Petroleum Engineer''s Guide to Oil Field Chemicals and Fluids, Second Edition

Petroleum Engineer’s
Guide to Oil Field
Chemicals and Fluids
Second Edition


Petroleum Engineer’s
Guide to Oil Field
Chemicals and Fluids
Second Edition

Johannes Fink

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Notices
Knowledge and best practice in this field are constantly changing. As new research and experience
broaden our understanding, changes in research methods, professional practices, or medical treatment
may become necessary.
Practitioners and researchers must always rely on their own experience and knowledge in evaluating and
using any information, methods, compounds, or experiments described herein. In using such information
or methods they should be mindful of their own safety and the safety of others, including parties for
whom they have a professional responsibility.
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ISBN: 978-0-12-803734-8


Preface to Second Edition
This manuscript is an extension and update from Petroleum Engineer’s Guide to Oil
Field Chemicals and Fluids, which appeared in 2010.
The most recent literature including articles as well as mostly US patents that
appeared since 2010 are collected and introduced in the new text.
Last but not the least, I want to thank the publisher for kind support, in particular,
Katie Hammon and Kiruthika Govindaraju.
J.K.F.
March 9, 2015

v


Preface
This manuscript is an extension and update from Oil Field Chemicals, which
appeared in 2003. The text focuses mainly on the organic chemistry of oil field
chemicals. As indicated by the title, preferably engineers with less background in
organic chemistry will use this text. Therefore, various sketches of the chemicals and
additional explanations and comments are included in the text to those an educated
organic chemist is certainly familiar.
The material presented here is a compilation from the literature, including patents.
The text is arranged in the order as needed by a typical job. It starts with drilling fluids
and related applications, such as fluid loss, bit lubricants, etc. Then it crosses over to
the next major topics, cementing, fracturing, enhanced recovery, and it ends with
pipelines and spill.
Some of the chemicals are used in more than one main field. For example,
surfactants are used in nearly all of the applications. The last three chapters
are devoted to these chemicals. As environmental aspects are gaining increasing
importance, this issue is also dealt carefully.

HOW TO USE THIS BOOK
INDEX

There are three indices: an index of acronyms, an index of chemicals, and a general
index.
In a chapter, if an acronym is occurring the first time, it is expanded to long form
and to short form, for example, acrylic acid (AA) and placed in the index. If it occurs
afterwards it is given in the short form only, i.e., AA. If the term occurs only once in
a specific chapter, it is given exclusively in the long form.

In the chemical index, bold face page numbers refer to the sketches of structural
formulas or to equations which refer reactions.

BIBLIOGRAPHY
The bibliography is given per chapter and is sorted in the order of occurrence. After
the bibliography, a list of tradenames that are found in the references and which
chemicals are behind these names, as far as laid open is added.

ACKNOWLEDGMENTS
The continuous interest and the promotion by Professor Wolfgang Kern, the head of the
department is highly appreciated. I am indebted to our university librarians, Dr. Christian
Hasenhüttl, Dr. Johann Delanoy, Franz Jurek, Margit Keshmiri, Dolores Knabl, Friedrich

vii


viii

Preface

Scheer, Christian Slamenik, and Renate Tschabuschnig for their support in the acquisition of
literature. This book could not have been otherwise compiled. Thanks are given to Professor
I. Lakatos, University of Miskolc who directed my interest to this topic.

J.K.F.


CHAPTER

Drilling muds

1

According to American Petroleum Institute (API), a drilling fluid is defined as a
circulating fluid used in rotary drilling to perform any or all of the various functions
required in drilling operations.
Drilling fluids are mixtures of natural and synthetic chemical compounds used to
cool and lubricate the drill bit, clean the hole bottom, carry cuttings to the surface,
control formation pressures, and improve the function of the drill string and tools in
the hole. They are divided into two general types: water-based drilling muds (WBMs)
and oil-based drilling muds (OBMs). The type of fluid base used depends on drilling
and formation needs, as well as the requirements for disposition of the fluid after it
is no longer needed. Drilling muds are a special class of drilling fluids used to drill
most deep wells. Mud refers to the thick consistency of the formulation.
Drilling fluids serve several fundamental functions [1, 2]:
•
•
•
•
•

control of downhole formation pressures,
overcoming the fluid pressure of the formation,
avoiding damage of the producing formation,
removal of cuttings generated by the drill bit from the borehole, and
cooling and lubricating of the drill bit.

In addition to these fundamental functions of drilling fluids, drilling fluids
preferably possess several desirable characteristics which can greatly enhance the
efficiency of the drilling operation.

To perform these functions, an efficient drilling fluid must exhibit numerous
characteristics, such as desired rheological properties (plastic viscosity, yield value,
low-end rheology, and gel strengths), fluid loss prevention, stability under various
temperature and pressure operating conditions, stability against contaminating fluids,
such as salt water, calcium sulfate, cement, and potassium contaminated fluids [1].
Preferably, the drilling fluid exhibits penetration enhancement characteristics, by
having physical properties, which wet the drill string and keep the cutting surfaces of
the drill bit (whether of the roller cone or other configuration) clean.
The wetting attribute is at least in part a function of the surface tension of the
fluid. The drilling fluid also preferably has a high degree of lubricity, to minimize
friction between the drill string and the wall of the borehole, an extremely valuable
result being the minimizing of differential sticking. In this situation, the hydrostatic

Petroleum Engineer’s Guide to Oil Field Chemicals and Fluids. />© 2015 Elsevier Inc. All rights reserved.

1


2

CHAPTER 1 Drilling muds

pressure of the drilling fluid column is sufficiently higher than the formation pressure
so that the drill string is forced against the wall of the borehole and stuck.
Yet another desirable characteristic is the prevention from swelling of the solids
of the formation, that is, primarily clays and shales, which further reduces incidents
of drill string sticking, undergauge holes, etc. Inhibition of clay swelling, in general,
results from preventing the clays from adsorbing water.

