Senior Teaching Resources

Table of contents

EPA Details What We Need To Do
USGS Programs Managed By Water Resources Discipline
General Water Resource Index
The Hydraulic Fracturing Water Cycle 
Ten Scariest Chemicals Used In Hydraulic Fracking
Chemicals Used In Fracking

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The EPA details things we need to do to save the water

The EPA provides information on how you can get involved including ways to protect human health and the environment by raising awareness about potential threats to your drinking water, local rivers, lakes, streams, wetlands, the fish and shellfish you eat, and aquatic ecosystems.
Adopt Your Watershed – This program challenges you to serve your community by taking part in activities to protect and restore your local watershed.
After the Storm – Weather – Weather emergencies such as flooding can introduce pollutants to your water supply. Learn how to protect your source of water and find out what to do in the event that your drinking water is compromised.
Emergency Preparedness – Identify some of the issues you may face preparing for, during and after an event that can directly threaten your health and the health of your family.
Good Samaritan – An Agency­ wide initiative to accelerate restoration of watersheds and fisheries threatened by abandoned hard rock mine runoff. The Good Samaritan initiative encourages voluntary cleanups by parties that are not responsible for the property in question.
Non-point Source Toolbox ­ Contains a variety of resources for the development of an effective outreach campaign to educate the public on non-point source pollution or storm water runoff.
Pollution Prevention – Water pollution and control measures are critical to improving water quality and lessening the need for costly wastewater and drinking water treatment. Find information on a variety of water pollution prevention and control measures.
Protect Your Health – Offers information on how to protect yourself from water­ related health risks such as microbes in tap water and in water bodies used for swimming, and contaminants in fish and shellfish.
Protecting Drinking Water ­ People who travel abroad know the familiar problem with unsafe drinking water. At home, we scarcely give it a thought. Usually, we are right. But the sources of our drinking water are constantly under siege from naturally occurring events and human activities that can pollute our sources of drinking water.
Volunteer Monitoring
Water Efficiency ­ Efficient use of water helps reduce the demands on our water supplies, as well as on both drinking water and wastewater infrastructure, as using less water means moving and treating less water.

Back To Top
 Managed by the Water Resources Discipline

Water Program

Conducts data collection and investigations that form the foundation for water­resources management and planning activities nationwide, through partnerships with over 1,000 State and local agencies.
National Streamflow Information Program (NSIP)
Implements the USGS plan to ensure reliable and consistent acquisition and delivery of streamflow information at key sites.
National Water­Quality Assessment Program (NAWQA)
Provides an understanding of water­quality of the Nation’s surface water and groundwater and how those conditions may vary locally, regionally, and nationally; whether conditions are getting better or worse over time; and how water quality is affected by natural features and human activities.
Toxic Substances Hydrology (Toxics) Program
Provides unbiased earth science information on the behavior of toxic substances in surface water and groundwater.
Groundwater Resources Program
Provides research and information for groundwater sustainability and ties to human and environmental needs.
Hydrologic Research and Development
Conducts basic and problem­oriented research into varied and complex hydrologic processes that are not well understood.
State Water Resources Research Institute Program
Supports water resources research, education, and information transfer at the 54 university­based State Water Resources Research Institutes, through the use of matching grants.
Hydrologic Networks and Analysis (HNA)
Includes the Federal core of the USGS water­quality networks, a variety of research and investigations, and a portion of USGS information storage, coordination, and dissemination efforts, including the National Water Information System.


Courtesy of USGS Water
Resources Programs


Water Information Coordination Program (WICP) Ensures the availability of cost effective water information required to make effective decisions for natural resources management and environmental protection.
Drinking­Water Research Topics
Conducts a wide range of monitoring, assessment, and research activities in collaboration with Federal, State, Tribal, and local agencies to help understand and protect the quality of drinking­ water resources.
National Stream Quality Accounting Network (NASQAN)
Focuses on the water quality of four of the Nation’s largest river systems—the Mississippi (including the Missouri and Ohio), the Columbia, the Colorado, and the Rio Grande.
Hydrologic Benchmark Network (HBN) Provides long­term measurements of streamflow and water quality in pristine areas, to serve as a baseline and control for distinguishing natural from artificial changes in other streams.
National Atmospheric Deposition Program/National Trends Network (NADP/NTN)
Monitors precipitation chemistry at about 200 sites nationwide.
National Water­Use Program Examines the withdrawal, use, and return flow of water on local, State, and national levels.
USGS Environmental Affairs Program Provides estimates of the Nation’s water use since 1950.


National Water Census
An initiative to provide a nationwide assessment of water availability and use. Information will be provided on components of the water budget, on water use, and ecological flow estimation. Regional Groundwater Studies will be expanded.

International Programs

International Water Activities Activities of the USGS International Water Resources Branch

STW™ General Water Resource Index

General Water Resource Index

The Impact Of Water On Index

EPA’s Study of Hydraulic Fracturing and Its Potential Impact on Drinking Water Resources

The Hydraulic Fracturing Water Cycle

Stage 1: Water Acquisition 1

  • Large volumes of water are withdrawn from ground water 2 and surface water 3 resources to be used in the HF process.
  • Potential Impacts on Drinking Water Resources
    • Change in the quantity of water available for drinking
    • Change in drinking water quality

    EPA Fracking

Stage 2: Chemical Mixing

  • Once delivered to the well site, the acquired water is combined with chemical
    additives 4 and proppant 5 to make the HF fluid.
  • Potential Impacts on Drinking Water Resources
    • Release to surface and ground water through on­site spills and/or leaks

    EPA Fracking

Stage 3: Well Injection

  • Pressurized HF fluid is injected into the well, creating cracks in the geological formation that allow oil or gas to escape through the well to be collected at the surface.
  • Potential Impacts on Drinking Water Resources
    • Release of HF fluids to ground water due to inadequate well construction or
    • Movement of HF fluids from the target formation to drinking water aquifers
      through local man­made or natural features (e.g., abandoned wells and existing faults)
    • Movement into drinking water aquifers of natural substances found
      underground, such as metals or radioactive materials, which are mobilized during HF activities

    EPA FrackingTop of Page

Stage 4: Flowback 6 and Produced Water 7 (HF Wastewaters)

  • When pressure in the well is released, HF fluid, formation water, and natural
    gas begin to flow back up the well. This combination of fluids, containing HF chemical additives and naturally occurring substances, must be stored on­site—typically in tanks or pits—before treatment, recycling, or disposal.
  • Potential Impacts on Drinking Water Resources
    • Release to surface or ground water through spills or leakage from on­site storage


    Stage 5: Wastewater Treatment and Waste Disposal

    • Wastewater is dealt with in one of several ways, including but not limited to:
      disposal by underground injection, treatment followed by disposal to surface water bodies, or recycling (with or without treatment) for use in future HF operations.
    • Potential Impacts on Drinking Water Resources
      • Contaminants reaching drinking water due to surface water discharge and inadequate treatment of wastewater

      • Byproducts formed at drinking water treatment facilities by reaction of HF contaminants with disinfectants


    1 [justify]Recently, some companies have begun recycling wastewater from previous HF activities, rather than acquiring water from ground or surface resources.
    2 Ground water is the supply of fresh water found beneath the Earth’s surface, usually in aquifers, which supply wells and springs. It provides a major source of drinking water.
    3 Surface water resources include any water naturally open to the atmosphere, such as rivers, lakes, reservoirs, ponds, streams, impoundments, seas, estuaries, etc. It provides a major source of drinking water.
    4 Chemical additives are used for a variety of purposes (see examples in Table 4 on page 29 of the HF Study Plan (PDF) (190 pp, 2.1 MB, About PDF)). A list of publicly known chemical additives found in HF fluids is provided in Appendix E, Table E1 of the HF Study Plan (PDF) (190 pp, 2.1 MB, About PDF).
    5 Proppant is a granular substance such as sand that is used to keep the underground cracks open once the HF fluid is withdrawn.
    6 After the HF fracturing procedure is completed and pressure is released, the direction of fluid flow reverses, and water and excess proppant flow up through the wellbore to the surface. The water that returns to the surface is commonly referred to as “flowback.”
    7 After the drilling and fracturing of the well are completed, water is produced along with the natural gas. Some of this water is returned fracturing fluid and some is natural formation water. These produced waters move back through the wellhead with the gas.

    Contact theHydraulic Fracturing Study Website Editor to ask a question, provide feedback, or report a problem.

Hydraulic fracturing

Last updated June 15th 2012 From Wikipedia, the free encyclopedia

The neutrality of this article is disputed. Please see the discussion on the talk page. Please do not remove this message until the dispute is resolved. (March 2012)


Hydraulic fracturing

Process type Mechanical
Industrial sector(s) Mining

Main technologies or sub­processesFluid pressureProduct(s)Natural gas
PetroleumInventorFloyd Farris; J.B. Clark (Stanolind Oil and Gas Corporation)Year of invention1947

Hydraulic fracturing is the propagation of fractures in a rock layer caused by the presence of a pressurized fluid. Some hydraulic fractures form naturally, as in the case of veins or dikes, and are a means by which gas and petroleum from source rocks may migrate to reservoir rocksInduced hydraulic fracturing or hydrofracking, commonly known as fracking, is a technique used to release petroleum, natural gas (including shale gastight gas and coal seam gas), or other substances for extraction.[a][1] This type of fracturing creates fractures from a wellbore drilled into reservoir rock formations.

The first use of hydraulic fracturing was in 1947, though the
fracking technique which made the shale gas extraction economical was first used in 1997 in the Barnett Shale in Texas.[1][2] [3] The energy from the injection of a highly­pressurized fracking fluid creates new channels in the rock which can increase the extraction rates and ultimate recovery of fossil fuels.

Proponents of fracking point to the vast amounts of formerly inaccessible hydrocarbons the process can extract. [4] Detractors point to potential environmental impacts, including contamination of ground water, risks to air quality, the migration of gases and hydraulic fracturing chemicals to the surface, surface contamination from spills and flowback and the health effects of these.[5] For these reasons hydraulic fracturing has come under scrutiny internationally, with some countries suspending or even banning it.

Schematic depiction of hydraulic fracturing for shale gas, showing potential environmental effects.

