drlg266 mod04 reading

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Drilling Fluids

DRLG 266Module 4

Fundamentals of Drilling

MacPhail School of Energy

Course Module

Revised: September 2014

www.sait.ca


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Introduction to Drilling Fluids

Rationale

Why is it important for you to learn this material?

Drilling fluid, commonly known as drilling mud or simply “mud,” is an essential

part of rotary drilling. Drilling fluid is circulated down the drill pipe and up the

annulus of every well drilled. This fluid may be gaseous or liquid or a mixture of

both and the liquid phase may be water or oil. The selection of drilling fluid type

and the properties required of this fluid will determine how efficiently the well is

drilled. The correct type of drilling fluid for the formation to be drilled is a

fundamental decision for the drilling planner to make. The correct drilling fluid

must coat the wellbore with a filter cake that seals off porous zones, helps

prevent collapse of the wellbore, minimizes lost circulation and aids in theprotection against formation fluid contamination. The drilling fluid (mud) must also

be chemically compatible with the formation and formation fluids.

A strong understanding of the various types of drilling fluids is an essential

component in the drilling of a well. The cost of the drilling fluid in any well is a

relatively small portion and yet the proper selection and design of the drilling

fluids system is the single most important factor in the drilling of an effective and

safe well. If the fluid is unsuitable, it is possible that the well will take much longer

to drill, cost up to twice the amount expected and, potentially, produce much less

than it would otherwise be capable of.

Drilling fluids have differing characteristics that determine their effectiveness inmeeting their functions. Since the majority of wells use a water-based fluid and

clays, this understanding will require a basic knowledge of clay mineralogy.

Understanding this and applying it to the required functions of the fluid being

used will allow drilling personnel to optimize the performance of the fluid, the

drilling rig equipment and optimize the drilling of the well.

Learning Outcome

When you complete this module, you will be able to:

Prescribe mud treatments to maintain mud weight, properties and chemistrywithin recommended limits.

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Learning Objectives

Here is what you wil l be able to do when you complete each objective:

1. Describe the functions of a drilling fluid.

2. Differentiate drilling fluids according to their continuous phase.3. Describe how clay chemistry affects drilling fluid properties.

4. Explain the different drilling fluid additives and chemicals and their typicalapplications.

5. Describe drilling fluid contaminants and their effects and how to mitigatethese affects.

6. Describe the physical properties of mud.

7. Describe the chemical properties of mud.

8. Test drilling fluid properties using API testing procedures.1.

Performance Evaluation

To show you have mastered the material, you will be asked to:

1. You will be tested on this material in Quiz #2 on modules 4-6: drilling fluids,

drilling fluid applications and drilling fluid programming.

2. You will need to complete the water-based mud (WBM) lab and submit a

report.

Introduction

Every well you drill uses a drilling fluid of some kind. This fluid is pumped through

the standpipe, the kelly hose, the swivel and kelly (if you are drilling without a top

drive), down the drill pipe and collars, through the bit and up the annulus back to

surface. Different fluids are used to solve specific hole related problems, to meet

identified geological and client requirements, to assist in drilling the well in the

most cost effective manner and to ensure the well you drill has the maximum

productivity.

Successful drilling operations depend on the optimum selection and performance

of the drilling fluid. To fully understand how you can select the best fluid you mustunderstand what you expect the fluid to do. To get the optimum performance

from your drilling fluids, you must understand the effect of the different fluids and

the interrelationships between the fluid properties. You must also realize that

drilling fluids represent a relatively small portion of the overall well costs (usually

8 – 12%) but that poor selection and performance may change the overall well

costs by a much higher amount – up to 50%.

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Industry uses a wide range of drilling fluids to solve specific problems. These

fluids range from air to water to water with a complex mixture of chemicals and

additives to oils and oil/water mixtures or emulsions. While the fluids may be

quite different in their composition and their rheological properties, they perform a

series of basic functions that are common to all mud systems.

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OBJECTIVE ONEWhen you complete this ob jective, you will be able to:

Describe the functions of a drilling fluid.

Learning Activities

Complete each of the following learning activities:

1. Read the Learning Material.

2. Complete Exercise One.

Learning Material

Drilling Fluid Functions

Drilling fluids have a wide range of functions. The nine most important are:

1. Clean cuttings from under the bit.

2. Control subsurface pressures.

3. Cool and lubricate the rotating bit and the drill string.

4. Transport cuttings up the borehole.

5. Suspend cuttings and weighting materials in the annulus whenever

circulation is stopped.

6. Assist in providing borehole stability by lining the borehole wall with a low

permeability filter cake.7. Release cuttings at surface without losing other beneficial materials.

8. Support part of the drill string and casing weight.

9. Minimize damage to the reservoir and its productivity.

[Adapted from Mitchell and Miska, pg. 89]

Some of these functions are vastly more important than others and not all of

these functions are of concern or apply all the time for every mud system.

Despite this, optimum drilling practice requires optimum performance from the

fluids.

The two most important functions of the drilling fluid are:


2. To control subsurface pressures.

If you do not clean out the cuttings from under the bit it will be necessary to redrill

the same cuttings numerous times and this will dramatically affect your rate of

penetration (ROP) and the overall costs of the well. If you do not control the

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subsurface pressure and allow oil and gas to flow into the wellbore (a kick) you

risk a blowout.

Each of the functions is discussed in detail below.


If cuttings are allowed to accumulate under the bit for any length of time, the bit

will have to re-drill them. This will reduce the size of the cuttings, making them

more difficult to remove from the fluids at surface. It will also severely curtail the

rate of penetration, increasing the overall well costs.

The major factor in removing the cuttings from under the bit is the hydraulic

horsepower carried by the fluid. This is seen under the bit as impingement

velocity, and this velocity is controlled by the physical properties of the system –

the surface pump pressure, the volume being pumped and the sizes of the

nozzles.

2. Control subsurface pressures.

For the well to be drilled safely, the drilling fluid must control any subsurface

pressure that is expected during the drilling process. The column of mud in the

annulus of the well exerts a pressure on the formation called the hydrostatic

pressure.

This hydrostatic pressure at any depth may be calculated by:

= ℎ

Where:

p is hydrostatic pressure [Pa]

ρ is drilling fluid density [kg/m3]

g is gravitational force [9.81 m/s2]

h is height (true vertical depth) [m]

Hydrostatic pressure is normally stated in kPa.

In a deviated or horizontal well, the height is the true vertical depth of the well

and not the total measured depth.

The hydrostatic pressure should be slightly higher than the formation pressure.

The amount by which it is higher is called the trip margin. Both are normally

specified in the drilling program developed for each specific well. If the

hydrostatic pressure is not higher than the formation pressure, any formation

liquids (or gas) will be allowed to flow into the wellbore (a kick) and will make

control of the well more diff icult.

Anything that changes either the density of the fluid or the height of the column of

drilling fluid will change the hydrostatic pressure. For example, the hole must be5


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kept full while tripping or the height of the fluid column will be reduced as the pipe

is pulled from the hole. This is more prevalent when the fluid has a high viscosity

and gel strength as it sticks more readily to the pipe. Additionally, fluids with

these same characteristics are more readily swabbed if the pipe is pulled too

quickly or if the bottom hole assembly is close to hole diameter. This will also

reduce the length of the fluid column. Conversely, running in too quickly under

the same conditions can cause a pressure surge, which can readily fracture the

formation and result in lost circulation, as well as a corresponding reduction in

the height of the fluid column.

3. Cool and lubricate the rotating bit and the dril l string.

The drilling process is essentially one of grinding up the formation. This process

generates a great amount of heat due to friction as the bit crushes the rock.

Additionally, continuous contact of the drill pipe and collars as the string is

rotated will generate more frictional heat. The drilling fluid cools the bit bytransferring the heat from the bit and the drill string to the fluid. The circulation of

drilling fluid helps carry the heat to surface, where it can be dissipated. The

drilling fluid also has lubricating qualities, forming a slick wall filter cake that helps

to reduce the friction, thereby lowering the amount of heat generated. To

increase the lubricating effect, special chemicals may also be added to the fluid.

Cooling of the bit is extremely important when thermally stable diamond or PDC

bits are being used. These bits generate more heat than tricones due simply to

the manner in which they drill the formation. They are also susceptible to heat

damage, with PDCs actually burning at temperatures above 700°C.

