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Section 6
Fracturing Fluids and Materials
Table of Contents
Fracturing Fluids and Materials .................................................................................................................6-3 Introduction............................................................................................................................................ 6-3 Topic Areas ............................................................................................................................................ 6-3 Learning Objectives ...............................................................................................................................6-3
Unit A: pH Control Agents ........................................................................................................................ 6-3 Unit A Quiz ............................................................................................................................................ 6-4 Unit B: Clay Control..................................................................................................................................6-5
Clay Characteristics................................................................................................................................6-5 Clay Control Additives...........................................................................................................................6-5 Unit B Quiz ............................................................................................................................................ 6-7
Unit C: Fluid Loss Control Additives........................................................................................................6-8 Fluid Loss Approaches...........................................................................................................................6-8 Fluid Loss Control Additives .................................................................................................................6-8 Unit C Quiz .......................................................................................................................................... 6-10
Unit D: Surfactants ..................................................................................................................................6-11 Surfactant Definition............................................................................................................................ 6-11
Surfactant Usage ..................................................................................................................................6-11 Surfactant Composition........................................................................................................................6-12 Surfactant Mechanisms ........................................................................................................................ 6-13 Blending of Surfactants........................................................................................................................6-14 Summary .............................................................................................................................................. 6-14 Unit D Quiz: Surfactants ...................................................................................................................... 6-15
Unit E: Gelling Agents.............................................................................................................................6-16 Water-Based Gelling Agents................................................................................................................6-16 Oil Gelling Agents ...............................................................................................................................6-18 Additional References .......................................................................................................................... 6-20 Unit E Quiz: Gelling Agents ................................................................................................................6-21
Unit F: Complexors/Crosslinkers.............................................................................................................6-22
Unit F Quiz...........................................................................................................................................6-25 Unit G: Breakers/Stabilizers ....................................................................................................................6-26 Breakers................................................................................................................................................6-26 Breaker Types ......................................................................................................................................6-26 Enzyme Breakers..................................................................................................................................6-26 Oxidizing Breaker ................................................................................................................................6-27 Acid Breakers.......................................................................................................................................6-28 Gelled-Oil Breakers..............................................................................................................................6-30 Breaker Activators................................................................................................................................6-30
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Stabilizers.............................................................................................................................................6-30 Unit G Quiz .......................................................................................................................................... 6-32
Unit H: Bactericides/Biocides..................................................................................................................6-33 Bacteria Conditions..............................................................................................................................6-33 Bacteria Types......................................................................................................................................6-33 Bactericides .......................................................................................................................................... 6-33
Additional References .......................................................................................................................... 6-34 Unit H Quiz .......................................................................................................................................... 6-35
Unit I: Conductivity Enhancers................................................................................................................6-36 SandwedgeXS ...................................................................................................................................... 6-36 Unit I Quiz............................................................................................................................................6-37
Answer Key ............................................................................................................................................. 6-38
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Fracturing Fluids and Materials
Fracturing Fluids and Materials
Introduction
Fracturing chemicals are used to make up the
fluid systems for stimulation treatments. A great
number of fracturing fluid systems is available
to the petroleum industry. The selection of a
fracturing fluid depends upon the particular formation to be treated and the tubular goods in
the well. Considerations in fluid selection are:
• the formation rock properties
• the formation fluid properties
• friction properties of the treating fluid
• fluid loss properties of the treating fluid
• proppant transport
Topic Areas
Chemical additives generally used in fracturing
can be grouped into nine classifications. The
following sections will explain these types and their uses:
• pH control agents
• Clay control agents
• Fluid loss control additives
• Surfactants
• Gelling agents and friction reducers
• Complexors and crosslinkers
• Breakers and stabilizers
• Bactericides
• Conductivity Enhancers
Learning Objectives
Upon completion of this section, you will be
familiar with:
• Classifications and usage for chemicals
blended into fracturing fluids
• Reactions of these chemicals
• Actions that each chemical will have in a
formation
Unit A: pH Control Agents
Most aqueous based stimulation fluids contain a
nominal amount of chemicals (common acids
and bases) for the sole purpose of obtaining the
proper fluid pH. These chemicals are referred to
as pH control agents or buffers.
pH expresses the degree of acidity or basicity of
a solution. The pH scale extends from 0 to 14
(Figure 6.1). A pH of 7 is neutral (neither acidic,
nor basic). An acidic solution will have a pH
value lower than 7. If it is basic (or alkaline) it
will have a pH value above 7.
Acidic Neutral Basic
0 7 14
Table 6.1 - pH Scale
The pH scale is useful in evaluating solutions
which are slightly acidic or basic. A 0.1%solution of HCL will have a pH of 1, while a 1%
solution of caustic soda (NaOH) will have a pH
of 14. The strength of higher concentrations of
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hydrochloric acid (HCL) or caustic are
expressed as percent rather than pH. Measuring
pH is done with narrow range pH paper or pH
meters.
The pH of a fluid is a significant factor in
stimulation treatments because it controlsvariables such as crosslinker function,
temperature stability, iron control problems,
polymer hydration, clay control, and gel break.
Compatibility of stimulation fluids with the
formation is an important consideration since the
effect of fluid pH on clays and the resulting
formation permeability can be significant. Clay
and shale formations are best protected in a low
pH environment. Rates at which gelling agents
develop viscosity are a direct function of the pH
of the liquid system. Adjusting the pH of the
liquid system also controls bacteria. Commonly
used pH control additives include:
• sodium bicarbonate
• fumaric acid
• acetic acid
• formic acid
• sodium diacetate
• monosodium phosphate
• sodium carbonate
• sodium hydroxide.
pH control agents used to adjust pH are listed
along with their values:
STRONG ACID pH
Hydrochloric Acid 0-2
Hydrofloric Acid 0-2
WEAK ACID pH
HYG-3 (Furmaric Acid) 3.5-4
FE-1A (Acetic Acid) 2-4
WEAK BASE pH
K-34 (Sodium Bicarbonate) 8.5
K-35 (Sodium Carbonate) 10.5
STRONG BASE pH
NaOH (Caustic Soda) 14
Buffers are mixtures of acids and salts of these
acids and are resistant to pH change. By using a
buffer listed below, rather than an acid or base,
the fluid pH can be maintained even though
contaminants from formation water or other
sources tend to try and change it.
BUFFER pH
BA-2 1.5-3
BA-20 6-8.5
BA-40 / BA-40L 7-11
Unit A Quiz
Fill in the blanks with one or more words to check your progress in Unit A.
1. Clay and shales can best be protected in a ____________________ pH environment.
2. pH is a means of expressing the degree of ____________________ or ____________________of a
solution.
3. On the pH scale, ____________ is neutral.
4. Buffers are mixtures of ____________________ and _____________________ of these
____________________.
5. To maintain a pH of 10, you could use ________________ as a buffer.
Now, look up the suggested answers in the Answer Key at the back of this section.
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Unit B: Clay Control
Clay Characteristics
Clays are present in almost all oil and gas
bearing formations and their presence can cause
many problems in the production of
hydrocarbons, particularly where stimulation
processes are employed. The clay composition
and its location in the rock matrix can vary
extensively, thus complicating control and
treatment when clay minerals are present.
Where water-swelling clay is contacted by
foreign water in the formation, an increase in
clay swelling can reduce the size of flowchannels and decrease the flow capacity of the
rock. In addition, any appreciable change in the
swelling characteristic of the clay may cause
some of the clay to be detached from its original
position. Fine particles may be released which
can migrate with fluid flow, form bridges at flow
restrictions in the formation, and thus decrease
the effective permeability of the producing zone.
The clays most commonly found in
hydrocarbon-producing formations are smectite,illite, mixed layer, kaolinite and chlorite. Clays
have a negative charge on their surfaces.
Clay Damage method*
Smectite Swelling
Mixed Layer Swelling
Illite Migrating
Kaolinite Migrating
Chlorite Migrating
* All clays swell to some degree, and they can all break
loose and migrate. One of these two processes will usuallybe dominant for any given clay.
To minimize the possibility of clay crystals or
packets of crystals breaking loose and migrating,
any water that may contact a clay-bearing
formation should contain a chemical that will
not alter the natural water retention
characteristics of the clay.
Clay Control Additives
Acids and Buffers
As discussed in the previous unit, pH can be
used to control formation clays. An acid or
buffering agent can protect clays best at a pH
range of 3 to 7.
Potassium Chlor ide (KCL), SodiumChloride (NaCl) and Clayfix (NH4Cl)
The main method of minimizing clay damage
through contact with fracturing fluids is by
adding a chemical that will not alter the natural
water retention characteristics of the clay.
Cations, such as potassium, sodium and
ammonium, possess the proper ionic size for
absorption onto clay platelets and are compatible
with most water based fracturing fluid systems.
The salts potassium chloride (KCL), sodium
chloride (NaCl) and ammonium chloride
(NH4Cl) are used to maintain the “status quo” of
clays to minimize permeability damage. Recentstudies have indicated that for maximum clay
stability through ion exchange, 7% KCL, 6%
NaCl or 5% NH4Cl is needed.
ClayFix II
CLAYFIX II is a liquid replacement for the
various salts used in aqueous fracturing
treatments. It offers an alternative to KCl, NaCl,
and CLAYFIX (NH4Cl) as a temporary clay
protection additive.
The primary application for CLAYFIX II is in
propped fracturing treatments. CLAYFIX II is
not recommended for matrix treatments. The
additive can be added to the mixing water while
batch mixing or it can be metered into the flow
stream before the other ingredients are added.
CLAYFIX II is compatible will all present LGC
formulations.
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NOTE: CLAYFIX II cannot be premixed in
LGC concentrates. This additive also is not a
substitute for permanent clay control additives,
such as salts.
Cla-Sta
®
Compounds
The Cla-Sta® compounds are cationic polymers
or oligomers that may be used with fracturing
fluids and acids to stabilize clays. They are most
effective if used in a “pre-pad” or thin fluid
pumped before the main fracture treatment and
become much less effective when blended with
other gelling agents. ClaSta Compounds can
even plug pore spaces if used above
recommended concentrations.