Main article: Fracture (geology)


Fracturing in rocks at depth is suppressed by the confi ning pressure, due to the load caused by the overlying rock strata. This is particularly so in the case of ‘tensile’ (Mode 1) fractures, which require the walls of the fracture to move apart, working against this confining pressure. Hydraulic fracturing occurs when the effective stress is reduced sufficiently by an increase in the pressure of fluids within the rock, such that the minimum
principal stress becomes tensile and exceeds the tensile strength of the material.[6][7] Fractures formed in this way will typically be oriented perpendicularly to the minimum principal stress and for this reason, induced hydraulic fractures in wellbores are sometimes used to determine stress orientations.[8] In natural examples, such as dikes or vein­filled fractures, their orientations can be used to infer past stress states.[9]


Most vein systems are a result of repeated hydraulic fracturing during periods of relatively high pore fluid pressure. This is particularly clear in the case of ‘crack­seal’ veins, where the vein material can be seen to have been added in a series of discrete fracturing events, with extra vein material deposited on each occasion.[10] One mechanism to explain such examples of long­lasting repeated fracturing is the effects of seismic activity, in which the stress levels rise and fall episodically and large volumes of fluid may be expelled from fluid­filled fractures during earthquakes. This process is referred to as ‘seismic pumping’.[11]


High­level minor intrusions such as dikes propagate through the crust in the form of fluid­filled cracks, although in this case the fluid is magma. In sedimentary rocks with a significant water content the fluid at the propagating fracture tip will be steam.[12]


Fracturing as a method to stimulate shallow, hard rock oil wells dates back to the 1860s. It was applied by oil industries in Pennsylvania, New York, Kentucky, and West Virginia by using liquid and later also solidified nitroglycerin. Later the same method was applied to water and gas wells. The idea to use acid as a nonexplosive fluid for a well stimulation was introduced in the 1930s. Due to acid etching, created fractures would not close completely and therefore enhanced productivity. The
same phenomenon was discovered with water injection and squeeze cementing operations.[13]

The relationship between well performance and treatment pressures was studied by Floyd Farris of Stanolind Oil and Gas Corporation. This study became a basis of the first hydraulic fracturing experiment, which was conducted in 1947 at the Hugoton gas field in Grant County of southwestern Kansas by Stanolind.[13][1] For the well treatment 1,000 US gallons (3,800 l; 830 imp gal) of gelled gasoline and sand from the Arkansas River was injected into the gas producing limestone formation at 2,400 feet (730 m). The experiment was not very successful as deliverability of the well did not change appreciably. The process was further described by J.B. Clark of Stanolind in his paper published in 1948. A patent on this process was issued in 1949 and an exclusive license was granted to the Halliburton Oil Well Cementing Company. On March 17, 1949, Halliburton performed the first two commercial hydraulic fracturing treatments in Stephens County, Oklahoma, and Archer County, Texas.[13] Since then, hydraulic fracturing has been used to stimulate approximately a million oil and gas wells.[14]

In the Soviet Union, the first hydraulic proppant fracturing was carried out in 1952. In Western Europe, in 1977–1985 hydraulic fracturing was conducted at Rotliegend and Carboniferous gas­bearing sandstones in Germany, Netherlands onshore and offshore gas fields, and the United Kingdoms sector of the North Sea. Other countries in Europe and Northern Africa included Norway, the Soviet Union, Poland, Czechoslovakia,
Yugoslavia, Hungary, Austria, France, Italy, Bulgaria, Romania, Turkey, Tunisia, and Algeria. [15]

Due to shale’s high porosity and low permeability, technology research, development and demonstration were necessary before hydraulic fracturing could be commercially applied to shale gas deposits. In the 1970s the federal government initiated both the Eastern Gas Shales Project, a set of dozens of public­private hydro­fracturing pilot demonstration projects, and the Gas Research Institute, a gas industry research consortium that received approval for research and funding from the Federal Energy Regulatory Commission.[16] In 1977, the Department of Energy pioneered massive hydraulic fracturing in tight sandstone formations. In 1997, based on earlier techniques used by Union Pacific Resources (now part of Anadarko Petroleum Corporation), Mitchell Energy (now part of Devon Energy) developed the hydraulic fracturing technique known as ‘slickwater fracturing’ that made the shale gas extraction economical.[17][2] [3]

In 2011, France became the first nation to ban hydraulic fracturing.[18][19]

Induced hydraulic fracturing


The technique of hydraulic fracturing is used to increase or restore the rate at which fluids, such as petroleum, water, or natural gas can be produced from subterranean natural reservoirs. Reservoirs are typically porous sandstoneslimestones or dolomite rocks, but also include
’unconventional reservoirs’ such as shale rock or coal beds. Hydraulic fracturing enables the production of natural gas and oil from rock formations deep below the earth’s surface (generally 5,000–20,000 feet (1,500–6,100 m)). At such depth, there may not be sufficient permeability or reservoir pressure to allow natural gas and oil to flow from the rock into the wellbore at economic rates. Thus, creating conductive fractures in the rock is essential to extract gas from shale reservoirs because of the extremely low natural permeability of shale, which is measured in the microdarcy to nanodarcy range.[20] Fractures provide a conductive path connecting a larger volume of the reservoir to the well, thereby increasing the volume from which natural gas and liquids can be recovered from the targeted formation. So­called ‘super fracking’, which creates cracks deeper in the rock formation to release more oil and gas, will allow companies to frack more efficiently.[ 21] The yield for a typical shale gas well generally falls off sharply after the first year or two.[22] 

While the main industrial use of hydraulic fracturing is in stimulating production from oil and gas wells,[23][24][25] hydraulic fracturing is also applied to:

  • Stimulating groundwater wells;[26]
  • Preconditioning rock for caving or inducing rock to cave in mining;[27]
  • As a means of enhancing waste remediation processes, usually hydrocarbon waste or spills;[28]


A hydraulic fracture is formed by pumping the fracturing fluid into the wellbore at a rate sufficient to increase pressure downhole to exceed that of the fracture gradient (pressure gradient) of the rock.[33] The fracture gradient is defined as the pressure increase per unit of the depth due to its density and it is usually measured in pounds per square inch per foot or bars per meter. The rock cracks and the fracture fluid continues farther into the rock, extending the crack still farther, and so on. Operators typically try to maintain “fracture width”, or slow its decline, following treatment by introducing into the injected fluid a proppant—a material such as grains of sand, ceramic, or other particulates, that prevent the fractures from closing when the injection is stopped and the pressure of the fluid is reduced. Consideration of proppant strengths and prevention of proppant failure becomes more important at deeper depths where pressure and stresses on fractures are higher. The propped fracture is permeable enough to allow the flow of formation fluids to the well. Formation fluids include gas, oil, salt water, fresh water and fluids introduced to the formation during completion of the well during fracturing.[33]

During the process fracturing fluid leakoff, loss of fracturing fluid from the fracture channel into the surrounding permeable rock, occurs. If not controlled properly, it can exceed 70% of the injected volume. This may result formation matrix damage, adverse formation fluid interactions, or altered fracture geometry and therefore decrease of production efficiency.[34]

The location of one or more fractures along the length of the borehole is strictly controlled by various different methods which create or seal­off holes in the side of the wellbore. Typically, hydraulic fracturing is performed in cased wellbores and the zones to be fractured are accessed by perforating the casing at those locations.[35]

Hydraulic­fracturing equipment used in oil and natural gas fields usually consists of a slurry blender, one or more high­pressure, high­volume fracturing pumps (typically powerful triplex, or quintiplex pumps) and a monitoring unit. Associated equipment includes fracturing tanks, one or more units for storage and handling of proppant, high­pressure treating iron, a chemical additive unit (used to accurately monitor chemical addition), low­pressure flexible hoses, and many gauges and meters for flow rate, fluid density, and treating pressure.[36] Fracturing equipment operates over a range of pressures and injection rates, and can reach up to 100 megapascals (15,000 psi) and 265 litres per second (9.4 cu ft/s) (100 barrels per minute).[37]

Well types

A distinction can be made between conventional or low­volume hydraulic fracturing used to stimulate high­permeability reservoirs to frac a single well, and unconventional or high­volume hydraulic fracturing, used in the completion of tight gas and shale gas wells as unconventional wells are deeper and require higher pressures than conventional vertical wells.[38] In addition to hydraulic fracturing of vertical wells, it is also performed in horizontal wells. When done in already highly­permeable reservoirs such as sandstone­based wells, the technique is known as “well stimulation”.[25]

Horizontal drilling involves wellbores where the terminal drillhole is completed as a ‘lateral’ that extends parallel with the rock layer containing the substance to be extracted. For example, laterals extend 1,500 to 5,000 feet (460 to 1,500 m) in the Barnett Shale basin in Texas, and up to 10,000 feet (3,000 m) in the Bakken formation in North Dakota. In contrast, a vertical well only accesses the thickness of the rock layer, typically 50–300 feet (15–91 m). Horizontal drilling also reduces surface disruptions as fewer wells are required to access a given volume of reservoir rock. Drilling usually induces damage to the pore space at the wellbore wall, reducing the permeability at and near the wellbore.
This reduces flow into the borehole from the surrounding rock formation, and partially seals off the borehole from the surrounding rock. Hydraulic fracturing can be used to restore permeability.[39]

The following is courtousy of Michael Kelley | Mar. 16, 2012, 1:35 PM


Methanol appeared most often in hydraulic fracturing products (in terms of the number of compounds containing the chemical).
Found in antifreeze, paint solvent and vehicle fuel.
Vapors can cause eye irritation, headache and fatigue, and in high enough doses can be fatal. Swallowing may cause eye damage or death.

BTEX compounds

BTEX compoundsFlcikr/arimoore

The BTEX compounds – benzene, toluene, xylene, and ethylbenzene – are listed as hazardous air pollutants in the Clean Air Act and contaminents in the Safe Drinking Water Act.
Benzene, commonly found in gasoline, is also a known human carcinogen. Long time exposure can cause cancer, bone marrow failure, or leukemia. Short term effects include dizziness, weakness, headache, breathlessness, chest constriction, nausea, and vomiting. Toluene, ethylbenzene, and xylenes have harmful effects on the central nervous system. The hydraulic fracturing companies injected 11.4 million gallons of products containing at least one BTEX chemical between 2005 and 2009.