1.1 CLASSIFICATION OF MUDS

The classification of drilling muds is based on their fluid phase alkalinity, dispersion,
and the type of chemicals used. The classification according to Lyons [3] is
reproduced in Table 1.1.
Drilling muds are usually classified as either WBMs or OBMs, depending upon
the character of the continuous phase of the mud. However, WBMs may contain oil
and OBMs may contain water [4].
OBMs generally use hydrocarbon oil as the main liquid component with other
materials such as clays or colloidal asphalts added to provide the desired viscosity
together with emulsifiers, polymers, and other additives including weighting agents.
Water may also be present, but in an amount not usually greater than 50 volume
percent of the entire composition. If more than about 5% of water is present, the mud
is often referred to as an invert emulsion, that is, water-in-oil emulsion.
WBMs conventionally contain viscosifiers, fluid loss control agents, weighting
agents, lubricants, emulsifiers, corrosion inhibitors, salts, and pH control agents. The
water makes up the continuous phase of the mud and is usually present in any amount
of at least 50 volume percent of the entire composition. Oil is also usually present in
minor amounts but will typically not exceed the amount of the water so that the mud
will retain its character as a water-continuous phase material.
Potassium muds are the most widely accepted water mud system for drilling
water sensitive shales. K+ ions attach to clay surfaces and lend stability to shale
Table 1.1 Classification of Drilling Muds
Class

Description

Fresh water
mudsa

pH from 7 to 9.5, include spud muds, bentonite-containing muds,
phosphate-containing muds, organic thinned muds (red muds,

lignite muds, lignosulfonate muds), organic colloid muds
Water-based drilling muds that repress hydration of clays (lime
muds, gypsum muds, sea water muds, saturated salt water muds)
Contain less than 3-6% of solids. Most contain an organic polymer
Oil in water and water in oil (reversed phase, with more than 5%
water)
Contain less than 5% water; mixture of diesel fuel and asphalt

Inhibited mudsa
Low-solids mudsb
Emulsions
OBMs
a Dispersed

systems.
systems.

b Nondispersed


1.1 Classification of muds

exposed to drilling fluids by the bit. The ions also help hold the cuttings together,
minimizing dispersion into finer particles. Potassium chloride, KCl, is the most
widely used potassium source. Others are potassium acetate, potassium carbonate,
potassium lignite, potassium hydroxide, and potassium salt of partially hydrolyzed
poly(acrylamide) (PHPA). For rheology control, different types of polymers are used,
for example, xanthan gum and PHPA. For fluid loss control, mixtures of starch and
polyanionic cellulose (PAC) are often used. Carboxymethyl starch, hydroxypropyl
starch, carboxymethyl cellulose (CMC), and sodium poly(acrylate) are also used.

PHPA is widely used for shale encapsulation.
Salt water muds contain varying amounts of dissolved sodium chloride (NaCl) as
a major component. Undissolved salt may also be present in saturated salt muds to
increase density or to act as a bridging agent over permeable zones. Starch and starch
derivatives for fluid loss control and xanthan gums for hole cleaning are among the
few highly effective additives for salt water muds.
Sea water mud is a WBM designed for offshore drilling whose make-up water
is taken from the ocean. Sea water has a relatively low salinity, containing about
3-4% of NaCl, but has a high hardness because of Mg+2 and Ca+2 ions. Hardness
is removed from sea water by adding NaOH, which precipitates Mg+2 as Mg(OH)2
and by adding Na2 CO3 , which removes Ca+2 as CaCO3 . Mud additives are the same
as those used in fresh water muds [4]:
•
•
•
•
•
•

bentonite clay,
lignosulfonate,
lignite,
CMC, or
PAC, and
caustic soda.

Xanthan gum may also be used in place of bentonite. Silicate-mud is a type of
shale-inhibitive water mud that contains sodium or potassium silicate as the inhibitive
component. High pH is a necessary characteristic of silicate muds to control the
amount and type of polysilicates that are formed. The pH of the mud is controlled

by addition of NaOH (or KOH) and the appropriate silicate solution. Silicate anions
and colloidal silica gel combine to stabilize the wellbore by sealing microfractures,
forming a silica layer on shales and possibly acting as an osmotic membrane, which
can produce in-gauge holes through troublesome shale sections that otherwise might
require an oil mud.
Lime mud is a type of WBM that is saturated with lime, Ca(OH)2 , and has excess,
undissolved lime solids maintained in reserve. Fluid loss additives include starch,
hydroxypropyl starch, CMC, or PAC [4].

1.1.1 DISPERSED NONINHIBITED SYSTEMS
Drilling fluids used in the upper hole sections are referred to as dispersed noninhibited systems. They are formulated from fresh water and may contain bentonite. The

3


4

CHAPTER 1 Drilling muds

Table 1.2 Classification of Bentonite Fluid Systems
Solid-Solid
Interactions

Inhibition
Level

Dispersed
Dispersed

Noninhibited

Inhibited

Nondispersed
Nondispersed

Noninhibited
Inhibited

Drilling Fluid Type
Fresh water clay NaCl <1%, CaCl2 , <120 ppm
Saline fluids, Na+ , Ca2+ salt, saturated salt, gypsum,
lime
Fresh water low-solids muds
Salt and polymer fluids

classification of bentonite-based muds is shown in Table 1.2. The flow properties are
controlled by a flocculant or thinner, and the fluid loss is controlled with bentonite
and CMC.