Cla-Sta®
XP
Cla-Sta® XP clay stabilizing agent is designed to
be resistant to both acid and chemical removal.
It is intended for use in formations with
permeability of 30 millidarcies (mD) or less but
is not limited to that permeability. Cla-Sta® XP
is an oligomer which provides clay and fines
control in most fracturing, acidizing, and gravel-
pack operations and is preferred over other Cla-
Sta products for formations with permeability
less than 30 millidarcies. Cla-Sta® XP is
compatible with many aqueous stimulationfluids and can be batch mixed into the base fluid
or continuously mixed at the blender. Cla-Sta®
XP is not a substitute for salts, such as KCl or NaCl and will not provide the immediate clay
protection needed during treatment.
Cla-Sta® FS
Cla-Sta® FS mineral fines and clay stabilizing
additive is a new polymer designed to stabilize
fines commonly produced from a variety of
formations. Cla-Sta® FS effectively stabilizes
mineral fines that do not respond to treatment
from conventional clay stabilizers. It is readily
adsorbed on the formation surfaces, reducing
their dislodgment or movement when exposed to
very high rates of fluid flow. By substantially
stabilizing mineral fine particles, solids
production, and permeability impairment caused
by fines, migration may be greatly reduced. This
fines stabilization is long lasting.
Hydrocarbons
One method to effectively control clay problems
is to not allow the formation to come into
contact with water. Oil-based fracturing fluids
do not allow water to be introduced into the
formation. Hydrocarbons such as diesel can be
blended with water based fluids to control leak
off into the fracture face and minimize water
contact.
Foams and Emulsions
Foams and emulsions have excellent fluid loss
properties resulting in the reduction of water
contact to the natural permeability of the
formation. An emulsion is a suspension of small
globules of one liquid in a second liquid with
which the first will not mix, like oil and water.
Foam is a suspension of gas bubbles inside a
liquid, like shaving cream. Foams and emulsions
also reduce the total water required to formulate
a fracturing fluid.
Methanol (Methyl Alcohol)
The addition of methanol to a fracturing fluid
reduces the fluid’s surface tension, thus reducing
the amount of water retained by the formation. It
also absorbs moisture on clay particles and helps
protect the clay from the swelling caused by
water base fluids. Both of these result in faster
cleanup and retained permeability.
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Fracturing Fluids and Materials
Unit B Quiz
Fill in the blanks with one or more words to check your progress in Unit B.
1. Clays are present in ________________ _______________ oil and gas bearing formations.
2. Clay swelling can reduce the size of ____________________ channels.
3. Released fine particles can reduce effective ____________________.
4. pH ranges at which clays can best be protected are from __________ to ___________.
5. Maximum protection from clay swelling can be achieved when using a concentration of
__________% potassium chloride (KCL), __________% sodium chloride (NaCl) or __________%
ammonium chloride (NH4CL).
6. ClayFix II is a ____________________ clay protection additive.
7. Cla-Sta® materials are most effective when added to a ________________-_________________.
8. Cla-Sta® materials should not be used above recommended concentrations because excess material
can cause ____________________ of the pore spaces.
9. One method to effectively control clay problems is not to let the formation come into contact with
____________________.
10. Foams and emulsions reduce the total ____________________ required to formulate a fracturing
fluid.
Now, look up the suggested answers in the Answer Key at the back of this section.
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Unit C: Fluid Loss Control Additives
In any fracturing operation, a portion of the fluid
in contact with the formation penetrates into the
pores and is lost as leak-off. The amount of fluid
lost in this way and the rate at which it is lost
has a pronounced effect on the shape of the
fracture. Fluid loss reduces the size of the
fracture as well as the fluid pressure inside the
fracture.
Fluid Loss Approaches
Fluid loss additives are required to function
across a wide range of pore size distributions,
such as low, medium or high permeability
sections. Another requirement is that a large
percentage of formation permeability needs to
be regained after being treated by the additive.
Different approaches have been taken to
establish fluid loss control. Traditionally, finely
powdered solids have been used to control fluid
loss. As the fluid moves into the pores of the
formation, the fluid loss additives build up on
the fracture face and form a filter cake. This
reduces fluid loss. Some of the solids are inert
while others go into solution and/or degrade.
Another approach to fluid loss control uses
liquid additives that deposit droplets along the
fracture fact to control the loss of fluid. A major
advantage of this approach is that no solids that
might impair productivity are left in the
formation or fracture.
Fluid Loss Control Additives
Water Based Fluids
WAC-9
WAC-9 is finely powdered sand. It is an
excellent fluid loss additive that can be used
with water, acid or oil based fluids. However,
since it is silica, it does not dissolve or degrade
over time.
WLC-4
WLC-4 is a particulate fluid loss additive
developed for use with water-based gelled
fracturing fluids at temperatures of 140° to
350°F. WLC-4 may be used to control leakoff in
formations up to around 50 md or with 100-
mesh sand to help control leakoff in natural
fractures. At temperatures above 140°F, the
additive degrades to low residue material in an
aqueous environment. The additive should be
applied at 20 to 50 lb/Mgal to aid leakoff
control.
WLC-5
WLC-5 is a fluid loss additive for use in aqueous
fluids. It contains an enzyme breaker that allows
it to be more degradable than other starch
additives such as Adomite Regain and WLC-4 at
low temperatures. WLC-4 does not contain this
enzyme breaker, and the enzyme breaker in
Adomite Regain is not as effective as the
breaker in WLC-5. Typical concentrationsusually range from 20 to 50 lb/Mgal. WLC-5
can be used at temperatures from 75° to 350°F
and permeabilities up to around 50 md.
WLC-6
WLC-6 is a non-damaging fluid-loss additive
that helps in reducing gel filter cakes, especially
from borate-crosslinked fluids. Ground to an
appropriate particle size for fracturing, it
remains solid long enough to function as a fluid-
loss additive, then dissolves in the produced water to ensure cleanup. As it dissolves, it
reduces the surface tension of the filter-cake
residue, helping to remove the filter cake and
improve fracture conductivity. WLC-6 is slowly
soluble in water and should be applied in low-to-
moderate temperature wells up to 150°F. WLC-
6 can also be used with FracPac treatments in
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formations with up to 300 md of permeability.
Use WLC-6 at concentrations of 25 to 50
lb/Mgal of fracturing fluid.
WLC-7
WLC-7 fluid loss additive, an organic solid, is a
finely ground powder that dissolves slowly in
water as the water temperature rises; therefore, it
can be cleaned up as water is produced from the
well. Because of its solubility, WLC-7 is non-
damaging. Laboratory tests indicate that WLC-7
helps reduce the potential damaging effects of
borate crosslinked gel filter cakes. WLC-7 can
be used in wells up to 180° F. It should be used
in concentrations from 25 – 50 lb/Mgal of
fracturing fluid. Laboratory tests show that
WLC-7 is beneficial up to 320 md.
Adomite® Aqua
Adomite®Aqua is an older fluid-loss additive for
use in water-based fracturing fluids and was
originally developed by Continental Oil
Company. It is currently manufactured by Nalco
Chemical Company and is available from all
service companies. It is compatible with most
water base gelling agents and testing has shown
some benefit in formations up to 200 md.
Although it is compatible with most stimulationchemicals, including MY-T-OIL IV, it containssolids that are inert, meaning some residue will
be left after treatment. Adomite®Aqua is not
recommended in hydrochloric acid solutions
stronger than 3%. Normal concentrations used
are from 20-50 lb/Mgal.
Adomite Regain
Adomite Regain is a starch-based particulate
fluid loss additive used for water-based
fracturing fluids. Designed with an internalenzyme breaker system, it is active at low
temperatures. Concentrations used are normally
in the 20 to 50 lb/Mgal range, at temperatures up
to 350°F. It can be used in formations up to 10
md.
Oil Based Fluids
There are a variety of fluid loss additivesapplicable to oil-based fracturing fluids.
WAC-9
WAC-9 may be used for fluid loss control with
any oil or water base fracturing fluids or acids.
K-34
K-34 (Bicarbonate of Soda) is used in My-T-Oil
IV gels as both a breaker and a fluid loss controladditive. Laboratory tests are required to
determine the concentrations used.
100 Mesh Sand
100 Mesh Sand may be used in highly
permeable limestone or dolomite formations to
control fluid loss. Pore spaces or “vugs” are
usually large enough that the larger particle size
found in 100 Mesh Sand is required to bridge the
openings. The amount of 100 Mesh Sand used
for fluid loss control depends on formation rock properties. 100 Mesh Sand can be used with
other fluid loss additives.
Foams and Emulsions
Gas bubbles present in foams and oil droplets
found in emulsions provide excellent fluid loss
control. Normally, additional fluid loss control
additives are not required for foam or emulsion
applications in formations with permeability of less than 1 md.
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Unit C Quiz
Fill in the blanks with one or more words to check your progress in Unit C.
1. Fluid loss reduces the ____________________ of the fracture and the fluid ____________________
inside the fracture.
2. One requirement of fluid loss additives is that a high percentage of formation
____________________ be regained after being treated by the additive.
3. Finely powdered ____________________ have been used to control fluid loss.
4. ____________________ additives deposit droplets along the fracture face to control fluid loss.
5. An advantage of a liquid fluid loss additive is that no ____________________ are left in the
formation or fracture.
6. WAC-9 is a finely powdered ____________________.
7. WAC-9 can be used as a fluid loss additive with ____________________, ____________________
or ____________________ base fluids.
8. WLC-4 can be used at concentrations from __________ to __________ lb/Mgal of fracturing fluid.
9. WLC-5 contains an ____________________ ___________________ that allows it to be more
degradable than other starch additives.
10. 100 Mesh sand is typically used in ____________________ _____________________ limestone or
dolomite formations.
Now, look up the suggested answers in the Answer Key at the back of this section.
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Unit D: Surfactants
A major obstacle to oil production is the
infiltration of water into oil-bearing formations.