Diesel fuel

Diesel fuelA carcinogen listed as a hazardous air pollutant under the Clean Air Act and a contaminant in the Safe Drinking Water Act.
In its 2004 report, the EPA stated that the “use of diesel fuel in fracturing fluids poses the greatest threat” to underground sources of drinking water.
Hydraulic fracturing companies injected more than 30 million gallons of diesel fuel or hydraulic fracturing fluids containing diesel fuel in wells in 19 states.
Diesel fuel contains toxic constituents, including BTEX compounds. Contact with skin may cause redness, itching, burning, severe skin damage and cancer. (Kerosene is also used. Found in jet and rocket fuel, the vapor can cause irritation of the eyes and nose, and ingestion can be fatal. Chronic exposure may cause drowsiness, convulsions, coma or death.)


A carcinogen found in paint, building construction materials and roofing joints.
It is listed as a hazardous air pollutant in the Clean Air Act and a contaminant in the Safe Drinking Water Act.
Lead is particularly harmful to children’s neurological development. It also can cause reproductive problems, high blood pressure, and nerve disorders in adults.
One of the hydraulic fracturing companies used 780 gallons of a product containing lead between 2005 and 2009.

Hydrogen fluoride

Hydrogen fluorideFlickr/Molly Des Jardin
Found in rust removers, aluminum brighteners and heavy duty cleaners.
Listed as a hazardous air pollutant in the Clean Air Act.
Fumes are highly irritating, corrosive, and poisonous. Repeated ingestion over time can lead to hardening of the bones, and contact with liquid can produce severe burns. A lethal dose is 1.5 grams.
Absorption of substantial amounts of hydrogen fluoride by any route may be fatal.
One of the hydraulic fracturing companies used 67,222 gallons of two products containing hydrogen fluoride in 2008 and 2009.


A carcinogen found in mothballs.
Listed as a hazardous air pollutant in the Clean Air Act.
Inhalation can cause respiratory tract irritation, nausea, vomiting, abdominal pain, fever or death.

Sulfuric acid

Sulfuric acidFlickr/yetanotherdave
A carcinogen found in lead­acid batteries for cars.
Corrosive to all body tissues. Inhalation may cause serious lung damage and contact with eyes can lead to a total loss of vision. The lethal dose is between 1 teaspoonful and one­half ounce.

Crystalline silica

Crystalline silicaSource: ProPublica
A carcinogen found in concrete, brick mortar and construction sands.
Dust is harmful if inhaled repeatedly over a long period of time and can lead to silicosis or cancer.


A carcinogen found in embalming agents for human or animal remains.
Ingestion of even one ounce of liquid can cause death. Exposure over a long period of time can cause lung damage and reproductive problems in women.

Unknown chemicals

Unknown chemicalsFlickr/SoulRider.222
“Many of the hydraulic fracturing fluids contain chemical components that are listed as ‘proprietary’ or ‘trade secret.’ The companies used 94 million gallons of 279 products that contained at least one chemical or component that the manufacturers deemed proprietary or a trade secret. In many instances, the oil and gas
injecting fluids containing chemicals that they themselves cannot

Site setup

Consistent with the Energy Policy Act of 2005, the U.S. Environmental Protection Agency (EPA) published a final rule in 2006 that exempts stormwater discharges of sediment from construction activities at oil and gas exploration and production operations from the requirement to obtain a National Pollutant Discharge Elimination System (NPDES) ‡ stormwater permit as long as stormwater runoff to waters under the jurisdiction of the CWA are not contaminated with oil, grease, or hazardous substances. With this exemption, EPA specifically encouraged the oil and natural gas industry to develop and implement Best Management Practices (BMPs) to minimize the discharges of pollutants, including sediment, in stormwater both during and after construction activities. In an effort to meet the expectations of EPA under this rulemaking ­­ to incorporate successful voluntary stormwater management practices into day­to­day operations – the American Petroleum Institute (API) and the Independent Petroleum Association of America (IPAA), industry associations, and company
unable to identify these ‘proprietary’ chemicals,suggesting that the companies are
service companies were
representatives (referred to as the Stormwater Technical Workgroup (SWTW)), built upon the 2004 guidance document entitled Reasonable and Prudent Practices for Stabilization (RAPPS) of Oil and Natural Gas Construction Sites. Through field validation of the RAPPS, gap identification, and concerted program improvements, the SWTW developed a voluntary guidance document that, if implemented correctly, will serve as a readily applicable tool for operators to use in order to efficiently and effectively maximize control of stormwater discharges at oil and natural gas exploration and production activities throughout the contiguous U.S.Read more at


Historical perspective

Hydraulic fracturing is not new. The first commercial application of hydraulic fracturing as a well treatment technology designed to stimulate the production of oil or gas likely occurred in either the Hugoton field of Kansas in 1946 or near Duncan Oklahoma in 1949. In the ensuing sixty plus years, the use of hydraulic fracturing has developed into a routine technology that is frequently used in the completion of gas wells, particularly those involved in what’s called “unconventional production,” such as production from so­called “tight shale” reservoirs. The process has been used on over 1 million producing wells. As the technology continues to develop and improve, operators now fracture as many as 35,000 wells of all types (vertical and horizontal, oil and
natural gas) each year.

Hydraulic fracturing has had an enormous impact on America’s energy history, particularly in recent times.
The ability to produce more oil and natural gas from older wells and to develop new production once thought impossible has made the process valuable for US domestic energy production.
Without hydraulic fracturing, as much as 80 percent of unconventional production from such formations as gas shales would be, on a practical basis, impossible. 

This technique uses a specially blended liquid which is pumped into a well under extreme pressure causing cracks in rock formations underground. These cracks in the rock then allow oil and natural gas to flow, increasing resource production.

Hydraulic Fracturing: The Process

What Is Hydraulic Fracturing?

Contrary to many media reports, hydraulic fracturing is not a “drilling process.” Hydraulic fracturing is used after the drilled hole is completed. Put simply, hydraulic fracturing is the use of fluid and material to create or restore small fractures in a formation in order to stimulate production from new and existing oil and gas wells. This creates paths that increase the rate at which fluids can be produced from the reservoir formations, in some cases by many hundreds of percent.
The process includes steps to protect water supplies. To ensure that neither the fluid that will eventually be pumped through the well, nor the oil or gas that will eventually be collected, enters the water supply, steel surface or intermediate casings are inserted into the well to depths of between 1,000 and 4,000 feet. The space between these casing “strings” and the drilled hole (wellbore), called the annulus, is filled with cement. Once the cement has set, then the drilling continues from the bottom of the surface or intermediate cemented steel casing to the next depth. This process is repeated, using smaller steel casing each time, until the oil and gas­bearing reservoir is reached (generally 6,000 to 10,000 ft). A more detailed look at casing and its role in groundwater protection is available HERE.
With these and other precautions taken, high volumes of fracturing fluids are pumped deep into the well at pressures sufficient to create or restore the small fractures in the reservoir rock needed to make production possible.
What’s in Hydraulic Fracturing Fluid?
Water and sand make up 98 to 99.5 percent of the fluid used in hydraulic fracturing. In addition, chemical additives are used. The exact formulation varies depending on the well. To view a chart of the chemicals most commonly used in hydraulic fracturing and for a more detailed discussion of this question, click HERE.
Why is Hydraulic Fracturing Used?
Experts believe 60 to 80 percent of all wells drilled in the United States in the next ten years will require hydraulic fracturing to remain operating. Fracturing allows for extended production in older oil and natural gas fields. It also allows for the recovery of oil and natural gas from formations that geologists once believed were impossible to produce, such as tight shale formations in the areas shown on the map below. Hydraulic fracturing is also used to extend the life of older wells in mature oil and gas fields.

How is Hydraulic Fracturing Done?*

The placement of hydraulic fracturing treatments underground is sequenced to meet the particular needs of the formation. The sequence noted below from a Marcellus Shale in Pennsylvania is just one example. Each oil and gas zone is different and requires a hydraulic fracturing design tailored to the particular conditions of the formation. Therefore, while the process remains essentially the same, the sequence may change depending upon unique local conditions. It is important to note that not all of the additives are used in every hydraulically fractured well; the exact “blend” and proportions of additives will vary based on the site­specific depth, thickness and other characteristics of the target formation.

1. An acid stage, consisting of several thousand gallons of water mixed with a dilute acid such as hydrochloric or muriatic acid: This serves to clear cement debris in the wellbore and provide an open conduit for other frac fluids by dissolving carbonate minerals and opening fractures near the wellbore.
2. A pad stage, consisting of approximately 100,000 gallons of slickwater without proppant material: The slickwater pad stage fills the wellbore with the slickwater solution (described below), opens the formation and helps to facilitate the flow and placement of proppant material.
3. A prop sequence stage, which may consist of several substages of water combined with proppant material (consisting of a fine mesh sand or ceramic material, intended to keep open, or “prop” the fractures created and/or enhanced during the fracturing operation after the pressure is reduced): This stage may collectively use several hundred thousand gallons of water. Proppant material may vary from a finer particle size to a coarser particle size
throughout this sequence.
4. A flushing stage, consisting of a volume of fresh water sufficient to flush the excess proppant from the wellbore.

Other additives commonly used in the fracturing solution employed in Marcellus wells include:

• A dilute acid solution, as described in the first stage, used during the initial fracturing sequence. This cleans out cement and debris around the perforations to facilitate the subsequent slickwater solutions employed in fracturing the formation.
• A biocide or disinfectant, used to prevent the growth of bacteria in the well that may interfere with the fracturingoperation: Biocides typically consist of bromine­based solutions or glutaraldehyde.
• A scale inhibitor, such as ethylene glycol, used to control the precipitation of certain carbonate and sulfate minerals
• Iron control/stabilizing agents such as citric acid or hydrochloric acid, used to inhibit precipitation of iron compounds by keeping them in a soluble form
• Friction reducing agents, also described above, such as potassium chloride or polyacrylamide­based compounds, used to reduce tubular friction and subsequently reduce the pressure needed to pump fluid into the wellbore: The additives may reduce tubular friction by 50 to 60%. These friction­reducing compounds represent the “slickwater” component of the fracing solution.
• Corrosion inhibitors, such as N,n­dimethyl formamide, and oxygen scavengers, such as ammonium bisulfite, are used to prevent degradation of the steel well casing.
• Gelling agents, such as guar gum, may be used in small amounts to thicken the water­based solution to help transport the proppant material.
• Occasionally, a cross­linking agent will be used to enhance the characteristics and ability of the gelling agent to transport the proppant material. These compounds may contain boric acid or ethylene glycol. When cross­linking additives are added, a breaker solution is commonly added later in the frac stage to cause the enhanced gelling agent to break down into a simpler fluid so it can be readily removed from the wellbore without carrying back the sand/ proppant material.

