Hydraulic Fracture Drilling-Part 2

Fracturing fluids

Water tanks preparing 

for a frac job

Note detailed list of fluids used in fracking below.

High-pressure fracture fluid is injected into the wellbore, with the pressure above the fracture gradient of the rock. The two main purposes of fracturing fluid is to extend fractures, add lubrication, change gel strength and to carry proppant into the formation, the purpose of which is to stay there without damaging the formation or production of the well. Two methods of transporting the proppant in the fluid are used – high-rate and high-viscosity. High-viscosity fracturing tends to cause large dominant fractures, while high-rate (slickwater) fracturing causes small spread-out micro-fractures.


This fracture fluid contains water-soluble gelling agents (such as guar gum) which increase viscosity and efficiently deliver the proppant into the formation.

Process of mixing water with

fracking fluids to be injected into

the ground

The fluid injected into the rock is typically a slurry of water, proppants, and chemical additives. Additionally, gels, foams, and compressed gases, including nitrogen, carbon dioxide and air can be injected. Typically, of the fracturing fluid 90% is water and 9.5% is sand with the chemical additives accounting to about 0.5%. However, fracturing fluids have been developed in which the use of water has been made unnecessary, using liquefied petroleum gas (LPG) and propane.

A proppant is a material that will keep an induced hydraulic fracture open, during or following a fracturing treatment, and can be gel, foam, or slickwater-based. Fluids make tradeoffs in such material properties as viscosity, where more viscous fluids can carry more concentrated proppant; the energy or pressure demands to maintain a certain flux pump rate (flow velocity) that will conduct the proppant appropriately; pH, various rheological factors, among others. Types of proppant include silica sand, resin-coated sand, and man-made ceramics. These vary depending on the type of permeability or grain strength needed. The most commonly used proppant is silica sand, though proppants of uniform size and shape, such as a ceramic proppant, is believed to be more effective. Due to a higher porosity within the fracture, a greater amount of oil and natural gas is liberated.

The fracturing fluid varies in composition depending on the type of fracturing used, the conditions of the specific well being fractured, and the water characteristics. A typical fracture treatment uses between 3 and 12 additive chemicals. Although there may be unconventional fracturing fluids, the more typically used chemical additives can include one or more of the following:

• Acids—hydrochloric acid (usually 5%-28%), or acetic acid is used in the pre-fracturing stage for cleaning the perforations and initiating fissure in the near-wellbore rock.
• Sodium chloride (salt)—delays breakdown of the gel polymer chains.
• Polyacrylamide and other friction reducers—minimizes the friction between fluid and pipe, thus allowing the pumps to pump at a higher rate without having greater pressure on the surface.
• Ethylene glycol—prevents formation of scale deposits in the pipe.
• Borate salts—used for maintaining fluid viscosity during the temperature increase.
• Sodium and potassium carbonates—used for maintaining effectiveness of crosslinkers.
• Glutaraldehyde—used as disinfectant of the water (bacteria elimination).
• Guar gum and other water-soluble gelling agents—increases viscosity of the fracturing fluid to deliver more efficiently the proppant into the formation.
• Citric acid—used for corrosion prevention.
• Isopropanol—increases the viscosity of the fracture fluid.

The most common chemical used for hydraulic fracturing in the United States in 2005–2009 was methanol, while some other most widely used chemicals were isopropyl alcohol, 2-butoxyethanol, and ethylene glycol.