1.1.2 PHOSPHATE-TREATED MUDS
Phosphates are effective only in small concentrations. The mud temperature must be
less than 55 ◦ C. The salt contamination must be less than 500 ppm sodium chloride.
The concentration of calcium ions should be kept as low as possible. The pH should
be between 8 and 9.5. Some phosphates may decrease the pH, so adding more NaOH
is required.

1.1.3 LIGNITE MUDS

Lignite muds are high-temperature resistant up to 230 ◦ C. Lignite can control
viscosity, gel strength, and fluid loss. The total hardness must be lower than 20 ppm.

1.1.4 QUEBRACHO MUDS
Quebracho is a natural product extracted from the heartwood of the Schinopsis trees
that grow in Argentina and Paraguay. Quebracho is a well characterized polyphenolic
and is readily extracted from the wood by hot water. Quebracho is widely used as a
tanning agent. It is also used as a mineral dressing, as a dispersant in drilling muds,
and in wood glues. Quebracho is commercially available as a crude hot water extract,
either in lump, ground, or spray-dried form, or as a bisulfite treated spray-dried
product that is completely soluble in cold water. Quebracho is also available in a
bleached form, which can be used in applications where the dark color of unbleached
quebracho is undesirable [5].
Quebracho-treated fresh water muds were used in shallow depths. It is also
referred to as red mud because of the deep red color. Quebracho acts as a thinner.
Poly(phosphate)s are also added when quebracho is used. Quebracho is active at low
concentrations and consists of tannates.


1.1 Classification of muds

1.1.5 LIGNOSULFONATE MUDS
Lignosulfonate fresh water muds contain ferrochrome lignosulfonate for viscosity
and gel strength control. These muds are resistant to most types of drilling contamination because of the thinning efficiency of the lignosulfonate in the presence of large
amounts of salt and extreme hardness.

1.1.6 LIME MUDS
Lime muds contain caustic soda, an organic thinner, hydrated lime, and a colloid
for filtrate loss. From this a pH of 11.8 can result, with 3-20 ppm calcium ions in
the filtrate. Lime muds exhibit low viscosity, low gel strength, and good suspension
of weighting agents. They can carry a larger concentration of clay solids at lower
viscosities than other types of mud. At high temperatures, lime muds present a danger

of gelation.

1.1.7 SEA WATER MUDS
The average composition of sea water is shown in Table 1.3. Sea water muds have
sodium chloride concentrations above 10,000 ppm. Most of the hardness in sea
water is caused by magnesium. Sea water muds are composed of bentonite, thinner
(lignosulfonate or lignosulfonate with lignite), and an organic filtration control agent.

1.1.8 NONDISPERSED NONINHIBITED SYSTEMS
In nondispersed systems no special agents are added to deflocculate the solids in the
fluid. The main advantages of these systems are the higher viscosities and the higher
yield point-to-plastics viscosity ratio. These alterated flow properties provide a better
cleaning of the borehole, allow a lower annular circulating rate, and minimize the
washout of the borehole.

1.1.9 LOW-SOLIDS FRESH WATER MUDS
Clear fresh water is the best drilling fluid in terms of penetration rate. Therefore,
it is desirable to achieve a maximal drilling rate using a minimal amount of solid
Table 1.3 Composition of Sea Water
Component

Concentration/(ppm)

Sodium
Potassium
Magnesium
Calcium
Chloride
Sulfate

10,500
400
300
400
19,000
3000

5


6

CHAPTER 1 Drilling muds

additives. Originally, low-solids mud formulations were used in hard formations, but
they now also tend to find use in other formations. Several types of flocculants are
used to promote the settling of drilled solids by flocculation.

1.1.10 VARIABLE DENSITY FLUIDS
Variable density fluids are those that having a density that varies as a function of
pressure into the subterranean formation. Such a fluid comprises a base fluid and a
portion of elastic particles.
The presence of the elastic particles in a variable density fluid allows the density
of the variable density fluid to vary as a function of pressure. For instance, as
the elastic particles encounter higher downhole pressures, they compress, thereby
lowering their volume. The reduction in the volume of the elastic particles in turn
increases the density of the variable density fluid.
When the elastic particles are fully compressed, the density increases considerably. The increase in volume of the elastic particles in turn reduces the overall
density of the variable density drilling fluid. The resulting change in density may be
sufficient to permit the return of the variable density fluid through the riser to the

surface without any additional pumps or subsurface additives [6].
The elastic particles can be a copolymer of styrene and divinylbenzene, a
copolymer of styrene and acrylonitrile, or a terpolymer of styrene, vinylidene
chloride, and acrylonitrile [6].

1.1.11 GAS-BASED MUDS
Although natural gas (methane) exhaust or other combustion gases can be used, air is
most common in such drilling fluids. Air is used to produce the so called foam muds
in which air bubbles are surrounded by a film of water containing a foam-stabilizing
substance or film-strengthening materials, such as organic polymers or bentonite.
This type of mud is not recirculated and is particularly used for reduced-pressure
drilling to improve the hole stability in caving formations. However, this type of mud
has some limitations with respect to drilling water producing or wet formations, as
well as a limited salt tolerance.

1.1.12 DRILL-IN FLUIDS
After drilling a well to the total depth, it is a normal practice to replace the drilling
mud with a completion fluid. This fluid is a clean, solids-free, or acid soluble,
non-damaging formulation, intended to minimize reductions in permeability of the
producing zone. Prior to producing from the formation, it is usually necessary to
cleanup what is left by the original mud and the completion fluid, by breaking and
degrading the filter cake with an oxidizer, enzyme, or an acid solution.
Nowadays, many wells exploit the pay-zone formations horizontally and for
long distances. It is no longer practical in these wells to drill the pay-zone with


1.1 Classification of muds

conventional solids-laden muds as the extended cleanup process afterwards is
much more difficult. Consequently, the modern generation of drill-in fluids were

developed.

