This document discusses fracturing fluids and proppants used in hydraulic fracturing. It describes the main types of fracturing fluids - water-based, oil-based, acid-based, and multiphase fluids - and lists their purposes and components. Water-based fluids are the most widely used due to their low cost and performance. The document also outlines various additives used in fracturing fluids to control viscosity, fluid loss, pH and bacteria. Finally, it discusses proppants which are used to hold open fractures, noting the factors that influence fracture conductivity such as proppant composition, strength, size and quantity.

1. Well Stimulation
Fracturing Fluid Chemistry and Proppants
Zohrab Javad-zadeh

2. Outline
• Introduction
• Water-base fluids
• Oil-base fluids
• Acid-based fluids
• Multiphase fluids
• Additives
• Proppants

3. Introduction
• The fracturing fluid is a critical component of the hydraulic fracturing
treatment. Its main functions are to open the fracture and to transport
propping agent along the length of the fracture. Consequently, the viscous
properties of the fluid are usually considered the most important. However,
successful hydraulic fracturing treatments require that the fluids have other
special properties. In addition to exhibiting the proper viscosity in the
fracture, they should break and clean up rapidly once the treatment is over,
provide good fluid-loss control, exhibit low friction pressure during pumping
and be as economical as is practical.

4. Water-base fluids
• Because of their low cost, high performance and
ease of handling, water-base fluids are the most
widely used fracturing fluids. Many water-
soluble polymers can be used to make a
viscosified solution capable of suspending
proppants at ambient temperature. However, as
the temperature increases, these solutions thin
significantly. The polymer concentration
(polymer loading) can be increased to offset
thermal effects, but this approach is expensive.
Instead, crosslinking agents are used to
significantly increase the effective molecular
weight of the polymer, thereby increasing the
viscosity of the solution.

5. Water-base fluids
• One of the first polymers used to viscosify water
for fracturing applications was guar gum. Guar is a
long-chain, high-molecular-weight polymer
composed of mannose and galactose sugars.
Polymers composed of sugar units are called
polysaccharides. Guar gum comes from the
endosperm of guar beans, which are grown mainly
in Pakistan and India. The beans are removed from
the bean pod and processed to separate the
endosperm from the bean hull and embryo
(splits), and the splits are ground into a powder.
The guar polymer has a high affinity for water.
When the powder is added to water, the guar
particles swell and hydrate, which means the
polymer molecules become associated with many
water molecules and unfold and extend out into
the solution. The guar solution on the molecular
level can be pictured as bloated strands suspended
in water. The strands tend to overlap and hinder
motion, which elevates the viscosity of the
solution.

6. Oil-base fluids
• Heavy oils were used originally as fracturing fluids, primarily because these fluids were perceived
as less damaging to a hydrocarbon-bearing formation than water-base fluids. Their inherent
viscosity also makes them more attractive than water. Oil-base fluids are expensive to use and
operationally difficult to handle. Therefore, they are now used only in formations that are known
to be extremely water-sensitive.

7. Acid-based fluids
Acid fracturing is a well stimulation process in which acid, usually hydrochloric acid (HCl), is injected into a
carbonate formation at a pressure sufficient to fracture the formation or to open existing natural fractures. As
the acid flows along the fracture, portions of the fracture face are dissolved. Because flowing acid tends to etch
in a nonuniform manner, conductive channels are created that usually remain when the fracture closes. The
effective length of the fracture is determined by the etched length, which depends on the volume of acid used,
its reaction rate and the acid fluid loss from the fracture into the formation. The effectiveness of the acid
fracturing treatment is determined largely by the length of the etched fracture.
In some cases, especially in carbonates, a choice exists between acid and propped fracturing treatments.
Operationally, acid fracturing is less complicated because no propping agent is employed. Also, the danger of
proppant screenout and the problems of proppant flowback and cleanout from the wellbore after the treatment
are eliminated. However, acid is more expensive than most nonreactive treating fluids.
The major barrier to effective fracture penetration by acid appears to be excessive fluid loss. Fluid loss is a
greater problem when using acid than when using a nonreactive fluid. The constant erosion of fracture faces
during treatment makes it difficult to deposit an effective filtercake barrier. In addition, acid leakoff is extremely
nonuniform and results in wormholes and the enlargement of natural fractures. This greatly increases the
effective area from which leakoff occurs and makes fluid-loss control difficult.