Typical fluid types are:

• Conventional linear gels. These gels are cellulose derivatives (carboxymethyl cellulose, hydroxyethyl cellulose, carboxymethyl hydroxyethyl cellulose, hydroxypropyl cellulose, methyl hydroxyl ethyl cellulose), guar or its derivatives (hydroxypropyl guar, carboxymethyl hydroxypropyl guar) based, with other chemicals providing the necessary chemistry for the desired results.
• Borate-crosslinked fluids. These are guar-based fluids cross-linked with boron ions (from aqueous borax/boric acid solution). These gels have higher viscosity at pH 9 onwards and are used to carry proppants. After the fracturing job the pH is reduced to 3–4 so that the cross-links are broken and the gel is less viscous and can be pumped out.
• Organometallic-crosslinked fluids zirconium, chromium, antimony, titanium salts are known to crosslink the guar based gels. The crosslinking mechanism is not reversible. So once the proppant is pumped down along with the cross-linked gel, the fracturing part is done. The gels are broken down with appropriate breakers.
• Aluminium phosphate-ester oil gels. Aluminium phosphate and ester oils are slurried to form cross-linked gel. These are one of the first known gelling systems.

For slickwater it is common to include sweeps or a reduction in the proppant concentration temporarily to ensure the well is not overwhelmed with proppant causing a screen-off. As the fracturing process proceeds, viscosity reducing agents such as oxidizers and enzyme breakers are sometimes then added to the fracturing fluid to deactivate the gelling agents and encourage flowback. The oxidizer reacts with the gel to break it down, reducing the fluid's viscosity and ensuring that no proppant is pulled from the formation. An enzyme acts as a catalyst for the breaking down of the gel. Sometimes pH modifiers are used to break down the crosslink at the end of a hydraulic fracturing job, since many require a pH buffer system to stay viscous. At the end of the job the well is commonly flushed with water (sometimes blended with a friction reducing chemical) under pressure. Injected fluid is to some degree recovered and is managed by several methods, such as underground injection control, treatment and discharge, recycling, or temporary storage in pits or containers while new technology is continually being developed and improved to better handle waste water and improve re-usability.

Fracture monitoring

Measurements of the pressure and rate during the growth of a hydraulic fracture, as well as knowing the properties of the fluid and proppant being injected into the well provides the most common and simplest method of monitoring a hydraulic fracture treatment. This data, along with knowledge of the underground geology can be used to model information such as length, width and conductivity of a propped fracture.

Injection of radioactive tracers, along with the other substances in hydraulic-fracturing fluid, is sometimes used to determine the injection profile and location of fractures created by hydraulic fracturing. The radiotracer is chosen to have the readily detectable radiation, appropriate chemical properties, and a half life and toxicity level that will minimize initial and residual contamination. Radioactive isotopes chemically bonded to glass (sand) and/or resin beads may also be injected to track fractures. For example, plastic pellets coated with 10 GBq of Ag-110mm may be added to the proppant or sand may be labelled with Ir-192 so that the proppant's progress can be monitored. Radiotracers such as Tc-99m and I-131 are also used to measure flow rates. The Nuclear Regulatory Commission publishes guidelines which list a wide range of radioactive materials in solid, liquid and gaseous forms that may be used as tracers and limit the amount that may be used per injection and per well of each radionuclide.

Microseismic monitoring

For more advanced applications, microseismic monitoring is sometimes used to estimate the size and orientation of hydraulically induced fractures. Microseismic activity is measured by placing an array of geophones in a nearby wellbore. By mapping the location of any small seismic events associated with the growing hydraulic fracture, the approximate geometry of the fracture is inferred. Tiltmeter arrays, deployed on the surface or down a well, provide another technology for monitoring the strains produced by hydraulic fracturing.

Microseismic mapping is very similar geophysically to seismology. In earthquake seismology seismometers scattered on or near the surface of the earth record S-waves and P-waves that are released during an earthquake event. This allows for the motion along the fault plane to be estimated and its location in the earth’s subsurface mapped. During formation stimulation by hydraulic fracturing an increase in the formation stress proportional to the net fracturing pressure as well as an increase in pore pressure due to leakoff takes place. Tensile stresses are generated ahead of the fracture/cracks’ tip which generates large amounts of shear stress. The increase in pore water pressure and formation stress combine and affect the weakness (natural fractures, joints, and bedding planes) near the hydraulic fracture. Dilatational and compressive reactions occur and emit seismic energy detectable by highly sensitive geophones placed in nearby wells or on the surface.