4. Transport cuttings up the borehole.

The circulation of the drilling fluid must remove the drill cuttings from the bit and

carry them to the surface where they can be removed and disposed of.

All cuttings fall through the drilling fluid at some velocity called the slip velocity.

This slip velocity may be calculated using Stokes Law, and is a function of the

fluid and cuttings densities, the size of the cuttings and the fluid viscosity. This

slip velocity is independent of the fluid velocity and is normally in the range of 15-

18 m/min, relative to the fluid the cuttings are falling through. The efficiency of the

lifting of the cuttings depends on the fluid properties (density and viscosity) and

the annular velocity.

Changes in these properties will affect the lifting efficiency, but will also affect

other operating parameters. For example, increasing the fluid density will assist

in lifting the cuttings, but will reduce the rate of penetration – which is inversely

proportional to the fluid density. Increasing the annular velocity will also increase

the lifting efficiency, but is quite likely to lead to hole erosion and all the ongoing

problems associated with erose holes.

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The minimum value if the annular velocity needs to be related to the slip velocity

to ensure a net upward movement of the cuttings. It is normal practice in Western

Canada to set the annular velocity at approximately twice the slip velocity –

usually in the range of 30-36 m/min. Using this annular velocity and knowing the

hole geometry, it is possible to calculate the pump output rates required and the

speed at which the pump is to be run.

In order to efficiently carry the cuttings from the bit to surface, it is important to

realize that a balance is required between the annular velocity of the drilling fluid

and the fluid properties – specifically the viscosity and density. A high velocity,

thin fluid will give the best lifting, but will lead to severe hole problems and

increased fuel costs for the pumps. Increasing the viscosity will reduce the lifting

efficiency, and improve the carrying capacity of the fluid – but also increase

pump wear while reducing fuel costs as the pump rates are decreased. In

addition, density provides buoyancy, but reduces the rate of penetration. Annular

velocities are normally defined as part of the drilling program leaving the drilling

supervisor to optimize fluid properties as conditions dictate.

5. Suspend cuttings and weighting materials in the annulus

whenever circulation is stopped.

The properties of the drilling fluid must be maintained such that any drill cuttings

not circulated out of the hole prior to trips or connections will remain suspended

in the fluid. If the cuttings are able to settle back down the wellbore due to poor

fluid suspension ability, they will accumulate on bottom and have to be re-drilled

before a new hole can be made and there is always the possibility they will pack

off around the bit and BHA with the further possibility of sticking the drill string.The gel strength is the fluid property that is most important in holding the cuttings

in suspension. It is important that the gel strength be controlled so that it stays

reasonably constant and does not build excessively while the fluid sits quiescent.

High strengths require high pump pressures to initiate circulation and are

expensive in terms of fuel and pump repairs.

6. Assist in providing borehole stability by lin ing the borehole wall

with a low permeability fi lter cake.

The hydrostatic pressure of the drilling fluid pushing against the sides of the

wellbore assists in maintaining wellbore integrity. It has also been demonstrated

that the higher the fluid density (and the higher the hydrostatic pressure), the less

sloughing occurs. Several oil companies use this to reduce the amount of

sloughing shale when tectonically active shales are encountered. It will work,

provided the operator is prepared to accept the lower rates of penetration that

result from the higher mud densities.

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If a permeable formation is drilled, the liquid phase of the drilling fluid will leak or

seep into the permeability leaving behind the solids portion of the fluids on the

wall of the hole. This filter cake will coat the wellbore walls and help to stabilize

any mechanically unstable formations. The filter cake will also help to minimize

further passage of the liquid phase (fluid loss) to the formation which will reduce

the effects on any water sensitive zone(s). There are also special chemicals and

additives available to assist in the formation of the filter cake.

The filter cake which builds up needs to be firm, thin, tough and slick so that it is

not mechanically displaced; so that it reduces the friction of the drill string while

drilling; and to ensure it does not appreciably reduce the hole diameter behind

the bit and potentially cause sticking.

7. Release cuttings at surface without los ing other beneficial

materials.

Once the cuttings reach surface, they need to be removed from the drilling fluidas quickly as possible. In most cases, this is an exact opposite requirement to

that of the fluid to keep the solids in suspension. Almost all rigs choose to thin

stream the fluids over an inclined stream, to try and mechanically affect this

surface separation, and to try and remove the smaller particles using high

volume centrifuges.

If the cuttings are not released at surface, they stay in the fluid and are

recirculated down the well. If the drilled solids remain in the fluid, the softer

particles like shale are eventually ground up even smaller (making them harder

yet to remove), and the hard materials such as sand become an abrasive that

cause excess wear and premature failure of the pump parts.

As drill solids continue to build in the drilling mud, they increase the density of the

fluid, reducing the rate of penetration and increasing the cost. A higher solids

content will also increase the viscosity of the drilling fluid and increase the costs

to pump the fluid.

8. Support part of the drill st ring and casing weight.

As the well is drilled deeper, more and more drill pipe is used, which results in a

much heavier drill string. This is also true of long, large, high weight casing

strings. All of the weight must be supported by the upper joints of pipe and by thesurface equipment – the derrick and the substructure. The buoyant effect of the

mud provides support for a portion of this weight and is taken into account when

running very long strings. The buoyancy is essentially the weight (amount) of

mud displaced by the pipe. The higher the fluid density, the more buoyancy is

available, but the lower the rate of penetration becomes.

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9. Minimize damage to the reservoir and its productivity.

The main reason for drilling wells is to produce oil or gas from a specific

formation. The amount of oil and gas produced is determined by the thickness of

the formation, the fluid saturations, the rock permeability and the formation

pressure. The formation is drilled through using a drilling fluid expected to build afilter cake and restrict the amounts of whole mud and filtrate that will invade the

formation. Invasion of either will probably result in some degree of permeability

reduction (damage) in the immediate vicinity of the wellbore. This damage may

be either:

• Blockage of the permeability (pore throats) by the mud solids• Hydration and swelling of the clays in the formation which are contacted

by the drilling fluid filtrate

Maintaining the hydrostatic pressure just above the reservoir pressure and

building a drilling fluid with a good filter cake and a low fluid loss, the amount of

invasion that occurs can be minimized.

The use of non-water-based fluids can also prevent some types of formation

damage, but these fluids are extremely expensive and often environmentally

sensitive. Inhibited water-based fluids may also be used to prevent clay hydration

through the use of potassium salts, calcium salts and anionic polymers. It is

important to note that the Western Canada Sedimentary Basin is a mature basin,

and that more and more of the reservoirs drilled in are in “dirty” formations –

formations with clays present that are easily damaged.

The use of inhibited water systems should reduce (or minimize) the degree of

damage, but may lead to other difficulties in interpreting the logs run on the well.It is always advisable to check with the geologist or log interpreter prior to using

these types of fluids.

Exercise One

1. What drilling fluid functions are directly related to the density of the fluid?

2. Which functions of a drilling fluid are the most important? Explain why.

3. Explain how hydrostatic pressure is calculated?

4. Why is it important that the drilling fluids circulated down the well release the

drill cuttings at surface?

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OBJECTIVE TWOWhen you complete this ob jective, you will be able to:

Differentiate drilling fluids according to their continuous phase.

Learning Activities


1. Read the learning material.

2. Complete Exercise Two.

Learning Material

Drilling Fluid Components

Drilling fluids are made up of two basic components:

1. The continuous phase of the drilling fluid.

The continuous phase of a drilling fluid is the base fluid that is used to make up

the system. The continuous phase may have chemicals dissolved within it, which

then become part of the continuous phase. The continuous phase will suspend

any materials that make up the discontinuous phase.

2. The discontinuous phase of the drill ing flu id.

The discontinuous phase is that portion of the drilling fluid held in

suspension/emulsion by the continuous phase.

The discontinuous phase will contain any solid or undissolvable liquids that are

added to the system to alter the properties imparted by the base fluid. These

intentionally added materials are known as additives.

The discontinuous phase will also contain any solids that are picked up from the

formations being drilled through. This material is considered to be contaminants,

the primary one being the drill cuttings created by the drilling process.