8. Multiphase fluids
• There are situations in which the properties of standard water-base, oil-base or
acid-based fluids can be external filter cake vulnerable to shear degradation by
the fluid. During a fracturing treatment, fluid loss occurs under dynamic
conditions (i.e., fluid flows along the face of the formation). Prud’homme and
Wang (1993) proposed that the extent to which the thickness of the filter cake
grows is controlled by the shear stress τ exerted by the fluid at the wall of the
cake and the yield stress of the cake. The cake stops growing when the fluid
stress becomes equal to the yield stress of the cake, and it starts to erode when
the fluid stress is larger than the yield stress of the cake. The yield stress of a
polymer cake depends on the polymer concentration and pressure gradient in
the cake, whereas the shear stress of the fluid is determined by the rheological
properties of the fluid and the shear rate γ at the formation face.

9. Additives
A fracturing fluid is generally not simply a liquid and viscosifying material, such as water and HPG polymer or diesel oil and aluminum phosphate ester
polymer. Various additives are used to break the fluid once the job is over, control fluid loss, minimize formation damage, adjust pH, control bacteria
or improve high-temperature stability. Care must be taken when using multiple additives to determine that one additive does not interfere with the
function of another additive.
• Crosslinkers. A number of metal ions can be used to crosslink water-soluble polymers. Borate, Ti(IV), Zr(IV) and Al(III) compounds are frequently
used crosslinkers.
• Breakers. Relatively high viscosity fluids are used to transport proppant into the fracture. Leaving a high-viscosity fluid in the fracture would reduce
the permeability of the proppant pack to oil and gas, limiting the effectiveness of the fracturing treatment. Gel breakers are used to reduce the
viscosity of the fluid intermingled with the proppant. Breakers reduce viscosity by cleaving the polymer into small-molecular-weight fragments.
• Fluid-loss additives. Good fluid-loss control is essential for an efficient fracturing treatment. Several types of materials are used to provide fluid-loss
control, but the effectiveness of the various types depends on the type of fluid-loss problem: loss to low- or high-permeability matrix or loss to
microfractures.
• Bactericides. Bactericides are added to polymer-containing aqueous fracturing fluids to prevent viscosity loss caused by bacterial degradation of
the polymer.
• Stabilizers. Stabilizers are used to prevent degradation of polysaccharide gels at temperatures above 200°F. The common stabilizers are methanol
and sodium thiosulfate (Na2S2O3). Methanol is more hazardous to handle and is used as 5% to 10% of the fluid volume. Sodium thiosulfate is
generally used at 10 to 20 lbm/1000 gal. Sodium thiosulfate is the more effective of the two, increasing the viscosity at elevated temperatures by a
factor of 2 to 10, depending on the temperature and time of exposure to temperature.
• Surfactants. A surface-active agent, or surfactant, is a material that at low concentration adsorbs at the interface between two immiscible
substances. The immiscible substances may be two liquids, such as oil and water, a liquid and a gas, or a liquid and a solid.
• Clay stabilizers. Clays are layered particles of silicon and aluminum oxide averaging 2 μm in size. Negatively charged particles result when the charge
balance between positive (aluminum) and negative (oxygen) is disrupted through displacement of cations or breaking of the particles. Cations,
from solution, surround the clay particle and create a positively charged cloud. Such particles repel each other and are prone to migration. Once
clay particles are dispersed, the particles can block pore spaces in the rock and reduce permeability.

10. Proppants
Proppants are used to hold the walls of the fracture apart to create a
conductive path to the wellbore after pumping has stopped and the
fracturing fluid has leaked off. Placing the appropriate concentration
and type of proppant in the fracture is critical to the success of a
hydraulic fracturing treatment. Factors affecting the fracture
conductivity (a measurement of how a propped fracture is able to
convey the produced fluids over the producing life of the well) are
• proppant composition
• physical properties of the proppant
• proppant-pack permeability
• effects of postclosure polymer concentration in the fracture
• movement of formation fines in the fracture
• long-term degradation of the proppant.
The physical properties of proppants that have an impact on fracture
conductivity are
• proppant strength
• grain size and grain-size distribution
• quantities of fines and impurities
• roundness and sphericity
• proppant density.
Strength comparisons are
shown in Fig. 7-14. The
following general guidelines
may be used to select
proppants based on strength
and cost:
• sand—closure stresses less
than 6000 psi
• resin-coated proppant
(RCP)—closure stresses less
than 8000 psi
• intermediate-strength
proppant (ISP)—closure
stresses greater than 5,000
psi but less than 10,000 psi
• high-strength proppant—
closure stresses at or greater
than 10,000 psi.