Different methods have different location errors and advantages. Accuracy of microseismic event locations is dependent on the signal to noise ratio and the distribution of the receiving sensors. For a surface array location accuracy of events located by seismic inversion is improved by sensors placed in multiple azimuths from the monitored borehole. In a downhole array location accuracy of events is improved by being close to the monitored borehole (high signal to noise ratio).

Monitoring of microseismic events induced by reservoir stimulation has become a key aspect in evaluation of hydraulic fractures and their optimization. The main goal of hydraulic fracture monitoring is to completely characterize the induced fracture structure and distribution of conductivity within a formation. This is done by first understanding the fracture structure. Geomechanical analysis, such as understanding the material properties, in-situ conditions and geometries involved will help with this by providing a better definition of the environment in which the hydraulic fracture network propagates.The next task is to know the location of proppant within the induced fracture and the distribution of fracture conductivity. This can be done using multiple types of techniques and finally, further develop a reservoir model than can accurately predict well performance.

Horizontal completions

Since the early 2000s, advances in drilling and completion technology have made drilling horizontal wellbores much more economical. Horizontal wellbores allow for far greater exposure to a formation than a conventional vertical wellbore. This is particularly useful in shale formations which do not have sufficient permeability to produce economically with a vertical well. Such wells when drilled onshore are now usually hydraulically fractured in a number of stages, especially in North America. The type of wellbore completion used will affect how many times the formation is fractured, and at what locations along the horizontal section of the wellbore.

In North America, shale reservoirs such as the Bakken, Barnett, Monterey, Haynesville, Marcellus, and most recently the Eagle Ford, Niobrara and Utica shales are drilled, completed and fractured using this method. The method by which the fractures are placed along the wellbore is most commonly achieved by one of two methods, known as "plug and perf" and "sliding sleeve".

The wellbore for a plug and perf job is generally composed of standard joints of steel casing, either cemented or uncemented, which is set in place at the conclusion of the drilling process. Once the drilling rig has been removed, a wireline truck is used to perforate near the end of the well, following which a fracturing job is pumped (commonly called a stage). Once the stage is finished, the wireline truck will set a plug in the well to temporarily seal off that section, and then perforate the next section of the wellbore. Another stage is then pumped, and the process is repeated as necessary along the entire length of the horizontal part of the wellbore.

The wellbore for the sliding sleeve technique is different in that the sliding sleeves are included at set spacings in the steel casing at the time it is set in place. The sliding sleeves are usually all closed at this time. When the well is ready to be fractured, using one of several activation techniques, the bottom sliding sleeve is opened and the first stage gets pumped. Once finished, the next sleeve is opened which concurrently isolates the first stage, and the process repeats. For the sliding sleeve method, wireline is usually not required.


These completion techniques may allow for more than 30 stages to be pumped into the horizontal section of a single well if required, which is far more than would typically be pumped into a vertical well.

Economic impacts

Hydraulic fracturing has been seen as one of the key methods of extracting unconventional oil and gas resources. According to the International Energy Agency, the remaining technically recoverable resources of shale gas are estimated to amount to 208 trillion cubic metres (208,000 km³), tight gas to 76 trillion cubic metres (76,000 km³), and coalbed methane to 47 trillion cubic metres (47,000 km³). As a rule, formations of these resources have lower permeability than conventional gas formations. Therefore, depending on the geological characteristics of the formation, specific technologies (such as hydraulic fracturing) are required. Although there are also other methods to extract these resources, such as conventional drilling or horizontal drilling, hydraulic fracturing is one of the key methods making their extraction economically viable. The multi-stage fracturing technique has facilitated the development of shale gas and light tight oil production in the United States and is believed to do so in the other countries with unconventional hydrocarbon resources.