Heavy brine completion fluids
Drill-in fluids are drilling fluids used in drilling through a hydrocarbon producing
zone, also addressed as a pay-zone [7]. Completion fluids are fluids used in completing or working over a well. Completion operations normally include perforating
the casing and setting the tubing and pumps prior to, and to facilitate, initiation of
production in hydrocarbon recovery operations.
As the pay-zone is penetrated horizontally, these fluids must provide the multifunctional requirements of drilling fluids in addition to the non-damaging attributes
of completion fluids. In practice, the normal drilling mud is replaced with a drill-in
fluid just before the pay-zone is penetrated, and used until the end of the operations.
Choosing the right completion fluid is important because inappropriate fluids can
have a significant impact on a project, not only during completion operations and
well production startup, but also throughout the well’s productive life. Experience
has shown that some completion practices that work well in one location, but may
not work well in a different location.
The importance of using clear completion and workover fluids to minimize
formation damage is well recognized and the use of clear heavy brines as completion
fluids is now widespread [7].
Most heavy brines used by the oil and gas industry are calcium halide brines,
particularly calcium chloride or calcium bromide brines, or formate brines. However, halide brines can cause structural failure in corrosion resistant alloys, and
chloride and bromide brines in particular are known to cause pitting corrosion
and stress corrosion cracking of corrosion resistant alloys if oxygen or carbon
dioxide is present. In contrast, formate brines do not cause such corrosion and
cracking but are more costly to purchase and have some solubility problems at high
density.
A phosphate based heavy brine drill-in or completion fluid has been described
[7]. The fluid is prepared with a phosphate brine, preferably consisting essentially of
water with phosphates dissolved therein, preferably in a quantity ranging from about
1.2-2.4 kg l−1 .
Such a phosphate solution may be economically obtained from waste product

from a sewage treatment plant, for example. This phosphate solution in turn is
blended with water, preferably fresh water although sea water might alternatively
be used, in a quantity such that the phosphate solution comprises more or less of the
blend or even approximately half of the blend.
Also, corrosion inhibitors and clay inhibitors may be added to the blend, although
the fluid is less corrosive without inhibitors than calcium halide brines. Non-amine
based corrosion inhibitors designed to prevent oxygen corrosion in monovalent brines
are most effective [7].

7


8

CHAPTER 1 Drilling muds

1.2 MUD COMPOSITIONS
Commercial products are listed in the literature. These include bactericides, corrosion
inhibitors, defoamers, emulsifiers, fluid loss and viscosity control agents, and shale
control additives [8–12].

1.2.1 INHIBITIVE WATER-BASED MUDS
Minimizing the environmental impact of the drilling process is a highly important
part of drilling operations to comply with environmental regulations that have
become stricter throughout the world. In fact, this is a mandatory requirement for
the North Sea sector. The drilling fluids industry has made significant progress
in developing new drilling fluids and ancillary additives that fulfill the increasing
technical demands for drilling oil wells. These additives have very little or no adverse
effects on the environment or on drilling economics.
New drilling fluid technologies have been developed to allow the continuation

of oil-based performance with regard to formation damage, lubricity and wellbore
stability aspects and thus penetration rates. These aspects were greatly improved by
incorporating polyols or silicates as shale inhibitors in the fluid systems.
Polyols based fluids contain a glycol or glycerol as a shale inhibitor. These polyols
are commonly used in conjunction with conventional anionic and cationic fluids to
provide additional inhibition of swelling and dispersing of shales. They also provide
some lubrication properties.
Sodium silicates or potassium silicates are known to provide levels of shale
inhibition comparable to that of OBMs. This type of fluids is characterized by a
high pH (>12) for optimum stability of the mud system. The inhibition properties of
such fluids are achieved by the precipitation or gelation of silicates on contact with
divalent ions and lower pH in the formulation, providing an effective water barrier
that prevents hydration and dispersion of the shales.

1.2.2 WATER-BASED MUDS
These muds have water as the continuous phase. Water may contain several dissolved substances. These include alkalies, salts and surfactants, organic polymers in
colloidal state, droplets of emulsified oil, and various insoluble substances, such as
barite, clay, and cuttings in suspension.
The mud composition selected for use often depends on the dissolved substances
in the most economically available make-up water or on the soluble or dispersive
materials in the formations to be drilled. Several mud types or systems are recognized
and described in the literature such as:
•
•
•
•

spud muds,
dispersed/deflocculated muds,
lime muds,

gypsum muds,


1.2 Mud compositions

•
•
•
•
•

salt water muds,
nondispersed polymer muds,
inhibitive potassium muds,
cationic muds, and
mixed metal hydroxide muds.

Despite their environmental acceptance, conventional WBMs exhibit major
deficiencies relative to OBMs/pseudo oil-based drilling muds (POBMs) with regard
to their relatively poor shale inhibition, lubricity, and thermal stability characteristics.
To overcome those deficiencies, specific additives may, however, be added into the
WBM compositions to deliver properties close to OBMs/POBMs, performance while
minimizing the environmental impact.
Consequently, to meet the new environmental regulations while extending the
technical performance of water-based drilling fluids, a new generation of water-based
fluids, also called inhibitive drilling fluids was developed to compete against OBMs.
Also, to minimize the formation damage, new types of non-damaging drilling fluids,
called drill-in fluid, have been developed to drill the pay-zone formations.
Components for WBMs are shown in Table 1.4. Various methods for the
modification of lignosulfonates have been described, for example, by condensation

with formaldehyde [19] or modification with iron salts [20]. It has been found
that chromium-modified lignosulfonates, as well as mixed metal lignosulfonates of
chromium and iron, are highly effective as dispersants and therefore are useful in
controlling the viscosity of drilling fluids and in reducing the yield point and gel
strength of the drilling fluids. Because chromium is potentially toxic, its release into
the natural environment and the thereof is continuously being reviewed by various
government agencies around the world.
Therefore, less toxic substitutes are desirable. Less toxic lignosulfonates are
prepared by combining tin or cerium sulfate and an aqueous solution of calcium
lignosulfonate, thereby producing a solution of tin or cerium sulfonate and a calcium
sulfate precipitate [21].

