**6.6. Problem 6: preventing bacterial proliferation**

collapse as soon as the applied pressure decreased due to the weight of the overlying rock. Hydrofrackers use proppants to prop the fractures open. Proppants need to be strong enough not to fracture or be crushed during the fracking process or during the producing life of the well. By far the most common proppant used in the USA to date is so called "white" sand. White sand is high-purity silica sand with few other minerals. This gives the sand its light color and relatively uniform chemical and physical properties. Prior to use the sand is washed and sieved to produce a more uniform size distribution. Multiple sizes are used, with smaller particles injected first to infiltrate farthest into the newly fractured bedrock and larger sand particles used near the end of the process to better match the larger aperture near the well. The volume of sand used in the hydrofracking industry is considerable. The US Geological Survey reports that sand and gravel production in the USA more than doubled between 2010 and 2014, with more than 70% of the total 2014 sand production being used by the hydrofracking industry! [23].

Sand is not the only proppant. Ceramic proppants of various formulations allow for a more uniform manufactured proppant with specific beneficial properties. Ceramic proppant can be manufactured with properties that make them better than sand, such as higher sphericity, more uniformity of size, and more crush resistant. Formations hydrofracked with ceramic proppants have higher conductivity than those propped with sand. Many other materials have been used as proppants

Proppants by their nature are inert and nonpolluting, but not without environmental impact. The landscape of rural Wisconsin is being transformed by mines that provide roughly 9000

Sand or ceramic proppants are more than twice as dense as water. Gelling agents and crosslinking polymers are added to the fracking fluid to increase the water's density and help keep the proppants suspended. Various guar formulations are the typical gelling agents. This is the same plant-based material seen as an emollient on processed food. Other plant-based gelling

The polymers and organic material described in Sections 6.1 and 6.3 keep proppants in solution, adjust the water's density, and decrease friction, making fracking possible. These same chemicals can then restrict the flow of natural gas out of the formation by clogging the newly created fractures and lowering the conductivity of the fractured rock. Therefore, an additional additive breaks these chemicals up into smaller molecules that will not clog the fractures. These "breakers" are usually enzymes that cut the organic chemicals into smaller pieces.

Additional chemical additives include pH adjusters, corrosion inhibitors, clay stabilizers, scale inhibitors, and metal precipitation inhibitors that are added to the hydrofracking fluid. In general these prevent mineral precipitates and particulates from clogging fractures and

including resin-coated sand, resin-impregnated crushed walnut shell, and thermoplastics.

truckloads of fracking sand per day [24].

agents are used as well.

46 Aquifers - Matrix and Fluids

inhibiting flow in the well.

**6.3. Problem 3: keeping everything in solution**

**6.5. Problem 5: preventing corrosion, scale, etc.**

**6.4. Problem 4: keeping the propped fractures open for flow**

Many of the additives in hydrofracking solution, including the breaker, surfactant, gelling agent, cross-linkers, surfactants, and friction reducers, are organic chemicals. All of these are substrates for microorganisms to feed on. Proliferation of microorganisms creates biomass. The biofilm on surfaces made up of living and dead microbes can lower porosity and gas permeability by lowering the fracture aperture. This is the same effect seen in bioremediation of aquifers where the stimulation of the native flora choke off conductivity. Biocide is added to fracking fluid to prevent this counterproductive effect.

Among all the chemicals used to formulate hydrofracking fluid, it is the biocides that are of most concern for water quality. Fewer than 20 biocides have been identified as more or less commonly used in the hydrofracking industry. Among the most common are glutaraldehyde, dibromonitrilopropionamide (DBNPA), tetrakis(hydroxymethy)phosphonium sulfate, and chlorine dioxide [25]. These biocides are toxic to microorganism, and some are quite toxic to aquatic fauna. They have low toxicity for mammals. Although they are not acutely toxic to mammals, some are toxic during long-term exposure or possess carcinogenicity or mutagenicity.

How do these hydrofracking chemicals get into the hydrosphere, and how do they become a threat to water resource quality? Chemicals must be transported to the site by rail or truck so accidents are of course a threat to surface water quality. Hydrofracking fluids are generally mixed on site and stored in railroad tank cars or in lined storage lagoons. It is not uncommon for lagoons lined with geotextile to leak at the geotextile seams or from punctures, so this could be a threat to shallow aquifers.

Once fully mixed hydrofracking fluid is injected into the target formation. Fluids travel first down through the vertical well and then into the horizontal portion being hydrofracked. Improperly cased and grouted wells could leak into shallow aquifers during high-pressure injection of the fracking fluid. Hydrofracking opponents in the USA have claimed that hydrofracking of shale gas formations can cause fractures to extend upward from the target shale formation, allowing fracking fluid to reach freshwater aquifers above. This is likely not a realistic fear. Freshwater aquifers are generally found within a few hundreds of meters of the ground surface. Shale gas formations that could be subject to hydrofracking are generally found thousands of meters below the ground, and the pressures used to hydrofrack are incapable of creating fractures of the length that would be required to reach a freshwater aquifer. It is possible however for hydrofracking fluid to flow upward through existing faults or abandoned wells.