The National Petroleum Council estimates that hydraulic fracturing will eventually account for nearly 70% of natural gas development in North America. Hydraulic fracturing and horizontal drilling apply the latest technologies and make it commercially viable to recover shale gas and oil. In the United States, 45% of domestic natural gas production and 17% of oil production would be lost within 5 years without usage of hydraulic fracturing.

A number of studies related to the economy and fracking, demonstrates a direct benefit to economies from fracking activities in the form of personnel, support, ancillary businesses, analysis and monitoring. Typically the funding source of the study is a focal point of controversy. Most studies are either funded by mining companies or funded by environmental groups, which can at times lead to at least the appearance of unreliable studies. An unbiased study was performed by Deller & Schreiber in 2012, looking at the relationship between non-oil and gas mining and community economic growth. The study concluded that there is an impact on income growth; however, researchers found that mining does not lead to an increase in population or employment. The actual financial impact of non-oil and gas mining on the economy is dependent on many variables and is difficult to identify definitively.

Environmental impact

Hydraulic fracturing has raised environmental concerns and is challenging the adequacy of existing regulatory regimes. These concerns have included ground water contamination, risks to air quality, migration of gases and hydraulic fracturing chemicals to the surface, mishandling of waste, and the health effects of all these, as well as its contribution to raised atmospheric CO₂ levels by enabling the extraction of previously-sequestered hydrocarbons. Because hydraulic fracturing originated in the United States, its history is more extensive there than in other regions. Most environmental impact studies have therefore taken place there.

Research issues

Several organizations, researchers, and media outlets have reported difficulty in conducting and reporting the results of studies on hydraulic fracturing due to industry and governmental pressure, and expressed concern over possible censoring of environmental reports., though work by National Science Foundation, the EPA and several universities has been considered unbiased. Concerns have been raised about the role of wealthy foundations in financing research that some have argued was designed to inflate the risks of development, and lobbying by the gas industry to promote its activities. The broader debate over these topics provides an example of the research challenges on this subject. Researchers have recommended requiring disclosure of all hydraulic fracturing fluids, testing animals raised near fracturing sites, and closer monitoring of environmental samples. After court cases concerning contamination from hydraulic fracturing are settled, the documents are sealed, and at least one recent case bears that out, while others believe it has and could lead to unnecessary risks to public safety and health. The American Petroleum Institute denies that this practice has hidden problems with gas drilling.

Air

The air emissions from hydraulic fracturing are related to methane leaks originating from wells, and emissions from the diesel or natural gas powered equipment such as compressors, drilling rigs, pumps etc. Also transportation of necessary water volume for hydraulic fracturing, if done by trucks, can cause high volumes of air emissions, especially particulate matter emissions. There are also reports of health problems around compressors stations or drilling sites, although a causal relationship is not established and one Texas analysis found no evidence of effects.

Natural gas produced by hydraulic fracturing causes higher well-to-burner emissions than gas produced from conventional wells. Although a recent report coauthored by researchers at the U.S. Department of Energy’s National Renewable Energy Laboratory  found emissions from shale gas, when burned for electricity, were “very similar” to those from so-called “conventional well” natural gas, hydraulic fracturing's higher emissions profile is mainly due to the gas released during completing wells as some gas returns to the surface, together with the fracturing fluids. Depending on their treatment, the well-to-burner emissions are 3.5%–12% higher than for conventional gas. Other studies have found different effects, and a debate has arisen particularly around a study by professor Robert W. Howarth finding shale gas significantly worse for global warming than oil or coal and various others criticizing the analysis. Howarth has responded that "The latest EPA estimate for methane emissions from shale gas falls within the range of our estimates but not those of Cathles et al., which are substantially lower." The U.S. EPA has estimated the methane leakage rate to be about 2.4% – well below Howarth’s estimate. The American Gas Association, and industry trade group, calculated a 1.2% leakage rate  based on the EPA's latest greenhouse gas inventory, although the EPA has not publicly stated a change to its prior estimate.