There are two basic drilling fluid systems in use in Western Canada: water-based

muds (WBM) and oil-based muds (OBM) – which are, in the majority of cases, aninvert emulsion.

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Water-Based Muds

In WBMs, the continuous phase is water. In Western Canada, this water is

predominantly fresh water; in other parts of the world, salt water is used (usually

sea water with 30,000-35,000 ppm sodium chloride).

There are several common additives used in water based systems. The primaryadditive is clay. This clay is a high grade of bentonite, which is primarily sodium

montmorillonite. The other common additive is barite (barium sulphate), which

has a specific gravity of 4.65 and is used to increase the fluid density. Other

additives are also used to alter specific characteristics.

There are also several common chemicals added to and dissolved in the water.

The most common is caustic soda (NaOH), which is used to control the pH.

Again, there is a wide range of chemicals also added to control specific

properties.

Oil-Based MudsThe only oil-based fluid used in Western Canada is an invert emulsion where oil

is the continuous phase. Because of availability, cost and a specific composition

(making property control much easier), in most fluids, this oil is diesel fuel. In an

invert the discontinuous phase is primarily water with salt (a chemical) dissolved

in it. The discontinuous phase may also include barite in both phases.

Clays are generally not used in inverts and the primary additive is barite (non-

weighted inverts have a density of 850-900 kg/m3) used to raise the density and

ensure well control. Chemicals are always used and the primary chemicals are

the emulsifiers, which sit in the interface between the diesel and water,

maintaining the stability of the emulsion.

Drilling Fluids Types

There are five basic types of drilling fluid in use around the world. They are:

1. Gases or pneumatic fluids

2. Water and water-based fluids

3. Oil and oil-based fluids

4. Synthetic fluids5. Combinations of the above

Each of these fluids has a specific use and is used to meet specific well

requirements. And of course some are more common than others in given areas.

Furthermore, within each type of fluid there are varieties – usually resulting from

the additives and chemicals deliberately added to them to give them specific

properties. Each is discussed below.

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Gaseous Fluids

In gaseous drilling fluids, the continuous phase is a gas. A variety of gases have

been used (air, methane, CO2 and N2), but for safety and cost reasons, the

primary gases used are air (for top hole) and nitrogen for deeper zones, which

may contain hydrocarbons. Methane (natural gas) has also been used wherehydrocarbons are expected and the well is being drilled very close to a high

pressure source of natural gas – usually a pipeline. Methane use is becoming

rare especially given the fire risk on surface.

When the carrying capacity of the gas alone is not sufficient to lift the liquids and

clean the hole, a foaming agent will be added to the gas stream. The primary

foaming agent is soap and this creates bubbles, which hold the liquid around the

outside by surface tension. This can increase the fluid carrying capacity of the

system and gives the added benefit of increasing the system’s tolerance to down

hole liquids. Note that the increase in the lifting capacity with foams is somewhat

limited.

Water-Based Fluids

Water-based drilling fluids are fluids where the continuous phase is fresh water.

Approximately 85% of all meterage drilled uses water-based fluids and the water

may have material dissolved within it or may contain undissolved material (known

as the discontinuous phase).

Water-based systems are sub-classified according to the salt content of the

continuous phase.

• Fresh water systems have a chloride content of less than 5,000 ppm.

• Brine systems have a chloride content of between 5,000 and 50,000 ppm.

• Sea water systems are a subset of brine systems where the make-up

water is drawn from the ocean/sea, the chloride content will be between

25,000 and 50,000 ppm, depending on the native content of the source

ocean/sea.

• Salt saturated systems have a chloride content of between 100,000 ppm

(near saturated) and 200,000 ppm (super saturated).

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Source: SAIT Polytechnic

Figure 1: Water-Based Systems

Water alone is a very poor drilling fluid. It has a very low viscosity and no fluid

loss control. In Western Canada it has limited use, and the majority of the water-

based systems will have materials added to them to change and control the fluid

properties – primarily to increase the viscosity and density, and to lower fluid

loss.

Water-based drilling fluid systems are the most commonly used systems as theyare relatively simple, have easier rheological control and can be adapted to most

situations through the addition of the appropriate additives/chemicals: they are

also very cost efficient especially if care is taken to prevent Cl- contamination.

Fresh Water/Drilled Solids-Water

The simplest, most primitive drilling fluid consists of fresh water from the nearest

source. While an attempt is made to remove the drill solids and cuttings at

surface, these systems quickly become contaminated with the drill cuttings (clays

and other solids).

In Western Canada, these fluids tend to develop a very thick filter cakecomprised of the surface clays they drill. If the cake becomes so thick as to

restrict drilling, the cake is called a mud ring. These mud rings are dispersed

back into the fluid using a thinner (a chemical) called sodium acid pyrophosphate

(SAPP). If unconsolidated sands, gravels or boulders are encountered, it will

usually be necessary to build viscosity using bentonite.

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The current application in Western Canada of this mud system is in the drilling of

surface holes. Despite the drawbacks of the fluid it does have two significant

advantages in surface hole drilling:

• The fluid is non-polluting and is unlikely to damage local farmers water

supplies.

• The fluid is inexpensive.

Bentonite - Water

The bentonite systems are a great improvement over fresh water systems for

handling drilling conditions. When high grade bentonite (sodium montmorillonite)

is added to fresh water, it hydrates and disperses (see the section on clay

mineralogy for details). This provides a non-Newtonian fluid with a controllable

viscosity, which tends to gel when stationary and suspend cuttings and weight

material.

Non-Newtonian fluids thicken at low annular shear rates to transport cuttings, but

thin out at the high bit shear rates to allow fast penetration rates. This fluid forms

a thin, low permeability filter cake to reduce filtrate loss and sticking.

The gel-water mud may on occasion be used as a low priced drilling fluid, but its

predominant use is a base mud, the properties of which can be modified by

additions of inorganic and organic compounds. A typical base, gel-chem mud, is

made up of fresh water that is less than 5,000 ppm chlorides and less than 100

ppm calcium and magnesium. The pH is usually 9.5-11 and it contains 40 to 60

kg/m3 of bentonite.

Gel-Chem

Gel-chem systems are bentonite-water systems that contain thinners and/or fluid

loss additives in addition to the gel. They can be either weighted or unweighted

systems. In unweighted systems, the additives are used to reduce fluid loss and

to maintain the desired rheology. The density will normally be kept below 1050

kg/m3.

In weighted systems, a weighting agent (density increaser) will have to be added

to control of down hole pressures. These systems will have thinners added to

maintain rheological control within the range required (known as dispersed

systems) to ensure that the system effectively performs the functions of a good

drilling fluid. Dispersed systems are the most common gel-chem systems as theyhave very good carrying capacity and suspension ability.

Gel-Polymer

This type of mud system is a rather broad classification, which includes

bentonite-water-based muds with one or two polymers added to obtain specific

properties. The polymers are added to non-dispersed mud systems as an

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extender to increase viscosity or shale stabilization, while at the same time

generally decreasing the filtration rate. A big advantage of the polymers is their

effectiveness in controlling independent properties of the mud with small

additions. Their main drawback is their high cost and the fact that they are

organic, requiring the use of biocides.

A typical gel-polymer combination would be a gel-polysaccharide system. Fluid

loss can quickly be reduced by additions of specialized polymers, starches or

carboxymethylcellulose (CMC).

Another typical gel-polymer combination would be a gel-polyanionic cellulose

system. This versatile mud provides good rheology and fluid loss properties.

These gel-polymer systems have good general properties, such as shear

thinning, shale protection by polymer coating and a thin, slick filter cake. Brines

or seawater may be used to add water or salinity to the system.

A special class of water-based muds is partially-hydrolyzed polyacrylamide

(PHPA) as an additive, either to encapsulate drill solids or to extend bentonite

clay in a low-solids mud. PHPA muds have become reasonably common in

Western Canada, and PHPA appears to be the polymer of choice where

extended viscosity and/or shale encapsulation is required. These muds perform

well but are, like all polymer systems, relatively expensive.

As a polymer system, PHPA works well in fresh water, seawater, saturated salt

water mud, KCl and solids-free brine systems. It also provides shale

filming/inhibition, flocculation of drilled solids, viscosity and lubricity.