Fractures: Their orientation and length

Certain predictable characteristics or physical properties regarding the path of least resistance have been recognized since hydraulic fracturing was first conducted in the oilfield in 1947. These properties are discussed below:
Fracture orientation
Hydraulic fractures are formed in the direction perpendicular to the least stress. Based on experience, horizontal fractures will occur at depths less than approximately 2000 ft. because the Earth’s overburden at these depths provides the least principal stress. If pressure is applied to the center of a formation under these relatively shallow conditions, the fracture is most likely to occur in the horizontal plane, because it will be easier to part the rock in this direction than in any other. In general, therefore, these fractures are parallel to the bedding plane of the formation.
As depth increases beyond approximately 2000 ft., overburden stress increases by approximately 1 psi/ft., making the overburden stress the dominant stress This means the horizontal confining stress is now the least principal stress. Since hydraulically induced fractures are formed in the direction perpendicular to the least stress, the resulting fracture at depths greater than approximately 2000 ft. will be oriented in the vertical direction.
In the case where a fracture might cross over a boundary where the principal stress direction changes, the fracture would attempt to reorient itself perpendicular to the direction of least stress. Therefore, if a fracture propagated from deeper to shallower formations it would reorient itself from a vertical to a horizontal pathway and spread sideways along the bedding planes of the rock strata.
Fracture length/ height
The extent that a created fracture will propagate is controlled by the upper confining zone or formation, and the volume, rate, and pressure of the fluid that is pumped. The confining zone will limit the vertical growth of a fracture because it either possesses sufficient strength or elasticity to contain the pressure of the injected fluids or an insufficient volume of fluid has been pumped.. This is important because the greater the distance between the fractured formation and the USDW, the more likely it will be that multiple formations possessing the qualities necessary to impede the fracture will occur. However, while it should be noted that the length of a fracture can also be influenced by natural fractures or faults as shown in a study that included microseismic analysis ‡ of fracture jobs conducted on three wells in Texas, natural attenuation of the fracture will occur over relatively short distances due to the limited volume of fluid being pumped and dispersion of the pumping pressure regardless of intersecting migratory pathways.

The following text and graphs are excerpts from an article written by Kevin Fisher of Pinnacle, a Halliburton Company for the July 2010 edition of the American Oil and Gas Reporter.

“The concerns around groundwater contamination raised by Congress are primarily centered on one fundamental question: Are the created fractures contained within the target formation so that they do not contact underground sources of drinking water? In response to that key concern, this article presents the first look at actual
field data based on direct measurements acquired while fracture mapping more than 15,000 frac jobs during the past decade.

Extensive mapping of hydraulic fracture geometry has been performed in unconventional North American shale reservoirs since 2001. The microseismic and tiltmeter technologies used to monitor the treatments are well established, and are also widely used for nonoil field (sic) applications such as earthquake monitoring, volcano monitoring, civil engineering applications, carbon capture and waste disposal. Figures 1 and 2 are plots of data collected on thousands of hydraulic fracturing treatments in the Barnett Shale in the Fort Worth Basin in Texas and in the Marcellus Shale in the Appalachian Basin.

More fracs have been mapped in the Barnett than any other reservoir. The graph illustrates the fracture top and bottom for all mapped treatments performed in the Barnett since 2001. The depths are in true vertical depth. Perforation depths are illustrated by the red­colored band for each stage, with the mapped fracture tops and bottoms illustrated by colored curves corresponding to the counties where they took place.

The deepest water wells in each of the counties where Barnett Shale fracs have been mapped, according to United States Geological Survey ( ‡), are illustrated by the dark blue shaded bars at the top of Figure 1. As can be seen, the largest directly measured upward growth of all of these mapped fractures still places the fracture tops several thousands of feet below the deepest known aquifer level in each county.


The Marcellus data show a similarly large distance between the top of the tallest frac and the location of the deepest drinking water aquifers as reported in USGS data (dark blue shaded bars at the top of Figure 2). Because it is a newer play with fewer mapped frac stages at this point and encompasses several states, the data set is not as comprehensive as that from the Barnett. However, it is no less compelling in providing evidence of a very good physical separation between hydraulic fracture tops and water aquifers.

Almost 400 separate frac stages are shown, color coded by state. As can be seen, the fractures do grow upward quite a bit taller than in the Barnett, but the shallowest fracture tops are still ±4,500 feet, almost one mile below the surface and thousands of feet below the aquifers in those counties.

The results from our extensive fracture mapping database show that hydraulic fractures are better confined vertically (and are also longer and narrower) than conventional wisdom or models predict. Even in areas with the largest
measured vertical fracture growth, such as the Marcellus, the tops of the hydraulic fractures are still thousands of feet below the deepest aquifers suitable for drinking water. The data from these two shale reservoirs clearly show the huge distances separating the fracs from the nearest aquifers at their closest points of approach, conclusively demonstrating that hydraulic fractures are not growing into groundwater supplies, and therefore, cannot contaminate them.”

* Pennsylvania Department of Environmental Protection “Hydraulic Fracturing Overview.” 07/20/2010.
‡ (4/11/2011).

Fracturing Fluid Management

Fluid Storage – “Pits” 

From the time the first oil and gas wells were drilled, “pits” have been used to hold drilling fluids and wastes. Pits can be excavated holes in the ground, or they can be above ground containment systems such as steel tanks. Pits are used for storage of produced water, for emergency overflow, temporary storage of oil, burn off of waste oil, and for temporary storage of the fluids used to complete and treat the well.
The containment of fluids within a pit is the most critical element in the prevention of contamination of shallow ground water. The failure of a tank, pit liner, or the line carrying fluid (“flowline”) can result in a release of contaminated materials directly into surface water and shallow ground water. Environmental clean­up of these accidentally released materials can be a costly and time consuming process. Therefore, prevention of releases is vitally important.
For pits constructed from ground excavation, pit lining may be necessary to prevent infiltration of fluids into the subsurface of the ground, depending upon the fluids being placed in the pit, the duration of the storage and the soil conditions. Typically, pit liners are constructed of compacted clay or synthetic materials like polyethylene or treated fabric that can be joined using special equipment.
Read more at FracFocus

history for this page.” Last
updated June 17th 2012

From Wikipedia, the free encyclopedia

Hydraulic fracturing has become a contentious environmental and health issue with France banning the practice and a moratorium in place in New South Wales (Australia), Karoo basin (South Africa), Quebec (Canada), and some of the states of the US.

Hydraulic fracturing by country click


Up until the mid 2000s, hydraulic fracturing was generally limited to conventional oil and gas wells in the Cooper Basin and limited to one, two or sometimes zero ongoing fracturing operations. The vast majority of coal seam gas wells have not been hydraulically fractured as the wells presently being drilled are in coal seams that have good natural permeability.[citation needed] The NSW Government has banned BTEX chemicals as additives.[1]


A number of protests occurred in Bulgaria after the government’s decision to grant an approval for Chevron Corporation to research the possibilities of shale gas extraction in the country’s northeast in 2011. After a nationwide protest in January 2012, the government decided to ban the hydraulic fracturing technology.[2]


Fracking has been in use in Canada at an industrial level since the 1990s. Concerns about fracking began in late July 2011, when the Government of British Columbia gave Talisman Energy a long­term water licence to draw water from the BC Hydro­owned Williston Lake reservoir, for a twenty year term. Fracking has also received criticism in New Brunswick and Nova Scotia, and the Nova Scotia government is currently reviewing the practice, with recommendations expected in March 2012. The practice has been temporarily suspended, in Quebec, pending an environmental review. The Canadian Centre for Policy Alternatives has also expressed concern.[3]


China completed its first horizontal shale gas well in 2011. A global shale gas study by the US Energy Information Administration said China’s technically recoverable shale gas reserves were almost 50% higher than those of the number two nation, the United States.[4]


In 2012, the first research has begun in North Jutland where 80% of underground gas has been commissioned for extraction by Total E&P Denmark B.V., a subsidy of the multinational company Total S.A.. The remaining 20% have been commissioned to the national trust foundation Nordsøfonden. The research is due for completion in 2016.[5]

Meanwhile, a critical view is reflected in national media,[6] and national campaigns against shale gas have started.[7]


Hydraulic fracturing was banned in France in 2011 after public pressure.[8][9]


In Northern Ireland, Tamboran Resources has tested sites in County Fermanagh which they claim could supply gas to Northern Ireland for years to come.[10] Tamboran Resources also has a license for gas exploration and plan to proceed hydraulic fracturing in the Lough Allen basin area of County Leitrim. The CEO of Tamboran Resources has declared a “zero­chemical hydraulic fracturing” pledge. The Protest group “No Fracking Ireland” has been set up by locals of counties Leitrim, Roscommon and Sligo and petitions against hydraulic fracturing are still ongoing.[11]

New Zealand

Main article: Hydraulic fracturing in New Zealand

In New Zealand, hydraulic fracturing is part of petroleum exploration and extraction on a small scale mainly in Taranaki and concerns have been raised by environmentalists. [12][13] On 28 March 2012, Dr Jan Wright, NZ Parliamentary Commissioner for the Environment announced her office would lead an independent investigation into the practice of hydraulic fracturing or fracking.[14]


Poland is busy aggressively developing its shale gas reserves, thought to be the largest in Europe, though the latest estimate is significantly lower than that previously provided by the U.S. Department of Energy.[15][16] A Polish Geological Institute study published in March 2012 concluded that, while fracking at one site had produced toxic waste, the latter was reused and did not harm the environment,[17] though critics said the study was carried out at the start of exploration in Poland and does not reflect dangers from a long­term activity.[18] Large­scale fracking in Poland would relieve some of the EU’s dependency on Russian gas,[19][20] but the East European state is densely populated and has a large agricultural sector, meaning the massive amounts of water required for fracking have raised additional concerns.[21]