There have been wide ranges reported, but between a quarter and half of the hydrofracking fluid injected to break the shale returns to the surface as flow-back subsequent to the frack. This hydrofracking fluid wastewater returns to the surface to the wellhead where it is collected. Wastewater can be treated onsite, treated offsite, treated and reused as hydrofracking fluid, or disposed of in a deep brine aquifer. This presents a number of additional opportunities for pollution of surface water or aquifers.

Hydrofracking wastewater that is treated offsite or treated and reused as hydrofracking fluid must be transported and so again poses the threats associated with transporting chemical-laden water. Wastewater treated onsite and then disposed of to a surface water body may not be sufficiently treated and could still contain some chemicals not removed by the

**7. Conclusion**

which are in the developing world.

availability and water quality.

**Author details**

Abdullah Faruque1

New York, USA

**References**

October 22, 2017]

likely be safe from chemical pollution due to fracking!

face water availability, and ultimately the recharge of our aquifers.

\* and Joshua Goldowitz2

\*Address all correspondence to: aafite@rit.edu

So, should we hydrofrack? On the positive side of the ledger, we need resources for an energy-hungry world. Although the Paris accords require countries to limit greenhouse gas emissions worldwide, fossil fuel consumption will continue to increase for decades. Also, on the positive side is that as we increase shale gas usage we have the opportunity to decrease the usage of coal for electricity production. Also, on the positive side of the ledger is the fact that shale gas production and export provide hard currency for exporting countries, some of

Effect of Hydrofracking on Aquifers http://dx.doi.org/10.5772/intechopen.72327 49

There are also significant considerations on the negative side of the ledger. It is an unassailable fact that hydrofracking will consumptively use vast volumes of freshwater, and a great deal of that usage will occur in regions already short on water resources. Pollution of water resources both in surface water and in aquifers due to hydrofracking is a reality. If we could hydrofrack the world's shale gas resource without human error, without equipment failure, and without any shortcuts taken to increase profits, then our freshwater resources would

Also, on the negative side of the ledger is the fact that methane is a significantly more potent greenhouse gas than carbon dioxide. Methane leaks during drilling, production, transportation, processing, distribution, and usage, and the effect these will have on the environment should be considered. Climate change caused by methane leaks will affect precipitation, sur-

We will develop our shale gas resource through the marriage of horizontal drilling and highvolume hydrofracking. The shale gas is simply too valuable and too tempting to leave in the ground. It is reasonable to accept that hydrofracking will have a negative effect on water

1 Civil Engineering Technology, Rochester Institute of Technology, New York, USA 2 Environmental Sustainability Health and Safety, Rochester Institute of Technology,

[1] Shooters – A "Fracking" History. American Oil and Gas Historical Society [Internet]. 2017. Available from: https://aoghs.org/technology/hydraulic-fracturing/ [Accessed:

**Figure 11.** Correlation between the number of earthquakes and the volume of fluid injected [26].

treatment process. Injecting wastewater into a deep brine aquifer again presents the hazard of leakage from improperly cased or grouted wells.

Hydraulic fracturing operations cause earthquakes. The USGS has reported a sharp increase in the number of potentially damaging earthquakes, those with a magnitude of three or larger in the Central and Eastern USA due to hydrofracking operation. There has been a 50-fold increase in M3+ quakes from an average of roughly 20 per year to over a thousand in 2015.

The realization that high-pressure injection of fluids into the deep subsurface can cause earthquakes is not new. In 1967 David Evans, a consulting geologist in Colorado, noted a correlation between injection volumes at a US Army hazardous waste injection well located at the Rocky Mountain Arsenal and earthquake frequency. His figure showing the correlation (**Figure 11**) became a staple of college-level geology textbooks. It was determined that the injection of wastes into the nearly 4000 feet deep well decreased frictional resistance to faulting. "The mechanism by which the fluid injection triggered the earthquakes is the reduction of frictional resistance to faulting, a reduction which occurs with increase in pore pressure" [26]. Disposal of waste fluids by injection into a deep well has triggered earthquakes near Denver, Colorado [26].

It should be obvious to all readers that the injection of millions of gallons of highly pressurized hydrofracking fluid into each well contributes to the notable increase in induced seismicity reported by the US Geological Survey. Less obvious is the reinjection of brine wastewater that is produced from the formation along with the hydrocarbons after hydrofracking.