PHPA’s strong encapsulating/filming action stabilizes clay and shale formations,

blocks the absorption or inhibition of water from the drilling fluids, and preventsclay and shale cuttings from disintegration while carrying them up the annulus

from the bottom of the hole (bit) to surface.

Fluids containing PHPA exhibit shear-thinning at the bit, which helps maximize

the ROP by providing low bit viscosity and high lifting capacity at the lower shear

rates in the annulus.

PHPA fluids do, however, tend to blind normal shaker screens, and a larger

mesh screen is generally required where these systems are used.

Gel-KCl and Gel-KCl Polymer

The beneficial effect of the K potassium ion on stabilization of hydratable shales

has been well established. It has been shown that the K+ ion fits exactly into the

clay matrix, preventing water access and subsequent swelling. In areas where

shale hydration causes hole sloughing, this mud system can be run with 4% to

6% KCl to reduce the problem. The KCl drilling fluid may also be used to reduce

the swelling of sensitive clays in the reservoir.

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Simply adding gel to concentrated KCl brine will not produce appreciable

viscosity, as the gel will not yield; the K+

ion prevents effective hydration of the

bentonite. The gel is therefore pre-hydrated in fresh water before incorporation

into the mud system.

As with any bentonite-water system contaminated with positive ions, viscosity isoften difficult to maintain. Adequate viscosity is provided by 0.6 to 1.8 kg/m3

polysaccharide and filtration is reduced with 1.4 to 3 kg/m3

cellulose polymers.

Maintaining a water loss of less than 10 cm3/30min with this system becomes

very expensive. The filter cake will be thicker than the average mud. This mud

resists contamination from salts, but calcium may cause precipitation of the

polymer at a pH value above 11.

A disadvantage to keep in mind is the difficulty in disposal of high chloride fluids.

In Alberta, it is necessary to obtain approval for fluids disposal at the end of the

well from the AER prior to spudding. This disposal approval will be a condition on

you drilling license.

Solids Free Systems

Solids free polymer drilling fluids were originally developed in Alberta in the

1980s to be fast hole drilling fluids. The idea was to eliminate clays and all other

solids (which decreases ROP), and to provide decreased bit viscosity due to

shear thinning, increased bit horsepower and increased spurt loss (which

increases ROP). This was done by substituting polymers for clays in water to

provide viscosity and carrying capacity, shear thinning, decreased turbulent

friction losses, high gel strengths and filtration control with high initial spurt loss.

The systems are highly resistant to contamination due to the absence of clays.

The main drawback is the high cost of polymers required to increase fluid

viscosity, to increase gel strength and to minimize filtration. These systems can

also be expected to “bind” drill solids into the system making solids control

difficult. They have been used primarily where large sumps are in use allowing

longer settlement times but historically the only solution to the solids control

problem is dilution of the system. Due to the high cost of the polymers, this can

greatly increase the cost of the hole.

With the increasing use of “sumpless” drilling operations and the increasing costs

of polymers, these systems are being used less and less. Additionally, other fluid

systems have been developed at a considerably lower cost, and no-solidspolymer systems are seen very infrequently.

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Flocculated Water (Clear Fluids Drilling)

This is a special application of a no-solids system where the objective is to drill

the well with “clear” water, that is, water that has little to no suspended solids in

it.

Empirical evidence shows that the fastest ROP attainable, with a liquid drillingfluid, is using the lowest fluid density possible. However in drilling with water-

based fluids, the drill cuttings are ground up to a very small size and it becomes

increasingly difficult to remove them. These cuttings accumulate in the drilling

fluid, causing the density to increase and the ROP to decrease.

In a flocculated water system (floc-water), chemicals are added to the water to

flocculate the bentonite along with drill cuttings into large soft accumulations,

which are then removed at surface before the clear fluid is circulated back down

the hole. The most common additives in Alberta are gypsum (calcium sulphate),

caustic, lime, soda ash (which all maintain a high pH) and a variety of specialized

polymer flocculants.

Summary – Water Based Fluids

Water-based drilling fluids are the least expensive, simplest way to drill a well.

They are readily adaptable, through the use of additives, to meet most drilling

situations. They tend to be less harmful to the environment and easier to dispose

of when the well is finished.

Pure Oil-Based Systems

There are a number of pure oil-based systems available (such as “Black Magic”),

although they are becoming increasingly rare. The pure oil-based drilling fluidsare mixtures of oxidizing asphalt organic acids, alkali, stabilizing agents and high

flash diesel oil. Such drilling fluids will usually tolerate less than 3% water

emulsified in the oil.

Invert Emulsions

Invert emulsion is the main oil mud type presently in use. Invert emulsions

contain up to 50% water emulsified in the diesel, with various additives used to

emulsify the water and stabilize the system.

The invert mud system is a water-in-oil emulsion in which oil is the external or

continuous phase. The water is broken up into small droplets and uniformly

dispersed within the oil phase. To emulsify the water in the oil, there must be

sufficient chemical emulsifier to completely form a film around each water

droplet. If there is not sufficient emulsifier, the emulsion will be unstable and the

small water droplets will coalesce into large water droplets, and eventually into

two distinct phases.

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From the standpoint of stability, the smaller the droplet, the more stable the

emulsion. In an invert emulsion, the average droplet size is less than several

microns. Additionally, uniform droplet size also makes the emulsion more stable

and to obtain small droplets of uniform size, energy or work must be applied as

shear. The importance of droplet size and its relationship to mud stability cannot

be over emphasized. The droplet size also contributes to viscosity and gel

strength. When oil (continuous phase) is added, the emulsion becomes more

stable because the distance between droplets is greater. The reverse is also

true; additional water will decrease stability because the distance between water

droplets is lessened. The addition of oil or water will affect viscosity. Oil

decreases viscosity while water increases viscosity. An unweighted invert will

weigh approximately 890 to 900 kg/m3

with a 40 to 50 second funnel viscosity.

The high temperature high pressure (HTHP) fluid loss is approximately 2 to 4

cm3/30 minutes and contains only oil. If free water is present it indicates

insufficient emulsification and steps should be taken immediately to rectify the

problem.

The water phase needs to contain various concentrations of salt to maintain a

balance with formation fluids containing salts. Generally speaking, a saline

formation fluid attempts to absorb less saline water from a fresh water source

through osmotic forces in order to balance the salinities. If left indefinitely, both

fluids will have the same salinity, meaning that the (potentially fresh water

sensitive) formation has absorbed a portion of the fresh water present in the

drilling fluid.

To counteract these forces, the water phase of the invert contains sufficient

chlorides to balance the osmotic forces of the formation, thus eliminating the

absorption of water. The water salinity is determined by the salinity of the

formations to be drilled and is usually between 40,000 ppm for relatively fresh

water formations and up to 140,000 ppm for very saline formations. If massive

halites are to be drilled, it is common practice to increase the salinity in the water

phase to 350,000 ppm.

Invert emulsion drilling fluids have applications such as the following:

1. Drilling through hydratable shales, which tend to slough.

2. Drilling crooked or directional holes that develop high torque and drag.

3. Drilling through water sensitive reservoirs.4. Drilling areas with high corrosion rates, particularly when much H2

5. Drilling through soluble formations such as massive salts and other

evaporites. S is present.

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The system has additional benefits, such as:

1. Reduced possibility of differential sticking across porous zones due to low

filter loss and lubricity of the filter cake.

2. Lower mud weight than water base in normally pressured zones

contributes to generally higher penetration rates.

3. Resistant to contamination.

4. Stable mud properties at temperatures above 175°C.

5. Can be modified into a very stable, non-corrosive, non-freezing packer

fluid.

There are disadvantages of oil-based systems, which restrict the areas where its

use is practical. These disadvantages include:

1. High initial cost of system. Costs may be between $4000 and $7000 per

m3

, as opposed to water-based fluids, which may cost as little as $150per m3.

2. Seepage losses can be high and expensive. Note that because of its

cost, the mud is normally cleaned (centrifuged to remove drill cuttings and

barite) and reused on other invert wells.

3. Lower viscosity and less effective cleaning properties.

4. Location restoration costs increased.

5. Dirty working conditions if not properly looked after.

6. Hard on rubber in circulation system.

7. The aniline point of diesel must be above 60°C. Note that the aniline point

is a measure of the amount of aromatics in the diesel. While this is

required to minimize the amount of damage done to rubber products in

the circulating system, it is also good practice to reduce aromatics such

as benzene and toluene from a health perspective, as they are known

carcinogens.