South Africa

There is currently a moratorium on hydraulic fracturing in South Africa’s Karoo region despite the interest of several energy companies.[21][22]

United Kingdom

Main article: Hydra ulic fracturing in the United Kingdom

Fracking is carried out in the United Kingdom by Cuadrilla Resources, though other companies have exploration licenses. Though not officially suspended, the process was unofficially suspended for nearly a year in the UK from June 2011 over safety concerns, but an expert report in April 2012 concluded the practice was safe, clearing the way for its resumption.[23] Protest groups have emerged since April 2012, with the major nationwide group being Frack Off.[24]

United States

Main article: Hydraulic fracturing in the United States

Hydraulic fracturing is most commonly used in the United States to extract natural gas from shale formations, with advances in the technology meaning shale gas has increased to 30 percent of US gas production over the past 15 years.[25] Because of the impermeability of shale, the gas industry of the 1970s could not economically extract shale gas.[26] Following direct investments in R&D and demonstration in massive hydraulic fracturing, directional drilling, and microseismic 3­dimensional imaging by the Department of Energy and other federal agencies,[27][28] Mitchell Energy applied an innovative technique called slick­water fracturing to achieve the first economical well for the extraction of shale gas in 1998.[29]

Hydraulic fracturing for the purpose of oil, natural gas, and
geothermal production was exempted under the Safe Drinking Water Act.[30] This was a result of the signage of the Energy Policy Act of 2005, also known as the Halliburton Loophole because of former Halliburton CEO Vice President Dick Cheney’s involvement in the passing of this exemption. The result of a 2004 EPA study on coalbed hydraulic fracturing was used to justify the passing of the exemption; however EPA whistleblower Weston Wilson and the Oil and Gas Accountability Project found that critical information was removed from the final report.[31] Halliburton is the leading provider of fracking services in the United States.[32]

Opposers of hydraulic fracturing in the US have focused on this 2005 exemption; however the more primary risk to drinking water is the handling and treatment of wastewater produced by hydraulic fracturing. The EPA and the state authorities do have power “to regulate discharge of produced waters from hydraulic operations” (EPA, 2011) under the Clean Water Act, which is regulated by the National Pollutant Discharge Elimination System (NPDES) permit program.[33][34][35] Although this waste is regulated, oil and gas exploration and production (E&P) wastes are exempt from Federal Hazardous Waste Regulations under Subtitle C of the Resource Conservation and Recovery Act (RCRA) despite the fact that wastewater from hydraulic fracturing contains toxins such as total dissolved solids (TDS), metals, and radionuclides.[36][37] About 750 chemicals have been listed as additives for hydraulic fracturing in a report to the US Congress in 2011. However, well­specific information can be found on Companies are still not required to provide the names of chemicals in “proprietary” formulas, so the chemical lists are incomplete.[38][39]


  1.  The Sofia Echo, 17 January 2012
  2. ^ ” Northern B.C. fracking licence concerns critics”. July 29, 2011.  
  3. ^ Jonathan Watts (21 April 2011). “China takes step towards tapping shale gas potential with first well”.
  4. ^ Total website on shale gas operations in Denmark
  5. ^ “D enmark attempts controversial gas” July 23, 2011. htt p://­satser­paa­kontroversiel­gas/. Retrieved 2011­07­30. 
  6. ^ Protest campaign: “Shale gas no thanks” ­
  7. ^ Tara Patel (31 March 2011). “The French Public Says No to ‘Le Fracking‘”Businessweek Retrieved 22 February 2012.
  8. ^ Tara Patel (4 October 2011). “France to Keep Fracking Ban to Protect Environment, Sarkozy Says”Businessweek­10­04/fra nce­to­keep­fracking­ban­to­protect­environment­sarkozy­says.html. Retrieved 22 February 2012.
  9. ^ “Fermanagh shale gas ‘could supply Northern Ireland'”. BBC. February 1, 2012.  
  10. ^ . September 1, 2011.
  11. ^ Maetzig, Rob (July 27, 2011). “Anti­frackers ‘need to get real'”. Taranaki Daily News.
  12. ^ Maetzig, Rob (August 3, 2011). “Concern as gas drilling intensifies”. Taranaki Daily News.
  13. ^­releases/pce­to­investigate­fracking/
  14. ^ Tim Webb (24 May 2011). “Shale gas extraction given clean bill of health by MPs”The Sunday Times Retrieved 4 March 2012. 
  15. ^ Marek Strzelecki (2 March 2012). “Poland Says 22 Shale Gas Wells Under Way or Planned in 2012”. Bloomberg.
  16. ^ “Polish report: shale gas procedure produces toxic refuse but does not harm environment”. Associated Press. 2 March 2012.
  17. ^ Monika Scislowska (2 March 2012). “Polish Report: Shale Gas Extraction Not Harmful”. Associated Press.­report­shale­gas­extraction­
    . Retrieved 4 March 2012.
  18. ^ Michael Kahn; Braden Reddall; Gabriela Baczynska (9 February 2012). “Insight: Poland’s shale gas play takes on Russian power”. Reuters. http://www­poland­shalegas­idUSTRE8180P M20120209. Retrieved 4 March 2012.
  19. ^ Mary Dejevksy (27 September 2011). “Poland’s Shale Gas dilemma for Europe”The Independenthttp://www is­and­features/polands­shale­gas­dilemma­for­europe­2361570.html. Retrieved 4 March 2012.
  20. a b Ian Urbina (30 December 2011). “Hunt for Gas Hits Fragile Soil, and South Africans Fear Risks”The New York Timeshttp://www­african­farmers­see­threat­fr om­fracking.html. Retrieved 23 February 2012. “Covering much of the roughly 800 miles between Johannesburg and Cape Town, this arid expanse—its name [Karoo] means “thirsty land”—sees less rain in some parts than the Mojave Desert.”
  21. ^ “S.Africa imposes “fracking” moratorium in Karoo”. April 21, 2011. http://www­safrica­fracking­idUSTRE73K4562 0110421
  22. ^ Fiona Harvey (17 April 2012). “Gas ‘fracking’ gets green light”The Guardianhttp://www­fracking­gets­green­light. Retrieved 17 April 2012.
  23. ^ Melley, James (28 September 2011). “New groups protest at shale gas”. BBC News. /news/science­environment­15021328. Retrieved 26 February 2012. 
  24. ^ Terrence Dopp (13 February 2012). “New Jersey Senate Committee Again Passes Gas­Fracking Ban”Businessweekhttp://www­02­13/new­jers ey­senate­committee­again­passes­gas­fracking­ban.html. Retrieved 22 February 2012.
  25. ^ Sherie Mershon; Tim Palucka (October 2010). ” A Century of Innovation: From the U.S. Bureau of Mines to the National Energy Technology Laboratory”. National Energy Technology Laboratory. h ttp://www­A_Century_of_Innovation.pdf. Retrieved 22 February 2012. 
  26. ^ Michael Shellenberger and Ted Nordhaus (16 December 2011). “A boom in shale gas? Credit the feds”The Washington Posthttp://www­boom­in­shal e­gas­credit­the­feds/2011/12/07/gIQAecFIzO_story.html. Retrieved 22 February 2012. 
  27. ^ “N ew Investigation Finds Decades of Government Funding Behind Shale Revolution”Breakthrough blog. The Breakthrough Institute. 20 December 2011. htt p:// Retrieved 22 February 2012. 
  28. ^ “I nterview with Dan Steward, Former Mitchell Energy Vice President”Breakthrough blog. The Breakthrough Institute. 20 December 2011. htt p:// Retrieved 22 February 2012. 
  29. ^ “Regulation of Hydraulic Fracturing by the Office of Water”. US EPA. October 6, 2011. cfm. Retrieved October 14, 2011. 
  30. ^ Sumi, Lisa. “Our Drinking Water at Risk What EPA and the Oil And Gas Industry Don’t Want Us to Know About Hydraulic Fracturing”. Oil and Gas Accountability Project & Earthworks. http://www .earth Retrieved 16 October 2011. 
  31. ^ David Wethe (19 January 2012). “Like Fracking? You’ll Love ‘Super Fracking'”Businessweekhttp://www­fracking­youll­love­super­frac king­01192012.html. Retrieved 22 January 2012.
  32. ^ “Regulation of Hydraulic Fracturing Under the Safe Drinking Water Act”. EPA. 31 October 2011. cfm. Retrieved 7 November 2011. 
  33. ^ “H ydraulic Fracturing”. Environmental Protection Agency. htt p:// Retrieved 5 October 2011. 
  34. ^ “Treatment and Disposal of Wastewater from Shale Gas Extraction”. Environmental Protection Agency. acturing.cfm. Retrieved 15 October 2011. 
  35. ^ “Exemption of Oil and Gas Exploration and Production Wastes from Federal Hazardous Waste Regulations”. Environmental Protection Agency. http://www .epa.g ov/osw/nonhaz/industrial/special/oil/oil­gas.pdf. Retrieved 15 October 2011. 
  36. ^ “Natural Gas Drilling in the Marcellus Shale NPDES Program Frequently Asked Questions”. Environmental Protection Agency. 16 March 2011. http://www s/pubs/hydrofracturing_faq.pdf. Retrieved 15 October 2011. 
  37. ^
  38. ^ “Fracking Chemicals Cited in Congressional Report Stay Underground”. ProPublica. April 8, 2011. http://www­chemicals­cited­in­con gressional­report­stay­underground/single. Retrieved July 11, 2011.
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Multiple names for the same chemical can also leave you with the impression that there are more chemicals than actually exist. If you search the National Institute of Standards and Technology (NIST) ‡ website the alternate names of chemicals are listed.