Water can reduce the sand’s effective
permeability to oil, resulting in a partial or
complete block. Many crude oils and waters
form emulsions that are more viscous than crude
oil. Some emulsions have a fluid viscosity that is
several thousand times that of oil. Both blocking
water and water-oil emulsions can be present
near the wellbore. Breaking or preventing these
emulsions can be of great benefit in increasing
the productive flow of oil to the wellbore.
Surfactants (“surface active agents”) have beendeveloped to reduce fluid retention in a
formation. Through the wise use of surfactants,
these chemicals can aid in stimulation fluid
recovery and reduce the possibility of emulsions
forming in the formation.
Surfactant Definition
A surfactant is defined as a “surface active
agent.” This means a chemical which, when
added to a liquid, changes the surface tension of the liquid. Emulsifiers, non-emulsifiers, and
anti-foaming agents are all examples of
surfactants. In a practical sense, the term is
limited to those chemicals that lower the surface
tension of liquids. Surface tension is composed
of the forces present in the surface film of all
liquids. It tries to pull the fluid into a form with
the least surface area. This would be a sphere or
a round droplet The particles in the surface film
are attracted inwardly, causing tension.
Mercury has a very strong surface tension, so it
always tends to form itself into balls (Figure 6.1)
.
Figure 6.1 - Liquid with a high surface
tension
Water has a strong surface tension and also
tends to form balls, especially in contact with
oily surfaces. Alcohol and the common liquid
hydrocarbons (xylene, kerosene, diesel oil,
gasoline) used in fracturing will have low
surface tensions. They tend to spread out on a
solid surface to form a film (Figure 6.2).
Figure 6.2 - Liquid with a low surfacetension
The surface tension of most liquids can be
changed by the addition of surfactants.
Surfactant Usage
Surfactants have been used in conjunction withfracturing treatments for several years. There are
four important effects of these chemicals in
fracturing:
• helps prevent water blocks
• helps prevent the creation of emulsions
between the injected fluid and the formation
fluid
• helps stabilize emulsions when using an
emulsified treatment fluid
• aids in fluid recovery
Emulsions that are accidentally created in the
formation and do not break spontaneously may
reduce the flow of fluid into the fracture.
Emulsions in the fracture may limit the flow of
fluid through the fracture itself. If properly used,
a surfactant incorporated in the injected fluid can
help prevent the formation of emulsions during
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the treatment. The selection of the most effective
type and concentration of surfactants for the
prevention of emulsions or fluid blocks can be
determined by emulsion and flow tests.
Surfactants vary in chemical composition and
the effects they have on oil-water mixtures.Some cause the formation of oil-water
emulsions. Surfactants of this type exist
naturally in some crude oils. They are the cause
of common oil field emulsions. These emulsions
may be very thick and, when formed in a
formation, will block the flow of well fluids
more so than water.
Although emulsions formed in a formation may
block the flow of oil, certain surfactants can be
used to develop emulsions that can be used to
fracture oil-bearing formations. Acidfrac is an
acid-in-oil emulsion prepared with a specifictype of surfactant. It has been successfully used
in many fracture treatments.
Surfactant Composition
Surfactants are composed of an oil soluble group
(lipophilic group) and a water-soluble group
(hydrophilic group). These chemicals have the
ability to lower the surface tension of a liquid by
adsorbing at the interface between the liquid and
a gas. Surfactants lower the interfacial tension by adsorbing at interfaces between two
immiscible (unmixable) liquids. They also
reduce contact angles by adsorbing at interfaces
between a liquid and a solid. Surfactants are
classified into four major groups, depending
upon the nature of the water-soluble group.
These divisions are:
• Anionic
• Cationic
•
Nonionic• Amphoteric
The following model (Figure 6.3) will be used
to simplify this discussion.
Figure 6.3 - Surfactant Molecule
Anionic surfactants (Figure 6.4) are organic
molecules whose water-soluble group is
negatively charged.
Figure 6.4 - Anionic Surfactant
Cationic surfactants (Figure 6.5) are organic
molecules whose water-soluble group is
positively charged.
Figure 6.5 - Cationic Surfactant
Nonionic surfactants are (Figure 6.6) organic
molecules that do not ionize and therefore
remain uncharged.
Figure 6.6 - Nonionic Surfactant
Amphoteric surfactants (Figure 6.7) are organic
molecules whose water-soluble group can be
positively charged, negatively charged, or
uncharged. The actual charge of an amphoteric
surfactant is dependent upon the pH of the
system.
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Figure 6.7 - Amphoteric Surfactant
Surfactant Mechanisms
Surface Tension
Because surfactants are composed of water-
soluble and oil soluble groups, they will absorb
at interfaces between a liquid and a gas, or two
immiscible liquids. Figure 6.8 illustrates how
surfactants function to lower surface tension.
Figure 6.8 - Surfactant Interaction
The “water-loving” group is more soluble inwater than the “oil-loving” group. Therefore, a
surfactant molecule orients itself at the air-water
interface with the oil soluble group in the air and
the water-soluble group in the water. This alters
the nature of the air-water interface. Depending
on the effectiveness of the surfactant, the
interface now is a combination of an “air-water-
oil” interface. Oil has a much lower surface
tension than water (Table 6.1). Therefore, the
surface tension of a water/surfactant mixture
will be lower than the surface tension of pure
water, perhaps as low as oil.
Surface Tension
Water 71.97 dynes/cm
Octane 21.77 dynes/cm
Benzene 28.90 dynes/cm
Carbon Tetrachloride 26 0.66 dynes/cmTable 6.1 – Surface tension of variousliquids
Some effective hydrocarbon surfactants will
reduce the surface tension of distilled water to
about 27 dynes/cm when used in relatively low
concentrations. Another type has been used as
an aid for stimulating tight gas wells. This type
of surfactant is based on an oil soluble group
composed of a fluorocarbon chain. Using this
type, it is possible to get surface tensions below20 dynes/cm.
Surfactants will also lower the interfacial tension
that develops between two immiscible liquids by
absorption of the surfactants at the oil-water
interface.
Wettability
The ability of a surfactant to adsorb at interfaces
between liquids and solids and to alter the
wettability of solids is usually explained by anelectrochemical approach. Wettability indicates
whether a solid is coated with oil or water. Most
formations are composed primarily of mixtures
containing sand, clay, limestone and dolomite.
Sand and clay usually have a negative surface
charge. With cationic surfactants, the positive
water-soluble group is adsorbed by the negative
silica particle, leaving the oil soluble group to
influence wettability. Therefore, cationics
generally oil wet sand. With anionic surfactants,
the negative silicate electrically repulses the
negative water-soluble group. Thus thesurfactant is not usually absorbed by sand.
Therefore, anionics generally leave silica
minerals in a natural water wet state.
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Figure 6.9 - Wettability Characteristics
Limestone has a positive surface charge at a pH
below 8 and a negative surface charge at pH
values above 9.5. Under oil field conditions
most limestone and dolomite formations will
have a positive surface charge. Since anionic
surfactants have a negative charge, the water
soluble group will be adsorbed by the positive
carbonate particle leaving the oil soluble groupto influence wettability. Because of this,
anionics usually oil wet limestone and dolomiteformations.
Carbonates do not adsorb cationics; therefore,
most cationics will leave limestone and dolomite
naturally water wet. An illustration of the
mechanism governing wettability characteristics
exhibited by anionic and cationic surfactants on
silicates and carbonates is shown in Figure 6.9.
In the case of nonionic surfactants, the
wettability of silicates and carbonates depends primarily on the weight ratio of the water-
soluble group to the oil soluble group.
Blending of Surfactants
Most surfactants used by the petroleum industry
are blends of several surfactants with a solvent
present. By selectively blending surfactants, it is
possible to obtain a mixture with more universal
properties. This is very important since there are
no two producing formations exactly alike.Therefore, no single surfactant is universally
applicable. Even by blending surfactants, it is
not yet possible to have one surfactant that will
always satisfactorily perform in every field.
Table 6.2 lists a number of surfactants
commonly used by Halliburton and their
charges.
Composition
Non-Ionic Surfactant forWater and Acid Systems
LoSurf – 259
LoSurf – 300
LoSurf – 357
LoSurf – 396
Cationic Non-Emulsifiers 17N
19N
20N
LoSurf – 400
Anionic Non-Emulsifiers LoSurf – 2000S
NEA-96M
Amphoteric Non-Emulsifier HC-2 (AQF-4)
Table 6.2 – Charges for commonly usedsurfactants
Summary
In summary, selection of the most effective type
and concentration of surfactants for the
prevention of emulsions or fluid blocks should
be determined by emulsion and flow tests.
Having made these tests and selected the correcttype and concentration for the surfactant, it is the
responsibility of the frac operator not to
substitute for the type or change the
concentration of surfactant. If the selected type
surfactant is not available, additional tests will
be required to determine a second choice for the
surfactant.
There are many surfactants available for oil field
work. Great care should always be observed in
their selection and use for particular conditions.
Check with the engineering staff in your district
for help in making selections.
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Unit D Quiz: Surfactants
Fill in the blanks with one or more words to check your progress in Unit D.
1. Surfactants can be defined as ____________________ ____________________ agents.
2. Surface tension is ____________________ for water than surface tension is for oil.
3. Four important effects of chemicals used as surfactants in fracturing fluids are:
1.__________________________________________________________________________
2.__________________________________________________________________________
3.__________________________________________________________________________
4.__________________________________________________________________________
4. Emulsions that are accidentally created in the formation may __________ the flow of fluids.
5. Surfactants incorporated in the injected fluid can __________________ the formation of emulsions if
____________________ selected.
6. Selection of the most effective type and concentration of surfactant can be determined by
____________________ and flow tests.
7. Surfactants can be classified into four major groups, depending upon the nature of the
____________________ ____________________ group.
Now, look up the suggested answers in the Answer Key at the back of this section.
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Unit E: Gelling Agents
Gelling agents are divided into two categories:
those for water base fluids and those for oil or
hydrocarbon base fluids. The two categories will
be discussed separately in this unit.