Compositions with improved thermal stability
To avoid the problems associated with viscosity reduction in polymer-based aqueous
fluids, formates, such as potassium formate and sodium formate are commonly added
Table 1.4 Water-Based Drilling Muds
Compound

References

Glycol-based
Alkali silicates
Poly(acrylamide), carboxymethyl cellulose
Carboxymethyl cellulose, zinc oxide
Acrylamide copolymer, poly(propylene
glycol) (PPG) (water-based mud)

[13]
[14, 15]
[16]

[17]
[18]

9


10

CHAPTER 1 Drilling muds

Table 1.5 Apparent Viscosity Before and
After Rolling [22]
Composition

Before
η/(cP)

After
η/(cP)

Brine/XC
Brin/PA
Brine/Filtercheck
Brine/FLC/XC
Brine/FLC/PA
Brine/XC/CLAYSEAL
XC/PA
XC/PA/FLC
XC/PA/FLC/CLAYSEAL
XC/PA/FLC/CLAYSEAL/Barite

13
8.5
4
16
14.6
12.5
30
38.5
34
38.5

3
6
4
10.5
9
3
28.5
16.5
28
38.5

to the fluids to enhance their thermal stability. However, this technology of using the
formates is very expensive. The thermal stability of polymer-based aqueous fluids
can be improved without the need of using formates [22].
The stability of a wellbore treatment fluid may be maintained at temperatures
up to 135-160 ◦ C (275-325 ◦ F). Various poly(saccharide)s may be included in
the fluid. The apparent viscosities of drilling fluids containing xanthan gum and
poly(acrylamide) (PAM) before and after rolling at 120 ◦ C are shown in Table 1.5.

Shale encapsulator
A shale encapsulator is added to a WBM in order to reduce the swelling of the
subterranean formation in the presence of water. A shale encapsulator should be at
least partially soluble in the aqueous continuous phase in order to be effective.
A conventional encapsulator is a quaternary PAM, which is preferably a quaternized poly(vinyl alcohol). Suitable examples of anions that are useful include
halogen, sulfate, nitrate, formate, etc. [23].
By varying the molecular weight and the degree of amination, a wide variety of
products can be tailored. It is possible to create shale encapsulators for the use in
low salinity, including fresh water [23]. The repeating units of quaternized etherified
poly(vinyl alcohol) and quaternized PAM are shown in Figure 1.1.

Membrane formation
In order to increase the wellbore stability, it is possible to provide formulations for
water-based drilling fluids, which can form a semi-permeable osmotic membrane
over a specific shale formation [24]. This membrane allows a comparatively free
movement of water through the shale, but it significantly restricts the movement of
ions across the membrane and thus into the shale.


1.2 Mud compositions

H

H

C

C

H

O

CH 3
N+

CH 3 X−

CH 3

H

H

C

C
C

H
O

CH 3
N

N+

H

CH 3

CH 3 X−

FIGURE 1.1
Quaternized etherified poly(vinyl alcohol) and quaternized poly(acrylamide) [23].

The method of membrane formation involves the application of two reactants to
form in situ a relatively insoluble Schiff base, which deposits at the shale as a polymer
film. This Schiff base coats the clay surfaces to build a polymer membrane.
The first reactant is a soluble monomer, oligomer, or polymer with ketone
or aldehyde or aldol functionalities or precursors to those. Examples are carbon
hydrates, such as dextrin, linear of branched starch. The second reactant is a primary
amine. These compounds are reacting by a condensation reaction to form an insoluble
crosslinked polymerized product. The formation of a Schiff base is shown in
Figure 1.2.
Figure 1.2 illustrates the reaction of a dextrine with a diamine, but other primary
amines and poly(amine)s will of course react in the same way. Long chain amines,
diamines, or poly(amine)s with a relatively low amine ratio may require supplemental
pH adjustment using materials such as sodium hydroxide, potassium hydroxide,
sodium carbonate, potassium carbonate, or calcium hydroxide [24]. The Schiff base
formed in this way must be essentially insoluble in the carrier brine in order to deposit
a sealing membrane on the shale during drilling of a well.
By carefully selecting the primary polymer and the crosslinking amine, the
relative concentrations of these components, together with the adjustment of pH,
crosslinking and polymerization and precipitation of components occurs which
effectively forms an osmotically effective membrane on or within the face of the
exposed rock.
The polymerization and precipitation of the osmotic membrane on the face of the
exposed rock significantly retards water or ions from moving into or out of the rock

formation, typically shale or clay. The ability to form an osmotic barrier results in an
increased stability in the clays or minerals, which combine to make the rock through
which the borehole is being drilled [24].