Chemical Name CAS Chemical Purpose Product Function
Hydrochloric Acid 007647­01­0 Helps dissolve minerals and initiate cracks in the rock Acid
Glutaraldehyde 000111­30­8 Eliminates bacteria in the water that produces corrosive by­products Biocide
Quaternary Ammonium Chloride 012125­02­9 Eliminates bacteria in the water that produces corrosive by­products Biocide
Quaternary Ammonium Chloride 061789­71­1 Eliminates bacteria in the water that produces corrosive by­products Biocide
Tetrakis Hydroxymethyl­Phosphonium Sulfate 055566­30­8 Eliminates bacteria in the water that produces corrosive by­products Biocide
Ammonium Persulfate 007727­54­0 Allows a delayed break down of the gel Breaker
Sodium Chloride 007647­14­5 Product Stabilizer Breaker
Magnesium Peroxide 014452­57­4 Allows a delayed break down the gel Breaker
Magnesium Oxide 001309­48­4 Allows a delayed break down the gel Breaker
Calcium Chloride 010043­52­4 Product Stabilizer Breaker
Choline Chloride 000067­48­1 Prevents clays from swelling or shifting Clay Stabilizer
Tetramethyl ammonium chloride 000075­57­0 Prevents clays from swelling or shifting Clay Stabilizer
Sodium Chloride 007647­14­5 Prevents clays from swelling or shifting Clay Stabilizer

    Isopropanol000067­63­0Product stabilizer and / or winterizing agentCorrosion InhibitorMethanol000067­56­1Product stabilizer and / or winterizing agentCorrosion InhibitorFormic Acid000064­18­6Prevents the corrosion of the pipeCorrosion InhibitorAcetaldehyde000075­07­0Prevents the corrosion of the pipeCorrosion Inhibitor    Petroleum Distillate064741­85­1Carrier fluid for borate or zirconate crosslinkerCrosslinkerHydrotreated Light Petroleum Distillate064742­47­8Carrier fluid for borate or zirconate crosslinker

CrosslinkerPotassium Metaborate013709­94­9Maintains fluid viscosity as temperature increasesCrosslinkerTriethanolamine Zirconate101033­44­7Maintains fluid viscosity as temperature increasesCrosslinkerSodium Tetraborate001303­96­4Maintains fluid viscosity as temperature increasesCrosslinkerBoric Acid001333­73­9Maintains fluid viscosity as temperature increasesCrosslinkerZirconium Complex113184­20­6Maintains fluid viscosity as temperature increasesCrosslinkerBorate SaltsN/AMaintains fluid viscosity as temperature increasesCrosslinkerEthylene Glycol000107­21­1Product stabilizer and / or winterizing agent.CrosslinkerMethanol000067­56­1Product stabilizer and / or winterizing agent.Crosslinker    Polyacrylamide009003­05­8“Slicks” the water to minimize frictionFriction ReducerPetroleum Distillate064741­85­1Carrier fluid for polyacrylamide friction reducerFriction ReducerHydrotreated Light Petroleum Distillate064742­47­8Carrier fluid for polyacrylamide friction reducerFriction ReducerMethanol000067­56­1Product stabilizer and / or winterizing agent.Friction ReducerEthylene Glycol000107­21­1Product stabilizer and / or winterizing agent.Friction Reducer

 Guar Gum009000­30­0Thickens the water in order to suspend the sandGelling AgentPetroleum Distillate064741­85­1Carrier fluid for guar gum in liquid gelsGelling AgentHydrotreated Light Petroleum Distillate064742­47­8Carrier fluid for guar gum in liquid gelsGelling AgentMethanol000067­56­1Product stabilizer and / or winterizing agent.Gelling AgentPolysaccharide Blend068130­15­4Thickens the water in order to suspend the sandGelling AgentEthylene Glycol000107­21­1Product stabilizer and / or winterizing agent.Gelling Agent    Citric Acid000077­92­9Prevents precipitation of metal oxidesIron ControlAcetic Acid000064­19­7Prevents precipitation of metal oxidesIron ControlThioglycolic Acid000068­11­1Prevents precipitation of metal oxidesIron ControlSodium Erythorbate006381­77­7Prevents precipitation of metal oxidesIron Control    Lauryl Sulfate000151­21­3Used to prevent the formation of emulsions in the fracture fluidNon­EmulsifierIsopropanol000067­63­0Product stabilizer and / or winterizing agent.Non­EmulsifierEthylene Glycol000107­21­1Product stabilizer and / or winterizing agent.

Non­Emulsifier    Sodium Hydroxide001310­73­2Adjusts the pH of fluid to maintains the effectiveness of other components, such as crosslinkerspH Adjusting AgentPotassium Hydroxide001310­58­3Adjusts the pH of fluid to maintains the effectiveness of other components, such as crosslinkerspH Adjusting AgentAcetic Acid000064­19­7Adjusts the pH of fluid to maintains the effectiveness of other components, such as crosslinkerspH Adjusting AgentSodium Carbonate000497­19­8Adjusts the pH of fluid to maintains the effectiveness of other components, such as crosslinkerspH Adjusting AgentPotassium Carbonate000584­08­7Adjusts the pH of fluid to maintains the effectiveness of other components, such as crosslinkerspH Adjusting Agent

   Copolymer of Acrylamide and Sodium Acrylate025987­30­8Prevents scale deposits in the pipeScale InhibitorSodium PolycarboxylateN/APrevents scale deposits in the pipeScale InhibitorPhosphonic Acid SaltN/APrevents scale deposits in the pipeScale Inhibitor    Lauryl Sulfate000151­21­3Used to increase the viscosity of the fracture fluidSurfactantEthanol000064­17­5Product stabilizer and / or winterizing agent.SurfactantNaphthalene000091­20­3Carrier fluid for the active surfactant ingredientsSurfactant

Methanol000067­56­1Product stabilizer and / or winterizing agent.SurfactantIsopropyl Alcohol000067­63­0Product stabilizer and / or winterizing agent.Surfactant2­Butoxyethanol000111­76­2Product stabilizerSurfactant

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Chemical Name Pounds
1. NITRATE COMPOUNDS 202,596,204
3. AMMONIA 4,865,069
4. METHANOL 4,359,461
5. SODIUM NITRITE 2,654,640
6. ETHYLENE GLYCOL 1,535,979
8. ZINC COMPOUNDS 1,065,962
11. ACETALDEHYDE 346,793
12. FORMALDEHYDE 335,018
13. GLYCOL ETHERS 276,640
14. CHLORINE 257,659
15. PICLORAM 240,111
16. FORMIC ACID 239,264
19. MANGANESE 113,093
20. LEAD COMPOUNDS 104,591
23. PHENOL 92,367
24. 1,4­DIOXANE 75,119
25. UNKNOWN 71,629
33. COPPER 37,147
35. ZINC 34,920
36. LEAD 34,072
39. NAPHTHALENE 27,502
42. TOLUENE 24,721
44. N­BUTYL ALCOHOL 23,328
46. NICKEL 20,257
48. FLUORINE 19,434
49. BENZENE 19,393
52. CATECHOL 16,929
53. CHLOROFORM 16,734
55. ALLYL ALCOHOL 13,920
59. ALUMINUM 12,368
60. CHROMIUM 12,252
61. CYCLOHEXANE 11,205
65. BARIUM 9,426
67. ACRYLIC ACID 8,129
68. N­HEXANE 7,317
70. PROPYLENE 6,594
71. 1,2,4­TRIMETHYLBENZENE 6,503
72. ANTIMONY 6,199
80. 1,2­DICHLOROETHANE 4,303
81. 1,2,3­TRICHLOROPROPANE 4,255
82. ANILINE 3,798
83. 2,4,5­TRICHLOROPHENOL 3,603
85. STYRENE 3,535
86. SELENIUM 3,260
89. COBALT 2,784
91. VANADIUM 2,666
97. 1,3­BUTADIENE 2,084
98. 2,4­DIMETHYLPHENOL 1,971
100. ETHYLENE 1,706

List of additives for hydraulic fracturing

Last updated June 4th 2012 From Wikipedia, the free encyclopedia
About 750 chemicals have been listed as additives for hydraulic fracturing in a report to the US Congress in 2011.[1] The following is a partial list of the chemical constituents in
additives used in fracturing operations, as indicated by the New York State Department of Environmental Conservation.[2] Each state has a contact person in charge of the fracking regulations of these additives [3].
Additives click