8. Slow penetration rate through carbonate rocks. Note that a low colloid

invert with relaxed filtration control can be used to obtain normal

penetration rate, although the costs will increase.

To properly run an invert mud, sufficient and efficient solids control must beutilized. This is not unusual for any mud system except that in the case of an

invert system the cuttings are oil soaked and contain up to 30% oil. Care must be

taken to segregate these cuttings and dispose of them properly.

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Synthetic Drilling Fluids

In many offshore drilling situations, there are hydratable shales, massive salt

sections and many other potential drilling problems. These drilling situations are

best dealt with using an oil-based drilling fluid. However oil-based fluids present

unique risks offshore – the majority of which relate to the perceivedenvironmental impact of a spill of an oil-based fluid and the observed difficulties

in disposing of the cuttings. Day rates for offshore rigs are so high that using

water-based fluids is not an option, as the risk of hole problems is simply too

high. And the environmental based complaints against oil-based fluids are such

that oil-based fluids are questionable in many cases. The majority of operators in

these areas have chosen to use a synthetic product or a synthetic based mud

(SBM).

In SBMs the synthetic liquid forms the continuous phase while an emulsified

brine forms the discontinuous phase. The formation and the cuttings are exposed

primarily to the synthetic phase and it acts in a manner similar to an oil-based

mud – reducing the swelling and degradation of the borehole walls and the

dispersion of the cuttings into the fluid. The system works well and does not need

large dilution volumes and the volume of both the mud system and spent cuttings

can be minimized.

SBMs are available using a range of base fluids and these include:

• Esters, which are synthesized from fatty acids and alcohols. In several

compounds, the fatty acids are synthesized from vegetable oils (canola).

In esters, the key is the selection of hydrocarbon chain length on either

side of the ester group. These groups are selected to provide adequate

viscosity, hole stability and to minimize toxicity.

• Ethers are a range of materials synthesized from alcohols. The

hydrocarbon groups associated with ethers are selected to maximize the

operating properties of the drilling fluid

• Polyalphaolefins (PAOs) are manufactured by the polymerization of

linear alpha-olefins such as 1-octene or 1-decene. Control over the

chemical structure and physical properties is possible by the adjustment

of the reaction parameters in the polymerization process and the

selection of the starting alpha-olefin.

•

Olefin Isomers are derived from the selective isomerization of normalalpha-olefins. Products are selected to maximize the required drilling

parameters while minimizing environmental impact.

All of the SBMs have different chemical properties and drilling performance.

Environmental impacts also differ.

Most SBMs have drilling and operational properties similar to oil-based mud

(OBM) systems and are commonly used to replace OBMs and drill situations

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such as hydratable shales, high temperatures and salts. In some cases, SBMs

provide better drilling performance than OBMs.

Costs for SBMs are several times higher than OBMs, but can be recovered if the

cuttings can be discharged on site (to the sea) and if the environmental

requirements prohibit (or make exorbitantly expensive) the use of OBMs.Given that the primary use for SBMs is environmental impact reduction, there are

several other reported advantages to its use. They include:

• Less waste relative to water-based muds (WBMs).

• Elimination of diesel as a base mud and less perceived pollution

potential.

• Improved drilling performance relative to WBMs.

• SBMs also provide increased lubricity (reducing torque and drag),

reduced friction, lower densities (and higher ROPs) and reduced

wastes.

The primary disadvantage is cost.

Exercise Two

Compare and contrast WBM, OBM and SBF by completing the following table ofadvantages and disadvantages.

Fluid Type Advantages Disadvantages

WBM

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Fluid Type Advantages Disadvantages

OBM

SBM

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OBJECTIVE THREEWhen you complete this objective, you will be able to:

Describe how clay chemistry affects drilling fluid properties.

Learning Activities



2. Complete Exercise Three.

Learning Material

Clay Mineralogy

Anyone who is involved or interested in the oil and gas industry will quickly

realize that is important to understand clay behaviour. Clays furnish the colloidal

particles in many drilling muds and are one of the most common additives to both

water-based systems. Even when you drill with water, clay from the formations

drilled become suspended in the fluid and alter the fluid properties. During the

drilling of the well, clays in the shales will absorb some water and this may affect

hole stability. Because of these interactions, a general knowledge of colloid

chemistry and clay mineralogy is essential.

Colloids

Colloids are not any particular material but are materials of a size that is similar

to the water molecules in which they are suspended. This means that colloids are

0.0001 to 0.0005 microns in size.

Colloidal systems (colloid particles suspended in water) have their behaviours

typically governed by their extremely large surface area. In most cases, surface

chemistry determines the colloid system properties. In the inside of any colloid,

each molecule is surrounded by similar molecules – at least on one side – and

the surface carries an electrostatic charge. To modify the system properties, you

need to add a surface active agent (often a surfactant), which modifies theinterfacial forces and determines the properties of the fluid.

Clays

Clay is defined as a rock: a fine-grained, earthy substance having plastic

properties that will become shale if consolidated. These clay minerals are

hydrous aluminum silicates, usually containing alkalis (sodium or potassium),

alkaline earths (calcium or magnesium) and iron in appreciable quantities.23


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Clays in Water

Mud engineers are not normally particularly familiar with the chemical

composition or the crystalline structure of the clay, but rather in how the clay

behaves when it is contact with water. These materials will tend to hydrate (the

bonding of water molecules to the surface of the clay particle) in the presence ofwater. This bonding is a major factor in the behaviour of the drilling fluid.

Depending on the extent of the hydration, the clay will cause an increase in the

viscosity, gelation and fluid loss of the fluid. The increase in viscosity provides

the fluid with better carrying capacity, (that is, the ability to clean the hole) and

increased suspension ability.

Clay Structure

There are two broad classes of clay:

1. Sheet like, thin platelets such as montmorillonite, illites and kaolinites.

2. Rod or needle like particles, such as attapulgite.

The sheet like group can be further classified by the number of sheets that form a

single platelet (two-layer or three-layer units). Each sheet is primarily made up of

either alumina (Al2O

3) or silica (SiO

2), although the substitution of other atoms is

common and can profoundly affect the properties of the resulting clay.

The three-layer group can be further divided into swelling and non-swelling clays.

Those clays that readily swell or hydrate allow water molecules to enter between

the platelets which spreads the layers , which in turn allow more water to be

absorbed onto the surface of the clay. The result is a colloidal suspension of the

clays which greatly increases viscosity. Clays that exhibit these properties arecalled smectites. The principle smectite is montmorillonite, which is the main

ingredient in bentonite.

Ion Exchange

The concept of ion exchange accounts for many significant changes in drilling

fluid properties. During the formation of clays, the Al+++

ion may be exchanged for

a lower valence ion (usually Mg++

), leaving a negative imbalance. In addition,

there are other ionic imbalances at the broken boundaries of the clay crystal.

This imbalance will be off-set by the absorption of a cation.

The stability of clays in water is attributed to the forces of attraction and repulsioncaused by the residual charges on the surface of the clay platelet. Because of

the exchangeable bases, negative charges predominate on the face of the

platelet, but positive charges (off-set by anions) are present and predominate on

the edges. The face area is much greater than that of the edges, thereby

assuring an overall negative charge for the particle. The charges bonded to the

clay and the ions present in the water make up an electrical double layer with a

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measurable potential, which will determine the stability of the particle in

suspension. Two-layer clays exhibit less ion exchange than three-layer clays and

are thus more stable. Three-layer clays tend to have much higher ion exchange

potentials and thus dissociate more readily in water. The three-layer clay of most

interest to us is sodium montmorillonite (bentonite), as it is readily hydratable and

extensively used as a viscosifier in fresh water.

Bentonite

Bentonite is the most important clay used in drilling. Drilling quality bentonite is

primarily sodium montmorillonite. In its simplest form, the clay particles resemble

a deck of cards or the pages of a book. The three-layered sandwich has two

outer layers of silica surrounding a middle layer of alumina. These platelets are

so small that approximately 1,500,000 of them would make a pile 1 mm high.

This structure is shown on page 98 of the Mitchell and Miska textbook.

