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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

© 2005, Halliburton 6 • 1 Stimulation I




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






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





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.





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.





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.





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.






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





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.





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.






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





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.





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.





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.





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.






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





• 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.





Characteristics of CMHEC include:

• Residue free

• Can be used with brines

• Can be crosslinked


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:


• 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





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





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.





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.






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.





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





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.





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.






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





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





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,





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





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.





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.





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.






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





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





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.






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





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 ____________________.






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? ___________________





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 ____________________.





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? ____________________

Frac-fluid

Documents

unit d

unit c quiz

unit b quiz

clay control additives

fluid loss control additives

surfactant definition

surfactant usage

surfactant composition