CAS Number

Chemical Constituent

2634­33­5 1,2­Benzisothiazolin­2­one / 1,2­benzisothiazolin­3­one
95­63­6 1,2,4­trimethylbenzene
123­91­1 1,4­Dioxane
3452­07­1 1­eicosene
629­73­2 1­hexadecene
112­88­9 1­octadecene
1120­36­1 1­tetradecene
10222­01­2 2,2 Dibromo­3­nitrilopropionamide, a biocide
27776­21­2 2,2’­azobis­{2­(imidazlin­2­yl)propane}­dihydrochloride
73003­80­2 2,2­Dibromomalonamide
15214­89­8 2­Acryl amido­2­methylpropane sulphonic acid sodium salt polymer
46830­22­2 2­acryloyloxyethyl(benzyl)dimethylammonium chloride
52­51­7 2­Bromo­2­nitro­1,3­propanediol
111­76­2 2­Butoxy ethanol
1113­55­9 2­Dibromo­3­Nitriloprionamide (2­Monobromo­3­nitriilopropionamide)
104­76­7 2­Ethyl Hexanol
67­63­0 2­Propanol / Isopropyl Alcohol / Isopropanol / Propan­2­ol
26062­79­3 2­Propen­1­aminium, N,N­dimethyl­N­2­propenyl­chloride, homopolymer
9003­03­6 2­propenoic acid, homopolymer, ammonium salt
25987­30­8 2­Propenoic acid, polymer with 2 p­propenamide, sodium salt / Copolymer of acrylamide and sodium acrylate
71050­62­9 2­Propenoic acid, polymer with sodium phosphinate (1:1)
66019­18­9 2­propenoic acid, telomer with sodium hydrogen sulfite
107­19­7 2­Propyn­1­ol / Propargyl alcohol
51229­78­8 3,5,7­Triaza­1­azoniatricyclo[,7]decane, 1­(3­chloro­2­propenyl)­chloride,
115­19­5 3­methyl­1­butyn­3­ol
127087­87­0 4­Nonylphenol Polyethylene Glycol Ether Branched / Nonylphenol ethoxylated / Oxyalkylated Phenol
64­19­7 Acetic acid
68442­62­6 Acetic acid, hydroxy­, reaction products with triethanolamine
108­24­7 Acetic Anhydride
67­64­1 Acetone
79­06­1 Acrylamide
38193­60­1 Acrylamide ­ sodium 2­acrylamido­2­methylpropane sulfonate copolymer
25085­02­3 Acrylamide ­ Sodium Acrylate Copolymer or Anionic Polyacrylamide
69418­26­4 Acrylamide polymer with N,N,N­trimethyl­2[1­oxo­2­propenyl]oxy Ethanaminium chloride
15085 02­3 Acrylamide­sodium acrylate copolymer
68551­12­2 Alcohols, C12­C16, Ethoxylated (a.k.a. Ethoxylated alcohol)
64742­47­8 Aliphatic Hydrocarbon / Hydrotreated light distillate / Petroleum Distillates / Isoparaffinic Solvent / Paraffin Solvent / Napthenic Solvent
64743­02­8 Alkenes
68439­57­6 Alkyl (C14­C16) olefin sulfonate, sodium salt
9016­45­9 Alkylphenol ethoxylate surfactants
1327­41­9 Aluminum chloride
73138­27­9 Amines, C12­14­tert­alkyl, ethoxylated
71011­04­6 Amines, Ditallow alkyl, ethoxylated
68551­33­7 Amines, tallow alkyl, ethoxylated, acetates
1336­21­6 Ammonia
631­61­8 Ammonium acetate
68037­05­8 Ammonium Alcohol Ether Sulfate
7783­20­2 Ammonium bisulfate
10192­30­0 Ammonium bisulfite
12125­02­9 Ammonium chloride
7632­50­0 Ammonium citrate
37475­88­0 Ammonium Cumene Sulfonate
1341­49­7 Ammonium hydrogen­difluoride
6484­52­2 Ammonium nitrate
7727­54­0 Ammonium Persulfate / Diammonium peroxidisulphate
1762­95­4 Ammonium Thiocyanate
7664­41­7 Aqueous ammonia
121888­68­4 Bentonite, benzyl(hydrogenated tallow alkyl) dimethylammonium stearate complex / organophilic clay
71­43­2 Benzene
119345­04­9 Benzene, 1,1’­oxybis, tetratpropylene derivatives, sulfonated, sodium salts
74153­51­8 Benzenemethanaminium, N,N­dimethyl­N­[2­[(1­oxo­2­propenyl)oxy]ethyl]­, chloride, polymer with 2­propenamide
10043­35­3 Boric acid
1303­86­2 Boric oxide / Boric Anhydride
71­36­3 Butan­1­ol
68002­97­1 C10 ­ C16 Ethoxylated Alcohol
68131­39­5 C12­15 Alcohol, Ethoxylated
10043­52­4 Calcium chloride
124­38­9 Carbon dioxide
68130­15­4 Carboxymethylhydroxypropyl guar
9012­54­8 Cellulase / Hemicellulase Enzyme
9004­34­6 Cellulose
10049­04­4 Chlorine dioxide
77­92­9 Citric Acid
94266­47­4 Citrus Terpenes
61789­40­0 Cocamidopropyl betaine
68155­09­9 Cocamidopropylamine Oxide
68424­94­2 Coco­betaine
7758­98­7 Copper(II) sulfate
31726­34­8 Crissanol A­55
14808­60­7 Crystalline Silica (Quartz)
7447­39­4 Cupric chloride dihydrate
1120­24­7 Decyldimethyl Amine
2605­79­0 Decyl­dimethyl Amine Oxide
3252­43­5 Dibromoacetonitrile
25340­17­4 Diethylbenzene
111­46­6 Diethylene glycol
22042­96­2 Diethylenetriamine penta (methylenephonic acid) sodium salt
28757­00­8 Diisopropyl naphthalenesulfonic acid
68607­28­3 Dimethylcocoamine, bis(chloroethyl) ether, diquaternary ammonium salt
7398­69­8 Dimethyldiallylammonium chloride
25265­71­8 Dipropylene glycol
139­33­3 Disodium Ethylene Diamine Tetra Acetate
5989­27­5 D­Limonene
123­01­3 Dodecylbenzene
27176­87­0 Dodecylbenzene sulfonic acid
42504­46­1 Dodecylbenzenesulfonate isopropanolamine
50­70­4 Sorbitol / Sorbitol
37288­54­3 Endo­1,4­beta­mannanase, or Hemicellulase
149879­98­1 Erucic Amidopropyl Dimethyl Betaine
89­65­6 Erythorbic acid, anhydrous
54076­97­0 Ethanaminium, N,N,N­trimethyl­2­[(1­oxo­2­propenyl)oxy]­, chloride, homopolymer
107­21 1 Ethane­1,2­diol / Ethylene Glycol
9002­93­1 Ethoxylated 4­tert­octylphenol
68439­50­9 Ethoxylated alcohol
126950­60­5 Ethoxylated alcohol
67254­71­1 Ethoxylated alcohol (C10­12)
68951­67­7 Ethoxylated alcohol (C14­15)
68439­46­3 Ethoxylated alcohol (C9­11)
66455­15­0 Ethoxylated Alcohols
84133­50­6 Ethoxylated Alcohols (C12­14 Secondary)
68439­51­0 Ethoxylated Alcohols (C12­14)
78330­21­9 Ethoxylated branch alcohol
34398­01­1 Ethoxylated C11 alcohol
61791­12­6 Ethoxylated Castor Oil
61791­29­5 Ethoxylated fatty acid, coco
61791­08­0 Ethoxylated fatty acid, coco, reaction product with ethanolamine
68439­45­2 Ethoxylated hexanol
9036­19­5 Ethoxylated octylphenol
9005­67­8 Ethoxylated Sorbitan Monostearate
9004­70­3 Ethoxylated Sorbitan Trioleate
64­17­5 Ethyl alcohol / ethanol
100­41­4 Ethyl Benzene
97­64­3 Ethyl lactate
9003­11­6 Ethylene Glycol­Propylene Glycol Copolymer (Oxirane, methyl­, polymer with oxirane)
75­21­8 Ethylene oxide
5877­42­9 Ethyloctynol
68526­86­3 Exxal 13
61790­12­3 Fatty Acids
68188­40­9 Fatty acids, tall oil reaction products w/ acetophenone, formaldehyde & thiourea
9043­30­5 Fatty alcohol polyglycol ether surfactant
7705­08­0 Ferric chloride
7782­63­0 Ferrous sulfate, heptahydrate
50­00­0 Formaldehyde
29316­47­0 Formaldehyde polymer with 4,1,1­dimethylethyl phenolmethyl oxirane
153795­76­7 Formaldehyde, polymers with branched 4­nonylphenol, ethylene oxide and propylene oxide
75­12­7 Formamide
64­18­6 Formic acid
110­17­8 Fumaric acid
65997­17­3 Glassy calcium magnesium phosphate
111­30­8 Glutaraldehyde
56­81­5 Glycerol / glycerine
9000­30­0 Guar Gum
64742­94­5 Heavy aromatic petroleum naphtha
9025­56­3 Hemicellulase
7647­01­0 Hydrochloric Acid / Hydrogen Chloride / muriatic acid
7722­84­1 Hydrogen peroxide
79­14­1 Hydroxy acetic acid
35249­89­9 Hydroxyacetic acid ammonium salt
9004­62­0 Hydroxyethyl cellulose
5470­11­1 Hydroxylamine hydrochloride
39421­75­5 Hydroxypropyl guar
35674­56­7 Isomeric Aromatic Ammonium Salt
64742­88­7 Isoparaffinic Petroleum Hydrocarbons, Synthetic
64­63­0 Isopropanol
98­82­8 Isopropylbenzene (cumene)
68909­80­8 Isoquinoline, reaction products with benzyl chloride and quinoline
8008­20­6 Kerosene
64742­81­0 Kerosine, hydrodesulfurized
63­42­3 Lactose
64742­95­6 Light aromatic solvent naphtha
1120­21­4 Light Paraffin Oil
14807­96­6 Magnesium Silicate Hydrate (Talc)
1184­78­7 methanamine, N,N­dimethyl­, N­oxide
67­56­1 Methanol
68891­11­2 Methyloxirane polymer with oxirane, mono (nonylphenol) ether, branched
8052­41­3 Mineral spirits / Stoddard Solvent
141­43­5 Monoethanolamine
44992­01­0 N,N,N­trimethyl­2[1­oxo­2­propenyl]oxy Ethanaminium chloride
64742­48­9 Naphtha (petroleum), hydrotreated heavy
91­20­3 Naphthalene
38640­62­9 Naphthalene bis(1­methylethyl)
93­18­5 Naphthalene, 2­ethoxy­
68909­18­2 N­benzyl­alkyl­pyridinium chloride
68139­30­0 N­Cocoamidopropyl­N,N­dimethyl­N­2­hydroxypropylsulfobetaine
7727­37­9 Nitrogen, Liquid form
68412­54­4 Nonylphenol Polyethoxylate
121888­66­2 Organophilic Clays
64742­65­0 Petroleum Base Oil
64741­68­0 Petroleum naphtha
70714­66­8 Phosphonic acid, [[(phosphonomethyl)imino]bis[2,1­ethanediylnitrilobis(methylene)]]tetrakis­, ammonium salt
8000­41­7 Pine Oil
60828­78­6 Poly(oxy­1,2­ethanediyl), a­[3,5­dimethyl­1­(2­methylpropyl)hexyl]­w­hydroxy­
25322­68­3 Poly(oxy­1,2­ethanediyl), a­hydro­w­hydroxy / Polyethylene Glycol
24938­91­8 Poly(oxy­1,2­ethanediyl), α­tridecyl­ω­hydroxy­
51838­31­4 Polyepichlorohydrin, trimethylamine quaternized
56449­46­8 Polyethlene glycol oleate ester
62649­23­4 Polymer with 2­propenoic acid and sodium 2­propenoate
9005­65­6 Polyoxyethylene Sorbitan Monooleate
61791­26­2 Polyoxylated fatty amine salt
127­08­2 Potassium acetate
12712­38­8 Potassium borate
1332­77­0 Potassium borate
20786­60­1 Potassium Borate
584­08­7 Potassium carbonate
7447­40­7 Potassium chloride
590­29­4 Potassium formate
1310­58­3 Potassium Hydroxide
13709­94­9 Potassium metaborate
24634­61­5 Potassium sorbate
112926­00­8 Precipitated silica / silica gel
57­55­6 Propane­1,2­diol, or Propylene glycol
107­98­2 Propylene glycol monomethyl ether
68953­58­2 Quaternary Ammonium Compounds
62763­89­7 Quinoline,2­methyl­, hydrochloride
15619­48­4 Quinolinium, 1­(phenylmethl),chloride
7631­86­9 Silica, Dissolved
5324­84­5 Sodium 1­octanesulfonate
127­09­3 Sodium acetate
95371­16­7 Sodium Alpha­olefin Sulfonate
532­32­1 Sodium benzoate
144­55­8 Sodium bicarbonate
7631­90­5 Sodium bisulfate
7647­15­6 Sodium bromide
497­19­8 Sodium carbonate
7647­14­5 Sodium Chloride
7758­19­2 Sodium chlorite
3926­62­3 Sodium chloroacetate
68­04­2 Sodium citrate
6381­77­7 Sodium erythorbate / isoascorbic acid, sodium salt
2836­32­0 Sodium Glycolate
1310­73­2 Sodium Hydroxide
7681­52­9 Sodium hypochlorite
7775­19­1 Sodium Metaborate .8H2O
10486­00­7 Sodium perborate tetrahydrate
7775­27­1 Sodium persulfate
9003­04­7 Sodium polyacrylate
7757­82­6 Sodium sulfate
1303­96­4 Sodium tetraborate decahydrate
7772­98­7 Sodium thiosulfate
1338­43­8 Sorbitan Monooleate
57­50­1 Sucrose
5329­14­6 Sulfamic acid
112945­52­5 Synthetic Amorphous / Pyrogenic Silica / Amorphous Silica
68155­20­4 Tall Oil Fatty Acid Diethanolamine
8052­48­0 Tallow fatty acids sodium salt
72480­70­7 Tar bases, quinoline derivs., benzyl chloride­quaternized
68647­72­3 Terpene and terpenoids
68956­56­9 Terpene hydrocarbon byproducts
533­74­4 Tetrahydro­3,5­dimethyl­2H­1,3,5­thiadiazine­2­thione (a.k.a. Dazomet)
55566­30­8 Tetrakis(hydroxymethyl)phosphonium sulfate (THPS)
75­57­0 Tetramethyl ammonium chloride
64­02­8 Tetrasodium Ethylenediaminetetraacetate
68­11­1 Thioglycolic acid
62­56­6 Thiourea
68527­49­1 Thiourea, polymer with formaldehyde and 1­phenylethanone
108­88­3 Toluene
81741­28­8 Tributyl tetradecyl phosphonium chloride
68299­02­5 Triethanolamine hydroxyacetate
112­27­6 Triethylene glycol
52624­57­4 Trimethylolpropane, Ethoxylated, Propoxylated
150­38­9 Trisodium Ethylenediaminetetraacetate
5064­31­3 Trisodium Nitrilotriacetate
7601­54­9 Trisodium orthophosphate
57­13­6 Urea
25038­72­6 Vinylidene Chloride/Methylacrylate Copolymer
7732­18­5 Water
1330­20­7 Xylene
Aliphatic acids
Aliphatic alcohol glycol ether
Alkyl Aryl Polyethoxy Ethanol
Alkylaryl Sulfonate
Aromatic hydrocarbons
Aromatic ketones
Oxyalkylated alkylphenol
Petroleum distillate blend
Polyethoxylated alkanol
Polymeric Hydrocarbons
Salt of amine­carbonyl condensate
Salt of fatty acid/polyamine reaction product
Surfactant blend