When the stack of clay platelets comes in contact with fresh water, the cations

have a tendency to move into the water, leaving the clay surface with a slightly

negative charge. Water molecules are available and bond with the negative

charges and the clay particle becomes surrounded by water molecules, forcing

the particle apart and causing swelling. As this continues, more and more water

surrounds the clay particle and eventually individual clay platelets become fully

separated. This process is caused by hydration and is the basic mechanism

whereby clay builds viscosity in water.

If the water used to hydrate the clay is salty, the Na+ ion is present and

represses the ionization of the sodium ion in the clay platelet. Additionally the

Na+ ion is attracted to the negative charge of the clay particle reducing the

polarity of the clay and minimizing the attractive forces between the particles.

Salt Water Clay or Attapulgite

Attapulgite (salt gel) differs from other clays in that it is made up of rod or needle

shaped particles rather than platelets. Due to this shape, it does not provide

viscosity in the same manner. Viscosity is mechanical rather than dependent on

inter-particle attractive forces. It is the inter-meshing of the needles that provides

viscosity, high shear stress is required to break up the mesh and when broken

the needles exhibit unbalanced charges. As soon as the shear is removed, the

needles regroup, but in a random manner. Attapulgite will provide viscosity in

waters of any salinity, however, the nature of the needles and the randommanner of combination do not provide good fluid loss control.

Clay Linkage

Depending on the drilling fluid environment in which the clays are present, the

clays can link together in various configurations. The orientation of the particles is

very important to the rheological properties of the drilling fluid. The drilling fluid

engineer will be able to predict the flow behaviour of the fluid based on25


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knowledge of how the clays can be expected to link up in a given type of drilling

fluid.

The attraction/repulsion of ions on the surface of the particle are responsible for

the forces that link or separate clay particles (ions with like charges repel, ones

with different charges attract). That is, anions will be attracted to cations, butrepelled by other anions.


Figure 2: Attraction and repulsion

The four most common linking processes are (refer to Figure 3 below):

1. Aggregation: a large amount of the clay particles are in the face-to-face

orientation. This is the common state when clay first enters the drilling

fluid, either in the form of drill cuttings or as an additive.

2. Flocculation: edge-to-edge or edge-to-face orientation, gives the most

viscosity with the least amount of clay. The system will tend to be

unstable, as the bonds are easy to break.3. Deflocculation: the system will contain aggregate particles, f locculated

particles and individual particles separated by space and repulsive forces.

4. Dispersion: widely separated individual clay particles. The particles have

a lower viscosity than flocculated systems, but tend to be more stable.

They also have the lowest viscosity for a given quantity of clay material.

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Figure 3: Clay Linkages

Bentonite

Sodium montmorillonite (bentonite) is the most common clay viscosifier used in

drilling fluids, as it readily hydrates in fresh water to a fully dispersed state. This

means that you will gain the highest yield (m3

of DF per tonne of clay) of any clay.

Dispersed clay particles are very small (less than 1 micron), and will form what is

known as a colloidal system. In a colloidal system, the particles are so small that

they will be held in suspension by Brownian motion alone. This minimizes any

loss of material due to gravity settlement, and will impart important rheologicalproperties to the drilling fluid. The attractive forces between the colloidal particles

create an increase in the viscosity of the fluid. It is viscosity that allows the drilling

fluid to clean cuttings from around the bit and to carry them out of the hole.

Viscosity also aids the ability of the drilling fluid to suspend cuttings when the

fluid is not being circulated.

Exercise Three

1. Describe the following:

a. How clay colloids are held in suspension.

b. The possible sources of clay material that a drilling fluid may contain.

c. The effect of clay material on drilling fluid properties.

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OBJECTIVE FOURWhen you complete this ob jective, you will be able to:

Explain the different drilling fluid additives and chemicals and their typical

applications.

Learning Activities



2. Complete Exercise Four.

Learning Material

Drilling Fluid Additives and Chemicals

There are two classes of material added to drilling fluids: additives and

chemicals.

Additi ves: These are solid materials that are added and become suspended in

the fluid, thus becoming part of the discontinuous phase of the system.

Chemicals: These are materials that dissolve into the base fluid (WBMs), thus

becoming part of the continuous phase of the system. In inverts they may also

dissolve into the discontinuous phase (the water).

Water-Based Fluids

Water-based drilling fluids are systems where the continuous phase is water. In

Western Canada, fresh water is used (with essentially no chemicals dissolved in

it). In other parts of the world (and particularly offshore), the water may contain

naturally dissolved chemicals such as salt. It is important to remember that if the

water has chemical already in solution, these chemicals may affect the additives

and other chemicals, and ultimately the properties of the drilling fluid.

Fresh water alone is a very poor drilling fluid because it has very limited viscosity

and essentially no fluid-loss control. To alter these basic rheological properties,

the water will have material added to it and suspended within it. If intentionallyadded to the system, these materials are known as additives and form the

discontinuous phase. Drilling fluid additives are used to adjust the properties of

the system in order to allow the fluid to effectively perform the functions required

of it. If the additives are not intentionally added, they are known as contaminants.

All contaminants will affect the drilling fluid properties in some way.

Examples of contaminants are drill cuttings, including shales, cement (from

drilling out the casing shoes) and other chemicals from the formations.28


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It should be noted that most drilling fluid additives will affect more than one of the

properties of the system. It is very important that the proper concentrations be

used and maintained to carry out the function intended without adversely

affecting other system properties.

Viscosifiers

As mentioned, pure fresh water has essentially no viscosity. Viscosifiers are

materials that are added to the system to increase the viscosity of the fluid. An

increase in viscosity enhances the drilling fluid’s ability to clean cuttings from the

bit and to transport them to surface. It also increases the fluid’s ability to suspend

material (cuttings) when circulation is stopped. All WBMs require viscosifiers. The

most common viscosifiers used are additives (colloidal clays), but they may be

chemicals.

Each is discussed below, together with the mechanism provides gives the

viscosity.

1. Bentonite

Drilling quality bentonite is high-grade sodium montmorillonite, a high yield clay

that gives good viscosity and aids in fluid loss control in fresh water systems. It is

used in almost all WBMs and provides viscosity through the electrical charge

imbalance (polar behaviour) on the individual platelets. These individual platelets

are surrounded by water molecules and cannot aggregate. However the

electrical attraction provides the viscosity.

Bentonite is readily available, reasonably inexpensive and consistent in its grind,

composition and properties.The majority of WBM fluids use a bentonite/water mixture as the base fluid for

the more complex fluids in use to meet specific formation or other well needs.

These more complex fluid mixtures build on the properties of the basic,

bentonite/water fluid mixture and they use additives and chemicals as described

below.

2. CMC

Sodium carboxymethylcellulose (CMC) is a long chain polymer that is added to

water as a colloid. It provides viscosity in water-based systems through the

physical interference/entanglement of the long chain molecules. CMC will extendthe viscosity of a bentonite in water system, but it is used primarily for f luid loss

control.

CMC is widely available and, while expensive, it is the least expensive of all the

organic-based polymers. Like all organic-based polymers, it requires the use of

biocides to protect it from bacterial degradation.

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3. Salt Gel

Mixing bentonite in salt water is ineffective in providing viscosity, as the Na+

ion

is attracted to the negative charges on the face of the platelets. The only effective

manner in which bentonite can provide viscosity is if it is pre-hydrated in fresh

water to develop its viscosity. Mixing the pre-hydrated bentonite into the saltwater will carry the viscosity into the new mixture, but this viscosity will not last.

Within a relatively short time, the Na+ ions will be attracted to the clay.

If a sea water fluid is to be used as the base fluid, a different kind of clay must be

used. This clay is normally attapulgite, often called salt gel. Attapulgite is a clay

viscosifier that can be used in water of any salinity, but is primarily used in brine

and sea water drilling fluids.

Attapulgite has a needle-like structure, and provides viscosity in the WBM

through a physical interference of the needles.

4. XCD Polymer

XCD polymer is a high molecular weight polymer specifically manufactured for

high dispersion. It is a water-soluble polysaccharide of xanthan gum, and

provides excellent viscosity in all salinities of water. It also provides a limited

measure of fluid loss control.

Like all polymers, it provides viscosity through the physical

interference/entanglement of the long chain molecules. Again, like all organic-

based polymers, it requires the use of biocides to protect it from bacterial

degradation.