1.2.3 OIL-BASED DRILLING MUDS
They have oil as the continuous phase. The oil most often selected is diesel oil,
mineral oil, and low toxicity mineral oil. Because some water will always be present,
the OBM must contain water-emulsifying agents. If water is purposely added (for
economical reasons), the OBM is called an invert emulsion mud. Various thickening

11


12

CHAPTER 1 Drilling muds

OH

OH
O

H 2N

NH2 O

HO

OH
CH3

OH

CH3

CH3

HO

HO

OH
HO

OH
OH

OH

OH

OH
N

N

HO

OH
OH

CH3
HO

OH

HO

CH3
HO

OH

CH3

OH

OH

FIGURE 1.2
Formation of a Schiff base [24].

and suspending agents as well as barite are added. The emulsified water may contain
alkalies and salts.
Due to their continuous phase, OBMs are known to provide unequaled performance attributes with respect to the rate of penetration, shale inhibition, wellbore
stability, high lubricity, high thermal stability, and high salt tolerance. However,
they are subjected to strict environmental regulation regarding their discharge and
recycling.
OBMs are being replaced now by synthetic muds. Diesel oil is harmful to the
environment, particularly to the marine environment in offshore applications. The

use of palm oil derivatives could be considered as an alternative oil-based fluid that
is harmless to the environment [25]. Hydrated castor oil can be used as a viscosity
promoter instead of organophilic quaternized clays [26].
An OBM can be viscosified with maleated ethylene-propylene elastomers [27].
The elastomers are ethylene-propylene copolymers or ethylene-propylene-diene
terpolymers. The maleated elastomers are far more effective oil mud viscosifiers
than the organophilic clays used. On the other hand, specific organophilic clays can
provide a drilling fluid composition less sensitive to high temperatures [28].


1.2 Mud compositions

Poly-α-olefins (PAOs) are biodegradable and nontoxic to marine organisms. They
also meet viscosity and pour point specifications for the formulation into OBMs [29].
The hydrogenated dimer of 1-decene [30] can be used instead of conventional organic
fluids, as can n-1-octene [31].

Poly(ether)cyclicpolyols
Poly(ether)cyclicpolyols possess enhanced molecular properties and characteristics
and permit the preparation of enhanced drilling fluids that inhibit the formation of
gas hydrates; prevent shale dispersion; and reduce the swelling of the formation to
enhance wellbore stability, reduce fluid loss, and reduce the filter cake thickness.
Drilling muds incorporating the poly(ether)cyclicpolyols are substitutes for
OBMs in many applications [32–36]. Poly(ether)cyclicpolyols are prepared by
thermally condensing a polyol, for example, glycerol to oligomers and cyclic ethers.

Emulsifier for deep drilling
Two major problems are encountered when using OBMs for drilling very deep wells
[37]. The first is a problem with the stability of the emulsions with temperature. The
emulsifying agents that are stabilizing the emulsions must maintain water droplets in

an emulsion up to temperatures of 200 ◦ C.
If the emulsion separates by coalescence of the water droplets, the fluid loses its
rheological properties. The second is an environmental problem. The emulsification
agents must not only be effective, but also as nontoxic as possible.
Fatty acid amides consisting of N-alkylated poly(ether) chains are used as
emulsifiers. For those the term polyalkoxylated superamides has been coined [38].
As a cosurfactant, tall oil fatty acids or their salts can be used.

Biodegradable composition
In compositions of oil-based biodegradable drilling fluids biodegradability can be
imparted. There, the main oil phase component is a mixture of methyl esters from
biodegradable fatty acids. A typical formulation of a biodegradable drilling fluid is
shown in Table 1.6.

Electric conductive nonaqueous mud
A wellbore fluid has been developed that has a nonaqueous continuous liquid phase
that exhibits an electrical conductivity increased by a factor of 104 to 107 compared
with conventional invert emulsion. 0.2-10% by volume of carbon black particles and
emulsifying surfactants are used as additives. Information from electrical logging
tools, including measurements while drilling can be obtained [40].

Water removal
Water can be removed from OBMs by the action of magnesium sulfate [41].

13


14

CHAPTER 1 Drilling muds

Table 1.6 Biodegradable Drilling Fluid [39]
Compound
Soybean methylate
D-Limonene
2,6-Di-tert-butyl-p-cresol
Hydrogenated castor oil
Fatty acid salts
Magnesium oxide
NaCl brine
Organophilic clay
Succinimide copolymer
Sodium poly(acrylate)
Citric acid
Barium sulfate

Amount / (%)
55
1
0.1
0.3
3
1
26
0.5
0.1
0.1
0.1
0.1

to
to
to
to
to
to
to
to
to
to
to
to

70
5
0.5
1
6
3
30
1
0
0
1.5
25

Function
Oil component
Pour point depressant
Antioxidant

Oil component
Puffer
In situ soap former
Aqueous component
Viscosifier
0.5 fluid loss agent
0.5 fluid loss agent
Puffer
Weighting agent

1.2.4 SYNTHETIC MUDS
Synthetic muds are expensive. Two factors influence the direct cost: the costs per
barrel and mud losses. Synthetic muds are the technical equivalent of OBMs when
drilling intermediate hole sections. They are technically superior to all water-based
systems when drilling reactive shales in directional wells. However, with efficient
solids-control equipment, optimized drilling, and good housekeeping practices, the
cost of the synthetic mud can be brought to a level comparable with OBM [42].
POBMs or synthetic OBMs are made on the same principle as OBMs. They
have been developed to maintain the performance characteristics of OBMs while
reducing their environmental impact. The objective behind the design of these drilling
fluids is to exchange the diesel oil or mineral oil base with an organic fluid which
exhibits a lower environmental impact. The organic fluids used are esters, polyolefins,
acetal, ether, and linear alkyl benzenes. As with OBMs, POBMs may contain various
ingredients, such as thickening and suspending agents, emulsifying agents as well as
weighting agents.
POBMs were developed to technically maintain the performance characteristics
of OBMs while reducing their environmental impact. They are, however, not as stable
as OBMs depending upon the continuous phase. From environmental perspective, the
current legislation is becoming as strict for POBMs as for OBMs. The mud selection
process is based on the mud’s technical performance, environmental impact, and

financial impact.
Skeletally isomerized linear olefins exhibited a better high-temperature stability
in comparison with a drilling fluid prepared from a conventional PAO. The fluid loss
properties are good, even in the absence of a fluid loss additive [43–46]. Although
normal α-olefins are not generally useful in synthetic hydrocarbon-based drilling
fluids, mixtures of mostly linear olefins are minimally toxic and highly effective as
the continuous phase of drilling fluids [44, 47].