Gelling agents are used for increasing viscosity,
reducing friction, controlling fluid loss, etc.
Viscosity (resistance to motion) is the most
important condition derived from the use of
gelling agents.
Water-Based Gelling Agents
Gelling agents are generally high molecular
weight polymers. Polymers contain functional
groups that interact with water and each other.
When dry, polymers are twisted into coils, but
swell or hydrate in water and develop a more
relaxed configuration (Figure 6.10). Hydration
of polymers reduces available water in the
solution. Some entanglement of the hydrated
polymers occurs and reduces freedom of motion.
Gelled fluids are classified as semi-solids.
Figure 6.10 - Polymer Configurations
A number of water-based gelling agents have
been developed for use in the fracturing process
(Table 6.3). Water-soluble polymers commonly
used in oilfield applications are:
• guar and its derivatives
• cellulose and its derivatives
• xanthan
• polyacrylamides.
Guar
Guar and its derivatives are the most extensively
used polymers in fracturing fluids. The guar
bean, which is grown primarily on theIndo-Pakistan subcontinent, is a polysaccharide
with one of the highest molecular weights of all
naturally occurring water-soluble polymers. The
average molecular weight is believed to be in the
range of 1 to 2 million. The guar bean's hull isremoved and the endosperm (inside portion) is
ground into a fine powder, which is used as a
viscosifier. The guar molecule is in a coiled state
in the powder form. Guar molecules absorb
water (a process referred to as hydration) upon
being placed in an aqueous media and uncoil,
elongate, and become linear.
Several factors will affect the hydration rate of
polymers:
• pH of the system
• amount of mechanical shear applied in the
initial mixing phase
• polymer concentration
• salt concentration of the solution
• particle size and chemical treatment of
polymer
• presence of special additives
Some of the general properties for guar gums
include:
• Contains 10 to 13% residue by weight
• Easy to crosslink
• Yields 40 lb gel viscosities of 32 to 36
centapoise (cp) at 511 sec-1 (reciprocal
seconds)
• Can be used with brines
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• Has low methanol tolerance
• Least expensive gelling agents
Derivatized Guar s
Derivatized (modified) guar gelling agents arealso manufactured from the guar bean. These
agents are subjected to additional chemical
processing, which adds to its cost. This
processing reduces the residue that remains after
the gelled fracturing fluid is broken and
improves dispersion to enhance mixing
characteristics. Derivatized guars, such as
hydroxypropyl guar (HPG) are commonly used
in the oilfield. The characteristics of HPG are:
• Contains 1 to 3% residue by weight
• Higher crosslink viscosities than guar
• Fewer crosslink sites
• Yields 40 lb gel viscosities of 32 to 36 cp at
511 sec-1
• Can tolerate 80% by volume methanol with
some HPG derivatives
• More expensive than guar.
Carboxymethyl hydroxypropyl guar (CMHPG)
is another commonly used guar derivative in the
oilfield. It is similar to HPG with someadditional versatility in crosslinking via the
carboxyl groups. CMHPG is a double
derivatized material. Some characteristics of
CMHPG include the following
• More sensitive than guar and HPG to brines
and electrolyte solutions
• Hydrates well in cold or warm water
• Yields 40 lb gel viscosities of 30 to 32 cps at
500 sec-1 in 2% KCl
• Anionic derivative
• 1 to 2% residue by weight
• Easy to crosslink
• Equivalent in cost to HPG
Cellulose
All cellulose compounds used as fracturing fluid
gelling agents are derivatized forms of cellulose.
Cellulose derivatives are polymers made from
cotton. They are chemically modified natural
products designed for applications that require a
highly efficient gelling agent that contains no
solids and leaves no residue when broken
properly.
Hydroxyethel cellulose is currently the most
commonly used form of derivatized cellulose
products in the oil field. Unlike guar and its
derivatives, HEC only hydrates rapidly at a pH
of over 7.0. HEC is most commonly used for
sand control operations.
General properties of HEC include the following
• May be used with brines
• Stable at high temperatures
• Residue-free
• Yields high viscosity gels – 40 lb gel
viscosities of 45 to 50 cp at 511 sec-1
• Expensive
The primary advantage of HEC and the other
derivatized celluloses is that they are residue
free after degradation.
Carboxymethyl cellulose (CMC) is a
residue-free polymer that can be crosslinked;
however, CMC is extremely salt sensitive,
which limits its application
Characteristics of CMC include:
• Maximum viscosity and stability with CMC
occurs at pH 7 to 9 with fresh water
• Extremely sensitive to divalent metal salts
such as CA+2, Zn+2
• Low salt tolerance
• Relatively expensive
The double derivatized carboxymethyl
hydroxyethyl cellulose (CMHEC) has found
acceptance as a gelling agent in stimulation
fluids. CMHEC has both nonionic and anionic
substituent groups.
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Characteristics of CMHEC include:
• Residue free
• Can be used with brines
• Can be crosslinked
• Relatively expensive
Xanthan
Biopolymers have been used in drilling fluidsfor a number of years. Recently, xanthan has
been introduced in fracturing and sand controlapplications. Xanthan yields much lessviscosity per pound of polymer when
compared to guar and cellulose; however, itdoes have excellent proppant transport
characteristics. Maximum freshwater solutionviscosity occurs at a pH of 5.5. At pH values
of less than 7, chrome or aluminum willcrosslink xanthan gum solutions.
Properties of xanthan include:
• Residue 3% by weight
• Expensive
• Can crosslink
• Excellent proppant transport.
Polyacrylamides
Polyacrylamides (PAM) are used in fracturingfluids as friction reducers. In the dry form
these are used at concentrations of 2 to 5 lb per
1,000 gal fluid. PAM's can be cationic or anionic
and are residue free. Properties of
polyacrylamides include:
• Relatively expensive
• Hard to mix without creating gel balls
• Extremely high molecular weight – 1 to 20
million.
• Produce the greatest friction reduction
(anionic polymers)
• Used in low concentration.
Acid Gell ing Agents
Gelling agents are normally found in fracture
acidizing treatments where viscosity is used to
help achieve deeper acid penetration. However,
in a matrix treatment, while deep penetration is
not the objective, viscosity can be an advantage
in fines removal. If used for this purpose, the
concentration of the acid gelling agent will be
much less than a similar application in fracture
acidizing. In addition, viscosity derived from a
surfactant rather than a polymer will minimize
the potential for additional damage.
Although the fluid systems using the same base
polymers are composed of the same base
materials, each one is specially formulated to
tailor its performance to meet particular needs.
Water BasePolymers
Chemica l Name Gel System
Guar
WG-19WG-22WG-26WG-31WG-35
FracGelBoraGelHybor-GDeltaFrac
WaterFrac-G
HydroxypropylGuar (HPG)
WG-11
Hybor-HDelta-H
WaterFrac-HSeaQuest
CarboxymethylHydroxypropylGuar (CMHPG)
WG-18
PurGel III ThermaGel
SiroccoSilverStim
HydroxyethylCellulose (HEC)
WG-17 HEC
Xanthan WG-24 Liquid Sand
Chemicallymodified naturalpolymer formethanol.
WG-20AlcoGel IIIAlcoFoam
Anionic FrictionReducingPolyacrylamide
FR-26LCNon-acid
WaterFrac
Cationic FrictionReducingPolyacrylamide
FR-28LCFR-38FR-48
AcidsWaterFrac
Liquidviscosifier foracid
SGA-HTSGA-ISGA-IISGA-IIISGA-IV
Sand Stone2000
Carbonate20/20
Table 6.3 – Gel names and their uses
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Oil Gelling Agents
In the fracturing of certain extremely water-
sensitive formations, even the use of potassium
chloride, calcium chloride and sodium chloride
solutions may not be effective in reducing clayswelling or formation particle migration. This
can usually be determined from laboratory tests
on formation cores or from field treating results.
In such cases, an oil base fluid should be
considered. However, when using a
hydrocarbon-based fluid system, safety to
prevent fires on location is a main concern and
good fire fighting equipment is a must.
To meet the needs of treating water sensitive
formations, gelling agents have been developed
to give structure to oil base fluids. The four
basic fluid systems below are available for oil base fracturing fluids and are a culmination of
years of research.
MY-T-OIL IV
Earlier gelled oil systems had to be batch mixed
prior to pumping the fracture treatment.
Extensive laboratory research and field-testing
have resulted in the development of a
continuously mixed gelled oil system. This
system can reduce the time on location caused
by batch mixing, as well as eliminate waste and
disposal problems caused by leftover gelled
fluid in the storage tanks.
The My-T-Oil IV system uses a two-component
system. The components are MO-75 gelling
agent and MO-76 activator. The chemicals are
added at a 1:1 ratio with the normal usage
concentration being 4 to 6 gal/Mgal. The final
viscosity of this system will vary greatly
depending on the type of hydrocarbon used and
the chemical concentrations. For refined
hydrocarbons such as diesel or kerosene, theviscosity should be in the range of 100 – 400 cp
at 170 sec-1. MY-T-OIL IV is effective at
temperatures up to 200 degrees.
MY-T-OIL V
A recent extension of the MY-T-OIL series,
MY-T-OIL V is a crosslinked, anionic
surfactant, oil-gellant system. It uses MO-85
anionic surfactant and MO-86 crosslinker. The
use of surfactant chemistry prevents damage by
polymer residue. The chemicals are added at a
1:1 ratio with the normal usage concentration
being 4 to 9 gal/Mgal, depending on
temperature. My-T-Oil V is capable of
viscosities over 600 cp at 170 sec-1 depending on
temperature, additive concentration and
hydrocarbon used. The system is designed for
continuous-mix stimulation of oil reservoirs over
a wide temperature range up to 275 degrees.
Crude oils that gel easily may be effectively
used in this application to reduce costs, but the
MY-T-OIL V system will gel a wide range of
crude oils. However, the risk of paraffin and/or
asphaltene precipitation in the formation is
greater than with refined fluids such as diesel.