Fluid-Loss-Control or Fluid-Loss AgentsFluid loss agents are additives that assist the drilling fluid to build a tight,

impermeable filter cake and lower the amount of filtrate lost to the formation

during the drilling process.

There are three primary reasons to lower the fluid loss and prevent filtrate

(primarily water) from entering the formation.

1. When drilling through water sensitive shales or other zones that may

become unstable when exposed to water, it is important to minimize the

volume of filtrate reaching the shale and thus lessen any problems that

are associated with water sensitive formations. Note that lowering thefluid loss will not completely eliminate this sort of problem, but will help

ensure that the situation does not become a major problem.

2. Log interpretation is usually based on a relatively low amount of fluid

invasion. Where high volumes of filtrate are present, this interpretation

becomes somewhat questionable. The majority of clients will specify a

maximum fluid loss (usually 8-10 cm3/30min) when drilling a pay zone.

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3. Fresh water allowed to penetrate a pay zone that contains swellable clays

will likely damage the permeability and reduce the potential productivity of

the zone. It is important that this damage be minimized.

1. Drispac

Drispac is a high molecular weight polyanionic cellulose (polymer) that provides

fluid loss control in water-based systems, regardless of their salinity.

The polymer provides fluid loss control through the physical interference of the

long chain molecules in the filter cake.

Using polymers to develop fluid loss control will have a serious secondary effect:

it will also cause a significant increase in viscosity. This viscosity is dependent

upon the concentration of Drispac used. Drispac should be used in low

concentrations in fresh water (1-3 kg/m3

), but it may be used in higher

concentrations – up to 10 kg/m3

– in salt water.

2. Lignite

The lignite used in drilling fluids is a naturally oxidized coal product that is used to

control filtrate loss in both fresh and saline water.

Lignites are a temperature stable thinner (they are much more stable than

lignosulphonates). They work by dispersing the clays in the mud, effectively

releasing the clay platelets that are bound into the cuttings and the calcium ions.

Once released, the clay platelets provide the fluid loss.

Lignites also act as thinners (viscosity reducers) but require a pH greater than

9.5 to provide effective deflocculation and dispersion.

3. Lignosulphonate

Lignosulphonates are used primarily as a low to normal temperature (less than

120°C) deflocculating agent in WBM. Lignosulphonates also contribute

significantly to fluid loss control in both fresh and saline water, and act in the

same manner as lignites.

Lignosulphonate is primarily used as a thinner, and provides a high degree of

dispersion in both fresh and saline water.

4. Starch

Starch used in the drilling industry may be a pre-gelatinized cornstarch or potato-

based starch that is designed specifically for use as a filtration control agent.

Starch acts as a gelatin, encapsulating drill cuttings and clay particles and

binding them into the filter cake, thereby reducing the filtration.

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Starch will also increase viscosity somewhat, and encapsulates cuttings in a

polymeric film, effectively preventing the cuttings from hydrative and dispersive

disintegration.

Starch works best in an alkaline environment, and should be used with a biocide.

5. Starlose

Starlose is a hydrophilic organic polymer made from starches, and is protected

against bacteria attack. It provides excellent fluid loss control in all water-based

systems in a similar manner to starches.

6. Tannins

Tannins are derived from wood bark and are used to control fluid loss in water-

based systems. Tannins work in a manner similar to lignites and

lignosulphonates in that they provide dispersion of the clays in the drilling mud.

They also act as a mild thinner.

Thinners/Deflocculants

Thinners are additives that cause the clays in the mud system to disperse,

separating the clay platelets and thus reducing the viscosity of the system.

Thinners are generally used to maintain the rheology of the system within the

desired range for any given type of drilling fluid. They act by reducing the

attractive electrical (ionization) forces between particles, allowing them to totally

separate within the continuous phase of the fluid.

Deflocculants are additives that reduce clumping (flocculation) or aggregation

within a system. Deflocculants also reduce the attraction between particles, butnot to the same extent as thinners. Deflocculants generally do not provide

complete dispersion of the clay particles within the mud.

1. Cypan

Cypan is a synthetic high molecular weight polymer of acrylonite. Cypan is

absorbed onto the clay platelets and initially isolates the individual platelets,

causing deflocculation of the system. Once deflocculation occurs, it may be

difficult to regain viscosity.

Cypan will cross link the clay particles in the filter cake and assist in building a

thin, tight filter cake, in addition to reducing fluid loss.

2. Lignite

While it is primarily used as a fluid loss agent (see above), lignite also acts as a

thinner in both fresh and saline systems.

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3. Lignosulphonate

Lignosulphonate is primarily used as a thinner, and provides a high degree of

dispersion in both fresh and saline water. Lignosulphonates also provide fluid

loss control (see above) and the same process applies.

4. SAPP

SAPP is sodium acid pyrophosphate, and is used to treat out calcium from

gypsum, cement and anhydrite. SAPP is frequently used as a thinner in low pH

(less than 9) drilling fluids where temperatures do not exceed 82°C. SAPP is very

useful in preventing mud rings during the drilling of surface hole.

Weighting Agents

Weighting material is used to increase the density of the drilling fluid when it is

necessary to have additional hydrostatic pressure to control the subsurface

pressures expected in the interval to be drilled. Weighting agents are primarily

dense solids that become part of the discontinuous phase or heavy salts (used

primarily in completions fluids systems) that dissolve into the continuous phase.

1. Barite

Barite (or bar) is barium sulphate, a finely ground compound having a specific

gravity (SG) of 4.265. It is used to increase the density of liquid based systems.

Barite may be used to increase the fluid density to approximately 2400 kg/m3

although 2200 kg/m3is more common. Barite is also commonly added in a short

pill form (usually less than 5 m3) to prevent wet trips. The dense pill is placed in

the drill pipe and provides a degree of overbalance on the drill pipe, causing the

fluid to fall from the drill pipe into the annulus.

2. Calcium Carbonate

Calcium carbonate is a non-water-soluble, naturally occurring limestone, ground

relatively finely, with an SG of 2.7. It is used as a weighting agent when it is

desirable that the compound be acid soluble, and it is used almost exclusively in

the drilling or completion of producing zones.

3. Hematite

Hematite is an iron ore, Fe2O3, with an SG of 5-6.2. It is used when a sufficientdensity increase cannot be obtained with barite. A system weighted with hematite

may have a density of up to 2800 kg/m3, and is a much more stable system than

one weighted with galena.

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4. Galena

Galena is lead sulphide (PbS) with an SG of 6.7. It is used when the density

cannot be increased sufficiently using other materials. Systems containing

galena tend to be unstable (the galena “sags,” or falls out of the drilling fluid).

These systems also exhibit very high and stable gel strengths.

5. Salts

Drill-in fluids are used to drill a pay zone that is sensitive to solids plugging.

These drill-in fluids are often clear fluids, basically water with limited additives. If

some additional weight is required, various salts can be dissolved into the

continuous phase of the drilling fluid. Salts are available with an SG of 2.1 (NaCl)

at the lower end, and 3.3 (NaBr) with the heavier salts. These brines may also be

used for completions fluids and packer fluids.

Lost Circulation Material

This is material added to the system to stop or minimize the loss of drilling fluid to

porous/permeable zones. Lost circulation varies from case to case: it may be

simply a high seepage loss (very important if you are using high cost muds such

as invert), or it may be a complete loss of drilling fluid to the formation. Severe

lost circulation is very important from a blowout prevention point of view; if you

have complete losses, the hydrostatic head will be dramatically reduced. If you

have any porous and permeable zones open in the wellbore, you can expect to

take a kick.

Lost circulation material (LCM) is material that aids in forming bridges to act as a

back stop to finer material (clays) in the drilling fluid. The most common types of

LCM are sawdust, cellophane (flat plastic) or fibrous materials. Lost circulation is

potentially serious enough that it must be healed or cured as soon as possible,

and a wide variety of material has been used as LCM in past situations.

1. Cellophane

Cellophane or celloflake is clear, multi-sized flakes of poly-cellulose. Sizes range

from 5 mm to several cm. Expectations are that cellophane will act as a sealing

agent to the formation permeability. Cellophane in the drilling fluids system will

also plate out on the shale shakers and blind the shakers. When using LCM, it is

usually necessary to bypass the shakers, and there is a risk that the bit jets may

plug.