1.2 Mud compositions

Acetals as mineral oil substitutes exhibit good biodegradability and are less toxic
than mineral oils [48, 49]. Acrylic acid (AA) salts are formed by the neutralization
reaction of AA in aqueous solution [50].
Alginates are hydrocolloids, which are extracted from brown marine microalgae.
Water-soluble alginates are prepared as highly concentrated, pumpable suspensions
in mixtures of propylene glycol and water by using hydroxypropylated guar gum
in combination with carboxymethylated cellulose, which is used as a suspending
agent [51].

1.2.5 INVERTED EMULSION DRILLING MUDS
Inverted emulsion muds are used in 10-20% of all drilling jobs. Historically, first
crude oils, then diesel oils and mineral oils, have been used in formulating invert
drilling fluids. Considerable environmentally damaging effects may occur when the
mud gets into the sea. Drilling sludge and the heavy mud sink to the seabed and partly
flow with the tides and sea currents to the coasts. All of these hydrocarbons contain
no oxygen and are not readily degraded [52].
Because of problems of toxicity and persistence, which are associated with these
oils, in particular for offshore use, alternative drilling oils have been developed.
Examples of such oils are fatty acid esters and branched chain synthetic hydrocarbons

such as PAOs. Fatty acid ester-based oils have excellent environmental properties, but
drilling fluids made with these esters tend to have lower densities and are prone to
hydrolytic instability.
PAO-based drilling fluids can be formulated to high densities and have good
hydrolytic stability and low toxicity. They are, however, somewhat less biodegradable
than esters. Further, they are expensive. The fully weighted, high-density fluids tend
to be overly viscous [31].

Esters
Esters of C6 to C11 monocarboxylic acids [53–57], acid-methyl esters [58], and
polycarboxylic acid esters [59], as well as oleophilic monomeric and oligomeric
diesters [60], have been proposed as basic materials for inverted emulsion muds.
Natural oils are triglyceride ester oils [61] and are similar to synthetic esters. Diesters
also have been proposed [60, 62–65].

Acetals
Acetals and oleophilic alcohols or oleophilic esters are suitable for the preparation
of inverted emulsion drilling muds and emulsion drilling muds. They may replace
the base oils, diesel oil, purified diesel oil, white oil, olefins, and alkyl benzenes [52,
66]. Examples are isobutyraldehyde, di-2 -ethylhexyl acetal, dihexyl formal. Also
mixtures with coconut alcohol, soya oil, and α-methyldecanol are suitable. Some
aldehydes are shown in Figure 1.3.
Inverted emulsion muds are more advantageous in stable, water sensitive formations and in inclined boreholes. They are stable up to very high temperatures and

15


16

CHAPTER 1 Drilling muds

O

O
CH

CH

C

O

H
Cinnamaldehyde

CH

H

2-Furaldehyde

CH 3
H3C

CH 2 C

O
CH 2 C
H

Isobutyraldehyde

FIGURE 1.3
Aldehydes.

provide excellent corrosion protection. Disadvantages are the higher price, the greater
risk if gas reservoirs are bored through, the more difficult handling for the team at
the tower, and greater environmental problems.
The high setting point of linear alcohols and the poor biologic degradability of
branched alcohols limit their use as an environment-friendly mineral oil substitute.
Higher alcohols, which are still just somewhat water-soluble, are eliminated for use
in offshore muds because of their high toxicity to fish. Esters and acetals can be
degraded anaerobically on the seabed.
This possibility minimizes the environmentally damaging effect on the seabed.
When such products are used, rapid recovery of the ecology of the seabed takes
place after the end of drilling. Acetals, which have a relatively low viscosity and
in particular a relatively low setting point, can be prepared by combining various
aldehydes and alcohols [52, 67].

Anti-settling properties
Ethylene-AA copolymer neutralized with amines such as triethanolamine or Nmethyl diethanolamine enhances anti-settling properties [68, 69].

Glycosides
The advantage of using glycosides in the internal phase is that much of the concern
for the ionic character of the internal phase is no longer required. If water is limited
in the system, the hydration of the shales is greatly reduced.
The reduced water activity of the internal phase of the mud and the improved
efficiency of the shale is an osmotic barrier if the glycoside interacts directly with
the shale. This helps to lower the water content of the shale, thus increasing rock
strength, lowering effective mean stress, and stabilizing the wellbore [70].

Methyl glucosides also could find applications in water-based drilling fluids and
have the potential to replace OBMs [71]. The use of such a drilling fluid could


1.2 Mud compositions

Table 1.7 Other Materials for Inverted Emulsion Drilling Fluids
Base Material

References

Ethers of monofunctional alcohols
Branched didecyl ethers
α-Sulfofatty acids
Oleophilic alcohols
Oleophilic amides
Hydrophobic side chain poly(amide)s from N,N-didodecylamine
and sodium poly(acrylate) or poly(acrylic acid)
Poly(ether amine)
Phosphate ester of a hydroxy polymer

[72]
[73, 74]
[75]
[76–78]
[79]
[80]
[81]
[82]

reduce the disposal of oil-contaminated drilling cuttings, minimize health and safety
concerns, and minimize environmental effects.

Miscellaneous
Other base materials proposed are listed in Table 1.7. Quaternary oleophilic esters
of alkylolamines and carboxylic acids improve the wettability of clay [83, 84].
Nitrates and nitrites can replace calcium chloride in inverted emulsion drilling
muds [85].