MISCO2 FRAC
MY-T-OIL V’s counterpart, MISCO2 FRAC
fracturing system, provides similar benefits for
gas reservoirs, including those which are low
pressured and/or water sensitive. MISCO2
FRAC is used with up to 50% CO2 by totalvolume. In this application, the system provides
excellent fracture and formation conductivity
with rapid load fluid recovery. MISCO2 FRAC
employs the same gelling system used in MY-T-
OIL V.
Super Emulsi frac (Oil Internal GelledWater External Emulsion FracturingFluid)
Super Emulsifrac is the Halliburton name for a
fracturing process developed by ExxonProduction Research Company (EPR). This
process uses an emulsion composed of an
internal hydrocarbon phase (such as diesel,
kerosene, condensate, or crude oil) and an
external water phase containing a gelling agent
such as WG-22, WG-31 or WG-11. The
emulsion is stabilized with an emulsifier such as
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SEM-5, SEM-6, or SEM-7 that is contained in
the gelled water phase. The internal hydrocarbon
phase is between 50 and 80% of the total
volume, and the remaining volume is composed
of the gelled water, emulsifier, and other
additives.
Super Emulsifrac fluids are similar to N2, or
CO2, foams, except that a hydrocarbon
constitutes the internal phase of the two-phase
fluid rather than gas. With the application of
constant internal phase principles to emulsion
fluids, friction pressures can be controlled
resulting higher sand concentrations.
Super Emulsifrac can be used up to 300 degrees
with the proper emulsifier concentrations.
Addit ional References
Fracturing Service Manual – HalWorld.
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Unit E Quiz: Gelling Agents
Fill in the blanks with one or more words to check your progress in Unit E.
1. Gelling agents are used for increasing viscosity, reducing friction, controlling fluid loss, etc.
___________________ is the most important condition derived from using gelling agents.
2. Gelling agents are generally high molecular weight ____________________.
3. Gelled fluids are classified as ____________________ - ____________________.
4. The amount of residue resulting from the use of guar gelling agents is __________ to __________%.
5. The guar bean’s hull is removed and the ____________________ is ground into a fine powder which
is used to create viscosity.
6. Carboxymethyl Cellulose (CMC) is extremely ____________________ ____________________,
which limits its application.
7. Derivitized guar gelling agents will give __________ to __________% residue after break of the
gelled fluids.
8. Polyacrylamides are mainly used in fracturing as ____________________ ___________________.
9. Cellulose derivatives are chemically modified ____________________ and contain
________________ solids and leave no ________________ upon breaking.
10. Xanthan yields much less ____________________ per pound of polymer when compared to guar
and cellulose; however, it does have excellent ___________________ ____________________
characteristics.
11. MY-T-OIL V uses ________________ surfactant and ________________crosslinker in a
_____:_____ ratio.
12. SUPEREMULSIFRAC is composed of an internal ____________________ phase and and external
____________________ phase.
Now, look up the suggested answers in the Answer Key at the back of this section.
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Unit F: Complexors and Crosslinkers
Complexors or crosslinkers can provide
additional viscosity in a fracturing fluid system.
They are added to the base gel fluid. Small
amounts of these crosslinkers chemically link
two or more polymer chains, thus increasing the
effective molecular weight and viscosity.
Crosslinking agents commonly used in
stimulation fluids are metals (antimony,
zirconium, aluminum, chromium, titanium) and
boron. Variables such as pH, polymer type,
pump time, and fluid temperature will dictate to
a large extent, the crosslinker used (Figure
6.??).
A major concern with crosslinked fluids is their
shear stability (ability to resist a decrease in
viscosity under shear) while pumping down the
tubular goods and through perforations. This
concern led to the development of delayed
crosslinkers that are designed to inhibit
crosslinking in the tubulars.
Factors which influence crosslinking
• Polymer concentration - generally, the
greater the concentration, the higher the
viscosity will be.• Metal ion type and concentration - an
optimum crosslinker concentration exists,
above or below which unacceptable
viscosities or gel stability results for each
crosslinker and gel concentration.
• pH - Some crosslinker systems are highly
pH sensitive, for example borate (requires
pH > 8), whereas others, like titanium,
tolerate a wide range in pH.
• Shear - The amount of shear a gelled fluid is
subjected to during mixing will influence theviscosity of the system. High shear generally
degrades viscosity; low shear mixing
generally yields more viscous gelled fluids.
K-38
K-38 is a white powdered borate crosslinker,
also called Polybor. It was developed to give the
highest concentration of borate ions in solution
per weight of borate source and is highly
effective as the primary crosslinker in BoraGel
or as a crosslink accelerator in the Hybor and
DeltaFrac fluid systems. K-38 is usually
dissolved in water at a 1 lb/gal concentration for
ease of mixing and metering.
CL-11
CL-11 is a light yellow, water-sensitive, alkaline
liquid. It contains a titanium-ion complex in an
alcoholic solution. CL-11 can be added to
Thermagel or VersaGel HT or it can be mixed
with the primary crosslinkers in these systems
(CL-24 and CL-18) to achieve accelerated
crosslink times. Crosslink time testing should be
conducted with actual source water before
performing the stimulation treatment.
CL-18
CL-18 is an older, titanate complex crosslinker
for use in the VersaGel HT fluid system. It is a
yellow-gold colored liquid and is flammable,
with a flash point of 74°F. It is a delayed
crosslinker which can be accelerated with
temperature or the addition of CL-11.
CL-22
CL-22 is an oil-base slurry of borate minerals
used in Hybor fluid systems. CL-28M is a water-
based slurry of borate minerals. Both CL-22 and
CL-28M provide delayed crosslink to borate
crosslinked fluids, similar in apparent viscosity
to the non-delayed borate crosslinked BoraGel
fluid.
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CL-23
The crosslinking agent, CL-23 is used in the
PurGel III fluid systems. CL-23 is a delayed-
crosslinking agent that is compatible with CO2.
It is an aqueous, colorless liquid containing a
zirconium complex. It may be diluted with fresh
water for convenience of metering. Crosslinker
concentration used depends upon the buffering
system employed.
CL-24
CL-24 is a pale yellow, liquid zirconium-ion
complex that is used as a delayed temperature-
activated crosslinker in the Thermagel fluid
system. The crosslinker begins activation at
100° to 110°F. The base gel fluid will crosslink rapidly at 140°F. Each drum of CL-24 is dated and the oldest stock should always be used first.
CL-24 is a flammable liquid. The recommended
concentration of CL-24 is 0.10 gal per 10 lb of
base gel per 1,000 gal of fluid.
CL-28M
CL-28M is a water-based suspension crosslinker
of a borate mineral used in Hybor fluid systems
and was developed as a low cost alternative to
CL-22 (see above). Since CL-28M is water- based, it does not have the flash point concerns
associated with CL-22. The suspension
properties of CL-28M have been improved to
provide better stability. However, containers
should be inspected for solids settling and
remixed if needed. Material loss could occur if
the suspension adheres to the sides of the
container.
100 150 200 250 300
Antimony (V)
Boron (III)
Chromium (N)
Antimony (III)
Titanium (IV)
Figure 6.11 – Upper Limit TemperatureRanges for Specific Crosslinking Agents intheir Usable pH and Concentrations Range.
CL-29
CL-29 is a fast acting zirconium complex that
was introduced as an accessory crosslinker for
the PurGel III fluid system. CL-29 provides a
more rapid crosslink time when used with CL-
23. It can also be used as a stand-alone
crosslinker.
CL-31
CL-31 is a concentrated solution of non-delayed
borate crosslinker originally designed for use inBoraGel fluid systems. Also used to control
crosslink time for Hybor fluids, it provides the
convenience of a concentrated, stable crosslinker
solution. One gallon of CL-31 contains the
equivalent of 2.0 lb of K-38, has a high pH and
is highly caustic. CL-31 has no flash point and
has a pour point of -5°F. If diluted with water or
aqueous sodium hydroxide, CL-31 will freeze
above -5°F. Because of its high pH, CL-31 can
be used as a self-buffering crosslinker.
BC-140 (formerly BC-2)
BC-140 is a dark-colored, specially formulated
crosslinker/buffer system for use in Delta Frac
fluid systems. No additional buffering agents,
acids, or bases are required to adjust the pH of
the fluid system. The concentration range of BC-
140 that provides the best viscosity performance
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for the Delta Frac fluid system is 1.5 to 2
gal/Mgal for 15 to 25 lb gel loading between 80°
and 120°F. Crosslinker concentration is
temperature and water dependent. In 2% KCL or
brine waters, BC-140 concentration is decreased
while at higher temperatures it is increased.
BC-200
BC-200 is a delayed crosslinker and functions as
both crosslinker and buffer for use in the Delta
Frac fluid systems. It is a dark brown suspension
of fine particles in a hydrocarbon. No additional
buffering agents, acids, or bases are required to
adjust the pH of the fluid system. Used at the
proper concentrations, BC-200 buffers fluids to
the proper pH. The resulting design raises the
pH of the fluid but does not increase crosslink
time. In fact, adding caustic or a buffer to raise
the pH of the fluid out of the proper range will
ruin the fluid by over-crosslinking, resulting in
much lower viscosity. The final pH of this
system should be approximately 9 to 9.5.
Although the crosslink time of the system cannot
be increased, it can be decreased by adding an
instant borate crosslinker such as K-38, BC-140or CL-31.
CL-36
CL-36 is a new mixed metal crosslinker
specifically designed for the Delta 275 fluid
system. It is a yellow, alcohol based system with
a flash point of 81°F. The concentration used is
a function of the temperature and pH of the final
fluid system (generally 1 to 2.2 gal/Mgal). CL-
36 is a delayed crosslinker that can be
accelerated with the addition of CL-31.
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Unit F Quiz
Fill in the blanks with one or more words or mark the best answer to check your progress in Unit F.
