Hydraulic Fracturing Fluids The Ultimate Guide

Fracturing Fluid Additives

There are a wide variety of chemical additives that are mixed into the fracturing fluid to achieve specific objectives and impart specific characteristics. In addition to considering reservoir rock and fracturing fluid compatibility, the design engineer must also be certain that the additives are compatible with each other. The highly complex fluid systems used today—especially the crosslinked fracturing fluids—are very sensitive to even small changes in additive concentrations.

Additives, while they are important contributors to the overall character of the fluid, make up a very small portion of the total volume (Figure 1). A typical slickwater treatment is more than 90 percent water, less than 10 percent sand proppant and less than one half of one percent additives, much of which are acid (pumped in the first stage), friction reducer, and surfactant. If we exclude the proppant, slickwater fracturing fluids are generally 99 percent water or more by volume. In the case of conventional gel-based fracturing fluids, polymers and surfactants can comprise as much as seven percent by volume of the total.

Typical additives used in fracturing treatments are described here. These additives are in addition to the basic viscosifiers that are used to make up linear gels or crosslinked gels.

Fracturing Fluid Additives

Fluid-Loss Additives

Extraneous solids have typically been added to fracturing fluids to reduce the amount of leakoff into the formation and improve fluid efficiency. The choice of materials for this purpose has been quite extensive, with the primary requirement being a mixture of widely ranged particle sizes that form a relatively impervious filter cake over the formation pores when the first amount of fluid leaks from the fracture void into the matrix. The material most commonly used in fracturing competent sandstone reservoirs is finely ground silica flour.

Larger-size silica particles (100/170 mesh, which is commonly referred to as “100 mesh”) have proven quite effective in reducing fluid leakoff into natural fractures.

Breakers and Breaker Retarders

Breakers usually enzymes, oxidizing agents or reducing agents attack the viscosifiers in the fracturing fluid, breaking the molecular chains and reducing the fluid viscosity. This reduced viscosity eases the return of the fluid trapped in the reservoir pores after the treatment and allows faster and more complete recovery of the treatment fluids. Ammonium persulfate is an example of a commonly used breaker.

The effectiveness of chemical breakers depends on their concentration and temperature. The concentration of breaker used in a large frac treatment is sometimes tapered so as to provide longer viscosity stability in the leading portion and a more rapid break in the last volume of fluid pumped. Breakers may start acting at the moment of addition, or be triggered by another factor such as temperature.

Breaker retarders, such as magnesium peroxide, can be used to delay the action of the breaker.

Biocides

Sometimes colonies of sulfate-reducing bacteria start to grow in oil reservoirs as a result of the introduction of untreated water into the reservoir during a workover operation. Growth of these bacteria can reduce permeability and accelerate corrosion. The use of recycled fracturing fluids containing enzyme viscosity breakers aggravates this situation. In order to cure and/or prevent this problem, small amounts of bacteria control agents (biocides) are often included in the fluid. Biocides typically consist of bromine-based solutions or glutaraldehyde.

Buffers

Buffers are used to adjust the pH of the makeup water used to prepare the fracturing fluid. Controlling the pH is necessary for regulating the rate at which the long-chain polymer solution develops (hydration) as well as the stability of the solution once it is formed. pH-lowering buffers are typically low molecular weight organic acids such as acetic or formic acid. pH-increasing buffers are typically carbonate or hydroxide compounds (sodium carbonate, potassium carbonate, sodium hydroxide and potassium hydroxide).

Acid

A dilute acid solution, used during the initial fracturing sequence, cleans out cement and debris around the perforations to facilitate the subsequent treatment stages. Hydrochloric acid is often used for this purpose.

Friction Reducers

Friction reducing agents such as potassium chloride or polyacrylamide-based compounds are used to reduce frictional pressure losses in the casing or tubing and subsequently reduce the pressure needed to pump fluid into the wellbore. The additives may reduce tubular friction by 50 to 60 percent. These friction-reducing compounds represent the “slick” component of the modern slickwater hydraulic fracturing solution.

Iron Precipitation Controllers

Iron precipitation control agents are used to inhibit precipitation of iron compounds by keeping them in a soluble form. By reducing ferric iron (Fe⁺³) to ferrous iron (Fe⁺²) and by scavenging oxygen, iron controllers help to prevent the precipitation of dissolved iron from solution. Such a precipitant, if deposited in the formation or proppant pack, can reduce permeability. Examples of iron controllers are citric acid, acetic acid, thioglycolic acid, sodium erythorbate.

Surfactants

Surfactants, such as ethylene glycol monobutyl ether are used to reduce the surface and interstitial tension of fracturing fluids. Their use reduces the amount of reservoir energy expended in removing the treatment fluids from the formation. They also act as frictional pressure drop reduction agents.

Stabilizers

Potassium chloride (KCl) is a low-cost salt commonly used as a clay-stabilization additive to prevent the water in the fracturing fluid from adversely affecting the clay particles present in the formation, and to ensure compatibility with the normally saline formation fluids. It is a common choice as it generally does not interfere with the performance of other additives. In some cases, additional clay control additives might be necessary. Other stabilizers include sodium chloride, calcium chloride, isopropanol, methanol, and ethylene glycol.

Defoamers

Defoamers are sometimes required to prevent handling problems at the surface during the pumping operation. High-rate fluid transfer frequently causes foaming, particularly if surfactants have been added to the fluid. Foaming can be more severe if brines are used instead of fresh water. Defoamers are typically surfactants or mutual solvents.

Demulsifiers

Formation fines or minute particles such as fluid-loss additives tend to initiate and stabilize emulsions. Demulsifiers may be required to prevent emulsions from forming between the fracturing fluid and formation fluids, improving fluid recovery. Lauryl sulfate and derivatives are commonly used.

Scale Inhibitors

A scale inhibitor may be added to control the precipitation of certain carbonate and sulfate minerals within the formation or the wellbore tubular. Phosphonic acid salt, sodium polycarboxylate, sodium acrylate and copolymers of acrylamide are examples of scale inhibitors.

Other Additives

• Corrosion inhibitors such as acetaldehyde and oxygen scavengers may be added to prevent degradation of the steel casing.
• Crosslinkers create links between long polymer chains to increase gelled fluid viscosity.Potassium metaborate, sodium tetraborate, boric acid, and chelated zirconium are commonly used.
• If delay of the crosslinking is desirable, magnesium oxide is often used.
• Petroleum distillates (diesel, naphthalene) are sometimes used as a carrier fluid to carry gelling agents, friction reducers and crosslinkers.