Reversible phase inversion
Invert emulsion fluids have been developed in which the emulsion can be readily
and reversibly converted from a water-in-oil type emulsion to an oil-in-water type
emulsion. The essential ingredient is an amine based surfactant as additive. The
amine surfactant may be diethoxylated tallow amine, diethoxylated soya amine, or
N-tallow-1,3-diaminopropane [86].
The invert emulsion is admixed with an acid that is functionally able to protonate
the amine surfactant. When sufficient quantities of the acid are utilized, the invert
emulsion is converted so that the oleaginous fluid becomes the discontinuous phase
and the non-oleaginous fluid becomes the continuous phase.
The conversion of the phases is reversible so that upon addition of a base capable
of deprotonating the protonated amine surfactant, a stable invert emulsion in which
the oleaginous liquid becomes the continuous phase and the non-oleaginous fluid
become the discontinuous phase can be formed [86].
In other words, when the drilling fluid is converted into an oil-in-water type
emulsion, solids, now substantially water-wet, may now be separated from the fluid
by gravity or mechanical means for further processing or disposal. The fluid may then
be mixed with a base, the base being functionally able to deprotonate the protonated
amine surfactant.

17

18

CHAPTER 1 Drilling muds

The base should be in sufficient quantities so as to convert the oil-in-water type
emulsion formed upon the addition of acid, back to a water-in-oil emulsion. The
resulting water-in-oil emulsion may then be used as it is or reformulated into a
drilling fluid suitable for the drilling conditions in another well [86].

1.2.6 FOAM DRILLING
While drilling low-pressure reservoirs with nonconventional methods, it is common
to use low-density dispersed systems, such as foam, to achieve underbalanced conditions. To choose an adequate foam formulation, not only the reservoir characteristics
but also the foam properties need to be taken into account.
Parameters such as stability of foam and interactions between rock-fluid and
drilling fluid-formation fluid are among the properties to evaluate while designing
the drilling fluid [87].
A foaming composition having a specific pH and containing an ionic surfactant
and a polyampholytic polymer whose charge depends on the pH is circulated in a
well. By varying the pH, it is possible to destabilize the foam in such a way as to
more easily break the foam back at the surface and possibly to recycle the foaming
solution [88].

1.2.7 CHEMICALLY ENHANCED DRILLING
Chemically enhanced drilling offers substantial advantages over conventional methods in carbonate reservoirs. Coiled tubing provides the perfect conduit for chemical
fluids that can accelerate the drilling process and provide stimulation while drilling
[89]. The nature of the chemical fluids is mainly acid that dissolves or disintegrates
the carbonate rock.

Temperature and salinity effects
Coiled tubing applications include drilling operations, hydraulic fracturing, well
completions, removing sand or fill from wellbore, and other applications that involve
pumping fluids at high temperatures and high salinity. Because of curvature effects in
coiled tubing, huge pressure losses occur, limiting the maximum flow rate achieved.
By adding specific chemicals known as friction reducers or drag reducers to the
fluids, these pressure losses can be minimized to a great extent.
Only a few number of studies have been reported that relate to temperature and
salinity effects on drag reduction in fluids flowing through coiled tubing [90].
An experimental study of two commonly used drag reducers (ASP-700 and ASP820) flowing through coiled tubing with different salinities and temperatures has
been presented [90]. Both small-scale and large-scale flow loops have been used. The
small-scale flow loop includes a 0.5 in. outside-diameter smooth coiled tubing, while
the large-scale flow loop includes 2 3/8 in. rough coiled tubings. Elevated temperature
tests and salinity tests were conducted using optimum concentrations of drag reducers
in fresh water, 2% KCl, and synthetic seawater.


1.3 Additives

Correlations were developed that can predict the drag reduction at different
salinities and temperatures. The developed correlations show a reasonable agreement
with the experimental data [90].

1.2.8 SUPERCRITICAL CARBON DIOXIDE DRILLING
The efficiency of drilling operations can be increased using a drilling fluid material
that exists as supercritical fluid or a dense gas at temperature and pressure conditions
occurring in the drill site, such as carbon dioxide.
A supercritical fluid exhibits physical-chemical properties intermediate between
those of liquids and gases. Mass transfer is rapid with supercritical fluids. Their
dynamic viscosities are nearer to those in normal gaseous states.

In the vicinity of the critical point the diffusion coefficient is more than 10 times
that of a liquid. Carbon dioxide can be compressed readily to form a liquid. Under
typical borehole conditions, carbon dioxide is a supercritical fluid.
The viscosity of carbon dioxide at the critical point is only 0.02 c P, increasing
with pressure to about 0.1 c P at 70 MPa (about 10,000 psi). Because the diffusivity
of carbon dioxide is so high, and the rock associated with petroleum-containing
formations is generally porous, the carbon dioxide is quite effective in penetrating
the formation.
This penetration is beneficial. Carbon dioxide is commonly used to stimulate
the production of oil wells, because it tends to dissolve in the oil, reducing the oil
viscosity while providing a pressure gradient that drives the oil from the formation.
Carbon dioxide can be used to reduce mechanical drilling forces, to remove
cuttings, or to jet erode a substrate. Supercritical carbon dioxide is preferably
used with coiled-tube drilling equipment. The very low viscosity of supercritical
carbon dioxide provides efficient cooling of the drill head and efficient cuttings
removal.
Furthermore, the diffusivity of supercritical carbon dioxide within the pores of
petroleum formations is significantly higher than that of water, making jet erosion
using supercritical carbon dioxide much more effective than jet erosion using water.
Supercritical carbon dioxide jets can be used to assist mechanical drilling, for
erosion drilling, or for scale removal. Spent carbon dioxide can be vented to the
atmosphere, collected for reuse, or directed into the formation to aid in the recovery
of petroleum [91].

1.3 ADDITIVES

1.3.1 THICKENERS
A variety of compounds useful as thickeners is shown in Table 1.8. Subsequently, the
individual compounds are explained in detail.

19