2. Fibre

Fibres may be organic (such as cedar-bark or ground sugar cane), or they may

be man-made (such as shredded nylon fibres). Fibrous material acts as a matting

agent to assist the sealing and bridging agents in sealing the formation

permeability.

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3. Mica

Mica or muscovite is a naturally occurring mineral that is processed into fine,

medium and coarse flakes. It is generally inert and non-toxic, and can be used in

both drilling fluids and cement slurries to reduce lost circulation. It is often used to

reduce seepage losses.

4. Kwik Seal

Kwik Seal is a mixture of granular materials, flakes and fibres, and is available in

a range of grind sizes.

5. Sawdust

Historically, sawdust has been readily available from sawmills as a relatively

cheap waste product. It has been used extensively as a lost circulation material

in WBM. Initially, the wood chip and fine wood dust swell in the mud and provide

a degree of plugging. However, the swelling is time dependent and the wood

structure breaks down quickly in the WBM, ending as a dispersion that does very

little for the lost circulation.

Demand for sawdust is increasing and the price and availability are changing

dramatically. Because of this, the advantages of using sawdust may be

disappearing rapidly.

6. Nut Hulls

In the southern US states, pecan and walnut shells are readily available as a

waste product and are ground into fine, medium and coarse grinds. These

granular products are not particularly effective, and it makes little economic

sense to use them outside the Southern US states.

Flocculants

Drilled solids (cuttings) are ground up into the drilling fluid and as they are ground

smaller they become extremely difficult to remove from the fluids. Additionally,

excessive solids in the drilling fluids increase the yield point and cause gelation.

Flocculants are additives and chemicals used to cause the suspended particles

to clump together or flocculate. When they are added, the flocculated drilling fluid

becomes essentially two phases – a continuous water phase with little or no

solids and a very wet solids phase. The system will have a high viscosity –caused by the flocculated solids – and a very high fluid loss – determined by the

clear fluids.

Flocculants are used to obtain a higher viscosity in a “low solids” system where it

is desired to keep the amount of solid material and thus the density as low as

possible.

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Flocculants are also used to flocculate fine drill cuttings into relatively large

clumps to facilitate their removal at surface when using a “clear water” drilling

fluid system where chemicals are used to maintain a water-based drilling fluid

system that is fairly close to clear or transparent.

1. Soluble Calcium Salts

When a soluble calcium salt is dissolved in the water-based mud, the Ca++

ion is

distributed and is attracted to the negative charges on the clay particles. These

attractions pull the clay platelets and the fine drilling solids together into large,

wet clumps.

The common calcium ions deliberately added to WBM systems include:

• Gypsum: naturally hydrated calcium sulphate (CaSO4)·2H2O. Cheap and

readily available gypsum is generally used as the base flocculant in clear

water systems, for drilling anhydrites or inhibition of reactive dirty (shaly)formations.

• Calcium Chloride: CaCI2 is used where flocculation of solids is required

in clear water systems.

• Lime: this is calcium hydroxide (Ca(OH)2), and will provide flocculation in

clay-based water muds. Lime may also be used to treat out carbonate

and bicarbonate contamination and to control pH.

2. Potassium Chloride

Potassium chloride is a potassium salt that may be used as a flocculant in low

solids systems. The potassium ion has a single valance, and is not particularly

effective as a flocculant. It is generally used to provide potassium ions in

“inhibited” systems that are made up to minimize formation clays (in water

sensitive shales and production zones) reactions with water. In these cases, the

potassium ion fits exactly between the clay platelets, preventing water ingress. In

Alberta, the high chloride content of these systems makes disposal of the mud

environmentally unacceptable by normal methods, and the ERCB requires that

the disposal plan be approved prior to issuing a well license.

3. Guar Gum

Guar gum is a natural organic polymer made from Arabic gums (tree sap) whichmay be used as a flocculant in saline systems.

5. Polyacrylamide

Various types of polyacrylamides are used in clear water drilling fluids as a

flocculant. These polymers include partially hydrolized polyacrylamide (PHPA)

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and are used to give an enhanced performance in low solids and clear water

systems.

Polyacrylamides act as many polymers and bind solids, encapsulating them in

the long chain molecules. Additionally, they provide a high level of viscosity

which will shear thin as it is pumped through the bit.

Specialized Additives

There are many other specialized additives that are added to drilling fluid

systems to attain specific results. These additives do not readily fall into any of

the general categories and a number of the more common ones are listed below.

If you have specific needs or problems to solve which are not completely

covered, contact your mud company. They will probably have seen the problem

elsewhere and be willing to make suggestions.

1. Aluminum Stearate

Aluminum stearate (Al(C18H35O2)3 is a surface active organo-metallic compound

used as a defoamer in dispersed or gel-chem systems. Aluminum stearate is not

water soluble and is normally premixed into diesel fuel before it is mixed into the

drilling fluid.

Anionic surfactants derived from vegetable oils may also be used to defoam most

water-based systems.

2. Biocide

Biocides are used to prevent bacteria attack on starches and (expensive)

polymers that would normally be prone to degradation and fermentation. Themost common biocides are a neutralized fatty amine acetate salt, but the most

effective biocides are paraformaldehyde-based.

Biocides are designed to kill bacteria, and in sufficient concentrations can be

harmful to people.

3. Caustic Soda

Caustic is sodium hydroxide, (NaOH) and is used to increase the OH+

ion content

of a system, and subsequently to raise the pH to between 10.5 and 11.5 where

most additives function better.

4. Pipe Free

Pipe free is a balanced blend of surface active ingredients (sulphonates). This

compound is used to degrade the filter cake along the wellbore wall in order to

free differentially stuck drill pipe.

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Pipe free is not water soluble, and is dissolved in diesel fuel before being added

to the fluid. Normally the pipe free pill is segregated from the remainder of the

system and displaced to the stuck point as a pill to soak the filter cake.

5. Soda Ash

Soda ash is sodium carbonate (Na2CO3), and is used to remove calcium ions

from cement and anhydrite contamination through precipitation as calcium

carbonate.

6. Sodium Bicarbonate

Sodium bicarbonate (NaHCO3) is used to remove calcium ions (primarily from

cement contamination) from muds with a pH above 9.

7. Zinc Carbonate, Iron Sponge

Zinc carbonate is used as a scavenger to remove H2S from the drilling fluid as a

chemical reaction. The concentration of zinc carbonate must be maintained for itto be effective. It works well in systems having a pH greater than 10.

Iron sponge is iron with a very large surface area where the H2S is absorbed onto

the surface of the iron. The sponge is removed at the shakers and the H2S will be

desorbed in the shale spoil pile.

Note: In Alberta, defoamers, biocides, pipe free and other diesel-based additives

are regarded as toxic if they are used. The fluid must be tested and treated prior

to being disposed.

Oil-Based FluidsOil-based systems use various specialized materials that have been adapted for

use in fluids where the continuous phase consists of a hydrocarbon base. The

additives will have the same general purpose as those added to water-based

systems.

Barite

Standard barite is used as a weighting agent.

Filtration Agent

This is a polymerized fatty acid that is used to reduce the HTHP filtrate of oil-based drilling fluids.

Gilsonite

Gilsonite is modified asphalt that is added to invert systems to lower fluid loss

and to coat the wellbore wall, providing mechanical stability.

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Organophil ic Clay

Organophilic clay is modified montmorillonite that is used both for viscosity

increase and to aid in fluid loss control.

Primary EmulsifierThis is a blend of emulsifiers based on stable fatty acids that react with oil and

water to form a tight emulsion. They are usually added with lime to aid in the

emulsification process.

Salt

It is easier to maintain a tight emulsion if the water has a high ion content. This

tends to stop osmotic transfer of water away from the drilling fluid to formations

that are highly saline. Any of the common calcium, potassium or sodium salts

can be used; however, calcium and potassium salts are generally preferred.

Secondary Emulsifier

A modified amine sulphonate used to tighten the water in oil emulsion. This

material is used when high temperatures or high electrolyte content is expected.

Wetting Agent

A wetting agent is usually a blend of alkanolamides and phosphoids used to oil

wet solid material added to oil-based systems. It also ensures that d

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