Fracturing Fluids and Additives

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Fracturing Fluids and Additives

This is an extract of the Document MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER, published by the Department of Energy of the United States.  

As described above, the current practice for hydraulic fracture treatments of shale gas reservoirs is to apply a sequenced pumping event in which millions of gallons of water‐based fracturing fluids mixed with proppant materials are pumped in a controlled and monitored manner into the target shale formation above fracture pressure (281).

The fracturing fluids used for gas shale stimulations consist primarily of water but also include a variety of additives. The number of chemical additives used in a typical fracture treatment varies depending on the conditions of the specific well being fractured. A typical fracture treatment will use very low concentrations of between 3 and 12 additive chemicals depending on the characteristics of the water and the shale formation being fractured. Each component serves a specific, engineered purpose (282). The predominant fluids currently being used for fracture treatments in the gas shale plays are water‐based fracturing fluids mixed with friction‐reducing additives (called slickwater)(283).

The addition of friction reducers allows fracturing fluids and proppant to be pumped to the target zone at a higher rate and reduced pressure than if water alone were used. In addition to friction reducers, other additives include: biocides to prevent microorganism growth and to reduce bio‐ fouling of the fractures; oxygen scavengers and other stabilizers to prevent corrosion of metal pipes; and acids that are used to remove drilling mud damage within the near‐wellbore area (284). These fluids are used not only to create the fractures in the formation but also to carry a propping agent (typically silica sand) which is deposited in the induced fractures.

Exhibit 35 demonstrates the volumetric percentages of additives that were used for a nine‐stage hydraulic fracturing treatment of a Fayetteville Shale horizontal well. The make‐up of fracturing fluid varies from one geologic basin or formation to another. Evaluating the relative volumes of the components of a fracturing fluid reveals the relatively small volume of additives that are present. The additives depicted on the right side of the pie chart represent less than 0.5% of the total fluid volume. Overall the concentration of additives in most slickwater fracturing fluids is a relatively consistent 0.5% to 2% with water making up 98% to 99.5%.


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Source: ALL Consulting based on data from a fracture operation in the Fayetteville Shale, 2008

Because the make‐up of each fracturing fluid varies to meet the specific needs of each area, there is no one‐size‐fits‐all formula for the volumes for each additive. In classifying fracturing fluids and their additives it is important to realize that service companies that provide these additives have developed a number of compounds with similar functional properties to be used for the same purpose in different well environments. The difference between additive formulations may be as small as a change in concentration of a specific compound. Although the hydraulic fracturing industry may have a number of compounds that can be used in a hydraulic fracturing fluid, any single fracturing job would only use a few of the available additives. For example, in Exhibit 35 there are 12 additives used, covering the range of possible functions that could be built into a fracturing fluid. It is not uncommon for some fracturing recipes to omit some compound categories if their properties are not required for the specific application.

Most industrial processes use chemicals and almost any chemical can be hazardous in large enough quantities or if not handled properly. Even chemicals that go into our food or drinking water can be hazardous. For example, drinking water treatment plants use large quantities of chlorine.
When used and handled properly, it is safe for workers and near‐by residents and provides clean, safe drinking water for the community. Although the risk is low, the potential exists for unplanned releases that could have serious effects on human health and the environment. By the same token, hydraulic fracturing uses a number of chemical additives that could be hazardous, but are safe when properly handled according to requirements and long‐standing industry practices. In addition, many of these additives are common chemicals which people regularly encounter in everyday life.


Additive Type

Main Compound(s)


Diluted Acid (15%)

Hydrochloric acid or muriatic acid

Help dissolve minerals and initiate cracks in the rock



Eliminates bacteria in the water that produce corrosive byproducts


Ammonium persulfate

Allows a delayed break down of the gel polymer chains

Corrosion Inhibitor

N,n‐dimethyl formamide

Prevents the corrosion of the pipe



Borate salts

Maintains fluid viscosity as temperature increases

Friction Reducer



Minimizes friction between the fluid and the pipe

Mineral oil


Guar gum or hydroxyethyl cellulose

Thickens the water in order to suspend the sand

Iron Control

Citric acid

Prevents precipitation of metal oxides




Potassium chloride

Creates a brine carrier fluid

Oxygen Scavenger

Ammonium bisulfite

Removes oxygen from the water to protect the pipe from corrosion


pH Adjusting Agent

Sodium or potassium carbonate

Maintains the effectiveness of other components, such as crosslinkers



Silica, quartz sand

Allows the fractures to remain open so the gas can escape

Scale Inhibitor

Ethylene glycol

Prevents scale deposits in the pipe



Used to increase the viscosity of the fracture fluid


Note: The specific compounds used in a given fracturing operation will vary depending on company preference, source water quality and site‐specific characteristics of the target formation. The compounds shown above are representative of the major compounds used in hydraulic fracturing of gas shales.

Exhibit 36 provides a summary of the additives, their main compounds, the reason the additive is used in a hydraulic fracturing fluid, and some of the other common uses for these compounds. Hydrochloric acid (HCl) is the single largest liquid component used in a fracturing fluid aside from water; while the concentration of the acid may vary, a 15% HCl mix is a typical concentration. A 15% HCl mix is composed of 85% water and 15% acid, therefore, the volume of acid is diluted by 85% with water in its stock solution before it is pumped into the formation during a fracturing treatment. Once the entire stage of fracturing fluid has been injected, the total volume of acid in an example fracturing fluid from the Fayetteville shale was 0.123%, which indicates the fluid had been diluted by a factor of 122 times before it is pumped into the formation. The concentration of this acid will only continue to be diluted as it is further dispersed in additional volumes of water that may be present in the subsurface. Furthermore, if this acid comes into contact with carbonate minerals in the subsurface, it would be neutralized by chemical reaction with the carbonate minerals producing water and carbon dioxide as a byproduct of the reaction.