Mist, Foams, Gasified
Muds)

• 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.

21
Drilling Fluid Classifications
Pneumatic Fluids (Air, Gas, Mist, Foams, Gasified
Muds)
22
Drilling Fluid Properties

• 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

23
Drilling Fluid Properties
Viscosity

• 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.

24
Drilling Fluid Properties
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

25
Drilling Fluid Properties
Viscosity

• In the most general sense, viscosity describes a
  substances 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 (m), by definition, is the ratio of
  shear stress (t) to shear rate (g)
• Unit PaS, NS/m2, kg/ms, cp, dyneS/cm2,
  lbfS/100ft2

26
Fluid Types
Newtonian Fluids

• 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).

27
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

28
Fluid Types
Non-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.

29
Fluid Types
Non-Newtonian Fluids

• A rheological model is a description of the
  relationship between the shear stress and shear
  rate. Newtons 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.

30
Fluid Types
Rotational Viscometer
31
Fluid Types
Bingham Plastic Fluids

• 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).

32
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.

33
Fluid Types
Bingham Plastic Fluids

• 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.

34
Fluid Types
Bingham Plastic Fluids
35
Fluid Types
Power Law Model

• 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.

36
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
• t Kgn     
• Where
• t   Shear stress
• K   Consistency index
• g   Shear rate
• n   Power Law index

37
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 fluids
  degree of non-Newtonian behavior over a given
  shear rate range.

38
Fluid Types
Power Law Model

• n   Power Law index or exponent
• K   Power Law consistency index or fluid index
  (dyne secn/cm2)
• q1   Mud viscometer reading at lower shear rate
• q2   Mud viscometer reading at higher shear rate
• w1   Mud viscometer RPM at lower shear rate
• w2   Mud viscometer RPM at higher shear rate

39
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

40
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