1. Small amounts of crosslinkers chemically link two or more ___________________
____________________, thus increasing the effective ___________________
____________________ and ___________________.
2. List four factors that influence crosslinking:
_____________________
_____________________
_____________________
_____________________
3. CL-11 is a light yellow, alkaline, ___________________-ion complex that is added to the Thermagel
fluid system to achieve an ____________________ crosslinking time
4. One gallon of CL-31 contains the equivalent of __________ lb of K-38, and it is highly
____________________.
5. BC-140 is a dark-colored, specially formulated ____________________/____________________
system for use in the Delta Frac fluid systems.
6. _____True _____False: The crosslinking time of the BC-200 buffer crosslinker can be increased.
Now, look up the suggested answers in the Answer Key at the back of this section.
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Unit G: Breakers and Stabilizers
Breakers
The viscosity of fracturing fluids is increased
when gelling agents and crosslinkers are used to
aid proppant transport and placement. This
increased viscosity is desirable during pump-in
procedures. However, if this viscosity is notreduced the treated well may not flow. The
stimulation fluid must have the capability to
decrease in viscosity (break) following proppant
placement. The decrease in fluid viscosity is
necessary to
• minimize return of proppant
• maximize return of stimulation fluids to the
surface
The decrease in the fluid viscosity is usually
achieved using chemicals referred to as gelling
agent breakers or gel breakers. The gel breaker
functions by breaking the long chain polymers
into shorter chain segments, allowing the fluid
more mobility with controlled and predictable
viscosity decrease. The degree of reduction in
viscosity is controlled by the breaker type, pH,
gel concentration, breaker concentration, time,
and temperature.
Breaker Types
Chemical breakers used to reduce viscosity of
guar and derivatized guar polymers are generally
grouped into three classes: oxidizers, enzymes,
and acids. All of these materials reduce the
viscosity of the gel by breaking connective
linkages in the guar polymer chain. Once the
connective bonds in the polymer are broken, the
resulting pieces of the original polymer chain are
the same regardless of the type of breaker used.
Figure 6.12
A breaker should be selected based on its
performance in the temperature, pH, time, and
desired viscosity profile for each specific
treatment.
Enzyme Breakers
Enzymes are referred to as Nature's catalysts because most biological processes involve an
enzyme. Enzymes are large protein molecules.
Proteins consist of a chain of building blocks
called amino acids. In Oilfield applications,
breaker enzymes cause hydrolysis, or the
addition of water, to the guar polymer. This
causes viscosity to decrease. However, because
of the characteristics of enzymes, they are only
effective in a relatively narrow range of
temperatures and pH levels.
GBW-3™ / GBW-30™
GBW-30 is a white powdered enzyme breaker.
It is used below 120°F and below pH 8.5. Like
GBW-3, GBW-30 is a water-soluble enzyme
breaker for aqueous-based gelling agents at
temperatures below 120°F (48.8°C). Its reactive
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strength is approximately 10 times that of GBW-
3.
HPH
HPH breaker is an enzyme breaker specificallydesigned for borate fracturing fluids up to
approximately 140°F. HPH breaker is a high-
pH, stable enzyme breaker solution that
generally maintains its activity at higher pH than
GBW-30 enzyme breaker; between pH 7 and pH
10. Between 70 and 140°F, HPH breaker’s pH
range of 8.5 to 9.5 is suitable for BoraGel and
Delta FracSM fluids. This pH range contrasts
with the pH range of GBW-30 breaker which
displays its maximum activity below pH 7.
Under lower temperature conditions, HPH
breaker will function at even higher pH values.
N-Zyme 1 / N-Zyme 3
N-Zyme 1 enzyme breaker and N-Zyme 3
enzyme breaker are new breakers for use with
fracturing fluids at temperatures up to 140°F. N-
Zyme 1 and N-Zyme 3 breakers can be used in
place of GBW-3 breaker, GBW-30 breaker, and
HPH breaker. N-Zyme 3, which is three times
more concentrated than N-Zyme 1, is
specifically formulated for lower-temperature
applications.
OptiFlo-HTE
OptiFlo-HTE is an encapsulated, delayed
release, high temperature, enzyme breaker. It is
a reddish colored granular solid. OptiFlo-HTE is
the direct replacement for the obsolete OptiFlo-
E. The recommended temperature range for
application is from 75 to 175°F
The merits of an encapsulated enzyme breaker
are many. The encapsulation of OptiFlo-HTEallows the enzyme to be shielded from the fluid
environment and can delay denaturization due to
temperature exposure when compared to a liquid
enzyme breaker as shown in Figure 6.13. Liquid
enzyme or solid un-encapsulated enzyme
breakers cause an almost immediate reduction in
viscosity when added to stimulation fluids; this
can lower the ability of the fracturing fluid to
transport proppant. The controlled release rate of
an encapsulated breaker allows higher
concentrations to be placed throughout the
stimulation treatment.
Figure 6.13 - Liquid vs encapsulatedenzyme breaker.
Oxidizing Breaker
Sodium, potassium, and ammonium persulfate
have been used effectively as breakers for over
30 years. In these types of breakers, oxidation-
reduction chemical reactions occur as the
polymer chain is broken.
SP
SP Breaker is a white granular oxidizing
material used as a breaker at temperatures above
120°F. It may be used below 120°F in
conjunction with an activator. Above 180 deg,
persulfate breakers become highly unstable and
create unpredictable breaks.
ViCon HT or ViCon NF
Powder form ViCon-HT or liquid form ViCon- NF is a powerful oxidizing breaker for use with
GEL-STA in fracturing fluids, and is the
premiere breaker at temperatures above 200°F.
Vicon can also be run below 200°F with an
activator. Although ViCon-NF is compatiblewith GEL-STA in dilute fluids, such as
fracturing fluids, ViCon-NF should not be
mixed with GEL-STA or GEL-STA L liquid
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concentrate. The required concentration of
ViCon-NF depends on the temperature, GEL-
STA concentration, and required break time.
Fann Model 50 viscometer data can be generated
in the desired temperature range for varying
amounts of GEL-STA and ViCon-NF. A high
retained viscosity is maintained at the cool downtemperature, but complete breaks occur as the
fluids reach formation temperature.
Optiflo II
In low temperature, high pH fluids, enzyme
breakers are not effective; therefore, there is a
need for a delayed release, low temperature
oxidizing breaker. OptiFlo II delayed breaker is
coated ammonium persulfate that is designed to
be used in low temperature applications. The
coating on OptiFlo II allows the breaker to be
released slowly by diffusion across the slightly
permeable coating. The release profile of
OptiFlo II at 80°, 100°, and 120°F show less
than 10% of the breaker is released in 1 hour,
but at least 70% of breaker is released in 24
hours. This product is not designed to be used in
applications where the actual fluid temperature
is above 125°F. However, the application of
OptiFlo II can be extended to jobs with
bottomhole static temperatures (BHST) above
125°F using formation cool down. Field
experience and temperature programs can aid in
the prediction of downhole fluid temperatures
during the job. The addition of OptiFlo II to the
pad is not recommended, but OptiFlo II can be
added to the pad fluid in jobs where static break
tests, data, and fluid rheology data support its
use.
Deposition of filter cake during a job can
decrease the conductivity of the generated
fracture. Delayed release breakers help improve
fracture conductivity by cleaning up the filter
cake and proppant pack. This cleanup isaccomplished by two beneficial features of
delayed release breakers.
• The capability of adding higher breaker
concentrations allows enough to be added to
break the filter cake and gel remaining in the
proppant pack.
• The breaker is a solid and cannot be lost to
the formation during fluid leak off.
Optiflo III
OptiFlo III is a delayed release breaker that hasimproved performance as a result of a new,
innovative coating technology that provides less
early time release of the breaker than previous
delayed release breakers. OptiFlo III improves
gel breaking technology by limiting the contact
time of the breaker with the fracturing fluid and
concentrating the breaker in the fracture.
Limiting the breaker contact with the fracturing
fluid allows increased breaker concentration
without sacrificing fluid performance. Higher
breaker concentrations, as well as concentration
of the breaker in the fracture, improves proppant pack cleanup and results in improved proppant
conductivity of the created fracture. OptiFlo III
contains ammonium persulfate (AP breaker) as
the active component. This breaker is designed
to be used in actual fluid temperatures of 130°F
to 200°F.
0
20
40
60
80
100
0 1 2 3 4 5 6 7 8
Time (hr)
R e l e a s e
d ( % )
OptiFlo HTE @ 75°F
OptiFlo III @ 175°F
OptiFlo II @ 120°F
Figure 6.14 - Release Profile of Encapsulated Breakers
Acid Breakers
Acid also provides the same break via hydrolysis
as an enzyme. Acid, however, poses various
difficulties for practical applications. Acid is not
used as a guar polymer breaker very often
because of cost, poor break rate control,
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chemical compatibility difficulties, and
corrosion of metal goods. Another difficulty
with acid breakers is that the formation may act
as a buffer. A small amount of acid introduced
as a breaker may be totally consumed by the
formation water and minerals. This absorption
could quickly change the pH of the fracturingfluid to a point where breaking may not occur.
Most formation brines have a pH between 6 and 8.
The applications for acid breakers are limited,
with two exceptions that involve delayed-release
type acids. First, a delayed-release acid may be
used to un-crosslink a borate. Second,
delayed-release acid may also be useful with
enzyme breakers. Especially at low
temperatures, the use of enzymes in borate
crosslinked fluids is often effective. To allow the
enzyme to be effective in the pH 9 to 11 borate
fluid, delayed-release acids can be used to lower
the fluid pH value to a range where the enzymes
are effective.
MatrixFlo II
MatrixFlo II is a liquid, delayed release acid
breaker that deeply penetrates a formation
matrix to provide a more complete break and
enhanced fracture conductivity. When used in
Delta Frac, BoraGel, and Hybor fracturing fluidsMatrixFlo II breaker can controllably decrease
fluid viscosity by lowering the pH and
uncrosslinking a crosslinked gel network. When
MatrixFlo II breaker is used with enzymes, it
will also lower the pH of the system and initiate
enzyme breaker activity to degrade the polymer
backbone further. MatrixFlo II breaker can be
used effectively at temperatures up to 180°F.
MatrixFlo II breaker significantly improves the
regained permeability of the fluid system.
OptiFlo-LT
OptiFlo LT is a delayed release acid additive
that decreases the pH of fracturing fluids.
OptiFlo LT can be used in BoraGel and Hybor
fluids to decrease fluid pH to initiate enzyme
breaker activity (to degrade gel polymer) and to
reverse the borate crosslink. OptiFlo LT was
developed to be used in conjunction with
enzyme breakers at temperatures below 120°F.
OptiFlo LT is designed to lower the pH value of
borate crosslinked fracturing fluid. It can be
used in other fluids where a delayed decreased
in fluid pH is desired. Unlike previous delayed release additives, OptiFlo LT has a fast release
mechanism. In general, OptiFlo LT itself will
not break the gel polymer of a borate crosslinked
fluid, but when used in conjunction with OptiFlo
HTE (encapsulated enzyme), a broken gel will
result. The combination of OptiFlo LT and
OptiFlo HTE offers an alternative to the use of
oxidizing breakers.
OptiKleen and OptiKleen LT
Gel filter cake that forms on the fracture face provides desirable fluid loss control; however,
this filter cake also can impair conductivity by
causing loss of effective width on both sides of the fracture. This impairment is most
pronounced at low proppant concentrations.
Simple breakers in the usual amounts are
sometimes not effective in breaking such a gel.
Moreover, filter cakes containing titanate or
zirconate crosslinkers especially resist removal.
For this reason, the breakers OptiKleen and
OptiKleen LT have been developed for post-
treatment filter cake removal. OptiKleen isrecommended for wells with greater than 130°F
bottomhole static temperature (BHST). At
120°F, it becomes only half as efficient in
dissolving filter cake. At 100°F it is ineffective.
A low temperature version, OptiKleen-LT, has
been developed for use in wells with bottomhole
temperatures below 130°F. The minimum
recommended volume of fluid with which to
treat a fractured well is the void volume of the
proppant bed. This volume can be estimated
using the following formula:
Minimum volume (gal) = 3/7 (PWT × ABV)
Where
PWT = total proppant weight (lb)
ABV = absolute volume of proppant
(gal/lb),
3/7 = the ratio of void volume to
proppant volume based on an
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Fracturing Fluids and Materials
ViCon-NF Breaker (or ViCon-HT Breaker) has
been very successful as a high temperature
breaker, but below 200°F it reacts too slowly to
be useful in the time period desired. By using a
catalyst to “activate” the Vicon, its lower
temperature limit can be reduced. Due to the
high reactivity and thermal instability of persulfates, the activated ViCon systems are the
breakers of choice for fluids at 170 to 200°F.They can also be used as low as 150°F, but the
persulfate systems may be as effective and more
economical. The other oxidizing breakers can
also be activated to function below their lower
temperature limits.
estimate that the void is about 30%
of the total proppant bed volume.
Gelled-Oil Breakers
K-34
K-34 is used as the breaker for MY-T-OIL IV
gels. Concentration range is 20 to 50 lb/Mgal
based on fluid temperature. K-34 is a finely
divided, white, free-flowing powder. It is not
considered dangerous; however, it should be
handled as a dusting material. It also possesses
fluid loss control properties and can contribute
fluid loss control in the MY-T-OIL IV fluid. Stabilizers
HL Breaker Gel breakers historically have been used toaccelerate gel degradation. However, at
sufficiently high temperatures, either pH or
temperature may break the viscosity of the gel
prematurely. At high temperatures, gel extenders
may be needed to increase the temperature
stability of gelled fluids, which results in a
higher retained viscosity at temperature for a
longer period of time. There three ways to
stabilize gels; methanol, Gel Sta, and pH
control.
HL Breaker is used as a breaker for the MY-T-
OIL IV fluid where there are bottomhole
temperatures less than 120°F and/or the need for
short gel break times. Concentrations range from
5 to 10 lb/Mgal, based on the gel concentration
and bottom hole temperature.
MO-IV
MO-IV is a white powder breaker developed for the MY-T-OIL V fluid system. This process is
currently proprietary information. It is effective
from 70° to 200°F.
Methanol (Methyl Alcohol)
Methanol has found wide spread use in various
fracturing fluids and additives. Occasionally,
methanol has been used to form a slurry of
gelling agent for easier introduction into a fluid
while reducing the tendency for the gelling agent
to form lumps. However, its largest use has been
to extend the upper temperature limit of some
gel systems to more effectively maintain
downhole fluid viscosity for treatment of wells
with high bottomhole temperature.
MO-V
MO-V is a white powder breaker developed for
the MY-T-OIL V fluid system. This breaker’s
makeup is currently proprietary information. It is
used from 201° to 275°F.
Breaker Activators The safety precautions required for the usage of
methanol based fracturing fluids are similar to
those followed for handling high gravity crude
oils and condensates. When the flash point of a
methanol/water mixture is reached, the mixture
becomes highly flammable due to the high
concentrations of methanol vapors above the
fluid. Unfortunately, unlike high gravity crudes
Just as there is a need to add activators to speed
up crosslink times, there is also a need for
activators to better control break times. CAT
(catalyst) LT, CAT-3, and CAT-4 are chemicals
that are used for this purpose.
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and condensates, the methanol flame is not
visible and no smoke is produced as the material
burns. The heat from the flame will be the first
sign of a methanol fire.
GEL-STA and GEL-STA L
The solid, GEL-STA, and the liquid, GEL-STA
L, are high-temperature gel stabilizers for use in
aqueous fracturing fluid processes. GEL-STA L
contains the equivalent of 3.5 lbs of GEL-STA
per gallon of water. GEL-STA functions by
scavenging oxygen from the fracturing fluid’s
environment. There is no premixing required
and it is more economical than 5% methanol,
although it can be added with methanol for
increased stability. GEL-STA is not compatible
with oxidizing breakers such as SP. It is
compatible with Vicon-NF and Vicon-HT, but
the ViCons should not be mixed with or even
placed closely to GEL-STA or GEL-STA Lliquid concentrate.
pH control
Maintaining a pH above 7 will also help
stabilize water base gels.
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Unit G Quiz
Fill in the blanks with one or more words or mark the best answer to check your progress in Unit
G.
1. A decrease in fluid viscosity is necessary to ____________________ return of proppant
____________________ return of stimulation fluids to the surface.
2. Chemical breakers used to reduce viscosity of guar and derivatized guar polymers are generally
grouped into three classes: ____________________, ____________________, and
____________________.
3. N-Zyme 1 enzyme breaker and N-Zyme 3 enzyme breaker are new breakers for use with fracturing
fluids at temperatures up to __________°F.
4. OptiFlo II delayed breaker is coated ____________________ ____________________ that is
designed to be used in low temperature applications.
5. When used in Delta Frac and Hybor fluids, MatrixFlo II breaker can controllably decrease fluid
____________________ by lowering the pH and ____________________ a crosslinked gel network.
6. If 100,000 lbs of proppant with an absolute volume of .0452 gal/lb is pumped into a formation, what
is the minimum recommended volume of OptiKleen needed for removing filter cake? ____________
7. ______ True _____ False: HL Breaker is used from 120-200°F.
8. K-34 is not only a breaker but also a
_____ A) fluid loss additive
_____ B) liquid
_____ C) gelling agent
_____ D) surfactant
9. List three ways to stabilize a water base gel:
__________________________________________
__________________________________________
__________________________________________
10. _____True _____ False: Breakers and stabilizers can be run together on a job.
Now, look up the suggested answers in the Answer Key at the back of this section.
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Unit H: Bactericides/Biocides
Bactericides are used to destroy or control
bacteria. Bacteria can cause viscosity instability
in batch mixed gels. When conditions arefavorable, sufficient numbers of bacteria can be
the chief cause of gel degradation.
Enzyme
Sugar
PolymerMicroorganism
Figure 6.15 - Degradation of Polymer byMicroorganisms
Bacteria Conditions
Some of the most favorable environments for
bacteria are dirty frac tanks and mixing water.
Dirty frac tanks often contain several gallons of bacteria-ridden decomposed gel from previous
jobs. When new gel is added, the bacteria have a
new food source. When the conditions are
favorable, some species may even attain
maximum concentrations within twenty-four
hours.
Bacteria feed on gel by releasing enzymes. The
enzymes degrade the gel to sugar, and the
bacteria absorb the sugar through their cell
walls. The enzymes released are very similar tothe low temperature breaker GBW-3. A
simplified cycle for the degrading of the polymer by bacteria is shown in Figure 6.15.
Bacteria Types
There are thousands of different kinds, or
strains, of bacteria that have been classified.
Many thousands have not. They are among the
simplest forms of non-vegetative organisms.
Because they are living, they have the same
needs as other forms of life: a source of energy,carbon, nitrogen, sulfur and phosphorus,
metallic elements, vitamins and water. They can
also adapt to changing environments.
Bacteria can be classified by their environmental
needs:
• Aerobic bacteria grow in the presence of
oxygen
• Anaerobic bacteria grow in the absence of
oxygen
• Some bacteria thrive in very lowtemperatures, while others do not
• Various bacteria may thrive in a variety of
pH ranges.
Bactericides
Bactericides should be handled with care.
Anything that can destroy bacteria may be
dangerous to handlers.
Caustic
Caustic is used to adjust the treating water pH
upward and can be an effective bactericide if
done properly. Add the caustic to each tank of
water to be treated until the pH of the water is
greater than 11.0 throughout the tank. This will
control bacteria over extended periods of time
and can also be used as an effective quick-kill
technique.
BE-3
BE-3 is a biocide that should be handled in a
very safe and careful manner. BE-3 is an
effective, extremely fast-killing biocide at low
concentrations (0.1 gal/Mgal). Maximum
effectiveness of BE-3 will be attained if the
entire volume of the biocide is placed in the frac
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BE-6tank with the first load of water as the tank is
being filled. This procedure places a high
enough concentration of biocide in the bottom of
the tank where bacteria and a large portion of
their enzymes can be destroyed. Addition of the
biocide to a full tank will result in killing the
bacteria but not affecting the enzymes. BE-3degrades rapidly at pH levels greater than 7.0.
Therefore, its use should be restricted to fluid with pH’s less than 7.0.
BE-6 is a new bactericide that addresses the
issue of packaging and persistence of kill. This
material is nonionic and provides a broad-
spectrum control of bacteria. BE-6 functions
similar to BE-5; it has a slow rate of kill (6 to 10
hours) and controls growth by inhibiting the
metabolic pathway of the bacteria. BE-6 is a
white, solid powder placed in a water-soluble
bag to improve handling and ease of addition.
The water-soluble bag is contained in a
protective outer bag that must be removed prior
to addition to the frac tank. Three of the 1-lb
water-soluble bags provide the normal dosage
for a single 20,000-gal frac tank.
BE-3S
BE-3S biocide is a rapid killing, board-spectrum
biocide packaged in water-soluble bags for
safety and ease of use. A powdered version of
BE-3, BE-3S provides all the treatment benefits
of BE-3 while helping to eliminate handling and
disposal problems associated with liquids. CAT-1
The use of biocides to treat tanks of fluid for
bacteria control has been used to control active
bacteria particularly during warm weather.
However, it has recently been determined that
even during winter months bacteria can assume
a sporulated form that resists the action of
biocides such as BE-5. Although these particular
bacteria may not prematurely break the gel, our
customers have expressed a desire to kill these
bacteria if found during bacteria counts. CAT-1
is available as sodium hypochlorite (household bleach) from most chemical suppliers in major
cities. Usually found in concentrations of 10 or
15% sodium hypochlorite, it is normally used at
0.5 gallons of a 10% solution or 0.33 gallons of
a 15% solution per 1,000 gallons of water to be
treated. The disadvantage of CAT-1 is that
because it is an excellent oxidizer, GEL-STA
must be added to the treated water to neutralize
it prior to adding a gelling agent.
BE-5
BE-5 is a broad spectrum biocide. It is used to
control the growth of microorganism
populations commonly found in source waters
for fracturing and stimulation processes. BE-5 is
effective against most types of bacteria, fungi,
and algae. It controls population growth by
acting as a metabolic inhibitor. Although slower
acting than other biocides, it has proven to bereliable.
BE-5 is a nonionic, nonfoaming, degradable
biocide with a broad pH stability range. The
active ingredient is absorbed into Fullers earth,
which renders the solid product as a nondusting
material that is much safer for handling than
other solid or liquid biocides. It is conveniently
packaged in a 6 lb plastic bottle containing a
sufficient dosage for one 20,000 gal frac tank.
One container of BE-5 biocide (6 lb) should be
added to each 20,000 gal frac tank with the first
load of water. BE-5 may not be premixed inLGC concentrates. The oil phase in the LGC
will inhibit the release of the biocide from the
Fullers earth.
Addit ional ReferencesChemical Stimulation Manual
Sales and Service Catalog
Chemical Services Technical Data Sheets
Halliburton Services Personnel Training Video
Hal World
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Fracturing Fluids and Materials
Unit H Quiz
Fill in the blanks with one or more words to check your progress in Unit I.
1. Bacteria cause viscosity ____________________ in batch mixed gels.
2. The most favorable environment for bacteria are ___________________ frac tanks and
____________________ water.
3. Bacteria feed on gel by releasing ____________________.
4. BE-3 degrades at pH’s greater than __________.
5. BE-3 should be added to the ________________ load of water in the tank.
6. _____ BE-5 container(s) should be added to each 20,000 gal frac tank with the ________________
load of water.
7. BE-6 has a ___________________ rate of kill and controls growth by inhibiting the
____________________ pathway of the bacteria.
8. To kill bacteria, caustic should be added until pH of the water is above __________ throughout the
tank.
9. After treating a frac tank with CAT-1, ____________________ must be added to
____________________ the treated water prior to gelling.
Now, look up the suggested answers in the Answer Key at the back of this section.
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Unit I: Conductivity Enhancers
SandWedgeTM
The conductivity enhancement additives came as
a direct result of research to find a liquid
proppant flowback control additive. The
SandWedge materials that were produced and
are continuously being improved were found to
have the unique property of improving the flow
of fluids through proppant. There are three
mechanisms that allow this to happen:
• Coating each grain improves breaker
efficiency. When the proppant is coated withSandWedge, gel cannot coat the proppant.
This property increases proppant
conductivity in two ways. First the breakers
are more efficient as they are able to break
gels by having more “break” sites availableto them and secondly, the proppant pack
itself is not susceptible to gel damage.
• Porosity improvement in low stress
environments. In closure stresses less than
4,000 psi, the porosity of the proppant pack,
when treated with SandWedge, retains its
cubic porosity pattern. At this pattern, the
pack has about 48% porosity. At 4,000 psi
closure, the majority of the pack is in a
rhombohedral packing and the pack porosity
is reduced to 26%. In proppant packs,
porosity is directly related to permeability;
therefore, the higher the porosity the higher
the permeability of the pack.
• SandWedge alters vertical proppant
distribution during the settling process. A
further benefit of SandWedge’s tackiness is
that proppant tends to form in clumps or bundles. This has the effect of causing the
proppant mass to maintain its cubic porosity
shape until acted on by closure forces
greater than 4,000 psi. This occurrence
requires that frac fluid flow through themass rather than around it during settling.
That impacts proppant settling in a positive
way.
SandWedgeTM NT
SandWedgeTM NT, which uses the dry proppant
coating method, was designed to make
SandWedgeTM compatible with most frac fluids
and surfactants. Dry coating means that instead
of adding the material to a fracturing fluid with
proppant already in it, SandWedgeTM NT is
allowed to coat the proppant before being
introduced to the fluid. It greatly reduces the
sensitivity to high pH fluids and high salt
concentrations. While the core of SandWedgeTM
remains the same, NT uses a safer and more
environmentally friendly solvent than the
previous version. SandWedgeTM NT can thus be
used in many more frac fluids because
incompatibility issues have been greatly
reduced.
C o n d u c t i v i t y ( m d
- f t )
SandWedgeTreatment
20/40 Sand—NoTreatment
Fibrous Strips
Closure Stress, psi
500045004000350030002500200015001000500
02000
3000 40006000
Figure 6.16 -
SandwedgeTMXS
SandWedgeTM XS is designed for wells in which
proppant flow back is identified as the primary
source for declines in production. The addition
of 5% ER-1 will make SandWedgeTM NT 10-20
times more sticky and greatly increase the
proppant packs resistance to flow back. If XS is
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Fracturing Fluids and Materials
run, a reduction in conductivity can be expected,
in the range of 10-15%.
Note SandWedgeTM XS is a conductivity
enhancer, NOT a proppant flowback additive. It
will not stop proppant flowback under harsh
conditions of high flowback rates or hightemperatures.
ER-1
ER-1 resin is a clear, viscous liquid that is mixed
with SandWedge™ polymer before the job, or
added on-the-fly into the blender tub during a
SandWedge™ NT dry-coat treatment. The resin
additive increases the molecular weight of
SandWedge™ polymer by partially crosslinking
it, greatly increasing its viscosity, tackiness, and
resistance to high-velocity flow. Typically, ER-1
resin is used at a concentration of 5%, based onthe SandWedge™NT volume. If high
concentrations of ER-1 resin are used withSandWedge™ polymer (>25%), a high-strength
thermoplastic polymer can result from the high
degree of crosslinking.
Unit I Quiz
Fill in the blanks with one or more words to check your progress in Unit I.
1. What are three ways SandWedgeTM improves fluid flow through proppant?
_____________________________
_____________________________
_____________________________
2. The porosity of a proppant pack may be improved at closure stresses below __________ psi.
3. SandWedgeTM NT is an improvement over SandWedgeTM because it uses a ____________________
_____________________ method and because it has a safer, more environmentally friendly
____________________.
4. SandwedgeTM XS is designed for wells in which ____________________ ____________________ is
identified as the primary source for declines in production.
5. SandwedgeTM XS will not stop proppant flowback under harsh conditions of high
____________________ rates or high ____________________.
Now, look up the suggested answers in the Answer Key at the back of this section.
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Fracturing Fluids and Materials
Self-Check Test for Section 6
Mark the single best answer to the following questions.
1. A buffer is a mixture of ____________________ and ____________________ of these
____________________.
2. List a swelling clay. ____________________
3. Cla-Sta compounds are most effective in a __________ - __________.
4. Fluid loss additives are used to slow down the ____________________ of the fracturing fluid into the
formation.
5. Surfactants are ____________________ ____________________ agents. Surfactants have been
developed to ____________________ fluid retention in a formation.
6. Surfactants are classified into four major groups depending upon the nature of the water-soluble
group. What are they?
____________________
____________________
____________________
____________________
7. Wettability indicates whether a solid is coated with ____________________ or
___________________.
8. Sandstone is negatively charged and water wet. Which surfactant group will leave sandstone in a
water wet condition? ___________________
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Fracturing Fluids and Materials
9. Name 2 factors that will affect the hydration rate of polymers.
___________________________________________
___________________________________________
10. What does a crosslinker do?
_____________________________________________________________________________
_____________________________________________________________________________
11. Name two variables dictate which crosslinker to use?
________________________________________
________________________________________
12. Name the 3 classes of chemical breaker we use
________________________
________________________
________________________
13. Enzyme breakers are only effective in a relatively narrow range of ____________________ and
________________ levels.
14. ViCon HT is of the group of ____________________ type breakers.
15. CAT-3 can be used to ________________ __________ break times.
16. What are 3 ways to stabilize gels?
____________________________________
____________________________________
____________________________________
17. Bacteria feeds on gel by releasing ____________________.
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Fracturing Fluids and Materials
18. Which Halliburton product should be chosen if a “quick kill” biocide is needed? ________________
19. SandWedgeTM is sold as a ____________________ ____________________, not for
____________________ ____________________.
20. Which SandWedgeTM product is for dry coating proppant? ____________________