  1. ^ Nicholas Kusnetz (April8, 2011). “Fracking Chemicals Cited in Congressional Report Stay Underground”. ProPublica. http://www­chemicals­cited­in­con gressional­report­stay­underground/single. Retrieved July 11, 2011.
  2. ^ ” N atural Gas Development Activities and High‐volume Hydraulic Fracturing”New York State Department of Environmental Conservation. pp. 45–51. http://w w
  3. ^ Fracking Regulations;­Re gulations/
  • This page was last modified on 4 June 2012 at 20:37.
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| Toxic Chemical Releases
To get a report for your community, go GoodGuide to search for reports on specific areas.

Chemicals matching “arsenic” (see senior education for complete listing)

  • ARSENIC(7440­38­2).
  • ARSENIC (TRIVALENT) (22569­72­8).
  • ARSENIC ACID (7778­39­4).
  • ARSENIC ACID (H3ASO4), BARIUM SALT (2:3) (13477­04­8).
  • ARSENIC ACID (H3ASO4), CALCIUM SALT (10103­62­5).
  • ARSENIC ACID (H3ASO4), COBALT(2+) SALT (2:3) (24719­19­5).
  • ARSENIC ACID (H3ASO4), COPPER(2+) SALT (29871­13­4).
  • ARSENIC ACID (H3ASO4), COPPER(2+) SALT (2:3) (7778­41­8).
  • ARSENIC ACID (H3ASO4), IRON(2+) SALT (2:3) (10102­50­8).
  • ARSENIC ACID (H3ASO4), IRON(3+) SALT (1:1) (10102­49­5).
  • ARSENIC ACID (H3ASO4), LEAD(2+) SALT (2:3) (3687­31­8).
  • ARSENIC ACID (H3ASO4), MANGANESE(2+) SALT (1:1) (7784­38­5).
  • ARSENIC ACID (H3ASO4), NICKEL(2+) SALT (2:3) (13477­70­8).
  • ARSENIC ACID (H3ASO4), STRONTIUM SALT (2:3) (13464­68­1).
  • ARSENIC ACID (H3ASO4), ZINC SALT (2:3) (13464­44­3).
  • ARSENIC ACID, TRISILVER(1+) SALT (13510­44­6).
  • ARSENIC ALLOY, AS,GE (12719­61­8).
  • ARSENIC ANTIMONIDE (ASSB3) (12255­36­6).
  • ARSENIC BROMIDE (64973­06­4).
  • ARSENIC DISULFIDE (1303­32­8).
  • ARSENIC OXIDE (3) (1327­53­3).
  • ARSENIC PENTOXIDE (1303­28­2).
  • ARSENIC SELENIDE (1303­36­2).
  • ARSENIC SULFIDE (AS2S4) (12344­68­2).
  • ARSENIC TELLURIDE (AS2TE3) (12044­54­1).
  • ARSENIC TRISULFIDE (1303­33­9).
  • ARSENIC V (17428­41­0).
  • ARSENICAL DUST(8028­73­7).
  • ANTIMONY ARSENIC OXIDE (64475­90­7).
  • DIARSENIC ACID (13453­15­1).
  • DIARSENIC ACID, VANADIUM(4+) SALT (1:1) (99035­51­5).
  • STRYCHNIDIN­10­ONE, COMPD. WITH ARSENIC ACID (H3ASO4) (1:1) (10476­82­1).


[June 7th 2012


  • Overview Page
  • Glossary of Terms
  • Bibliography
  • Newsletter
  • Useful Links


  • Overview Page
  • Dental Fluorosis Classification Criteria
  • Mild Forms of Dental Fluorosis
  • Moderate to Severe Dental Fluorosis
  • Perception and Psychological Impact of Dental Fluorosis
  • Dental Fluorosis & Elevated Fluoride
  • Exposure as a Cause of Tooth Decay
  • Biology of Dental Fluorosis


  • Overview Page
  • “Universal Decline of Tooth Decay” Irrespective of Water Fluoridation
  • Topical Vs. Systemic Effects
  • Fluoride’s Impact on Smooth Tooth Surfaces vs Pit & Fissures
  • Water Fluoridation & Tooth Decay (Caries)
  • Fluoridation Cessation Studies
  • Water Fluoridation & Poverty




  • Fluoride & Osteoarthritis
  • Fluoride & Rheumatoid Arthritis
  • Fluoride & DISH (Diffuse Idiopathic Skeletal Hyperostosis)
  • Fluoride & Spondylosis/Spondylitis


Fluoride & Bone Fracture:

  • Overview Page
  • Fluoride & Bone Strength
  • Epidemiology on Fluoride & Bone Fracture
  • Fluoride­Induced Bone Fractures in Human Clinical Trials
  • Mechanisms by which fluoride may reduce bone strength

B) Fluoride & Bone Density:

  • Overview Page
  • Fluoride’s Differential Effect on Bone Density
  • Fluoride­induced Increase in Bone Density: Not associated with Increased Strength
  • Fluoride & Bone Density: Epidemiology

C) Skeletal Fluorosis:

  • Overview Page
  • The Difficulty of Diagnosis
  • “Pre­skeletal” Fluorosis
  • X­Ray Diagnosis of Skeletal Fluorosis
  • Skeletal Fluorosis in the U.S.

  • Skeletal Fluorosis in India & its Relevance to the West
  • High Individual Variability in Skeletal Response to Fluoride
  • Factors which may increase susceptibility to fluorosis
  • Variability in Radiographic Appearance of Fluorosis
  • Variable Length of Exposure Producing Fluorosis
  • Estimated “Threshold” Doses for Skeletal Fluorosis
  • Water Fluoride Levels Associated with Skeletal Fluorosis
  • Fluoridation, Dialysis, & Osteomalacia
  • Fluoride & Renal Osteodystrophy
  • Fluoride & Osteomalacia
  • Fluoride & Rickets 
  • Fluoride & Osteoid
  • Fluoride & Secondary Hyperparathyroidism
  • Fluoride & Osteopetrosis
  • Fluoride & Spinal Cord Compression
  • Crippling Skeletal Fluorosis


  • Overview
  • Fluoride & Mutagenicity
  • Fluoride & Osteosarcoma
  • Fluoride & Osteosarcoma Timeline
  • NTP Bioassay on Fluoride/Cancer (1990)
  • Fluoride & Liver Tumors in NTP Fluoride/Cancer Study
  • Interview with Dr. William Marcus (EPA)
  • Dr. William Marcus’ Internal Memo
  • Interview with Dr. William Hirzy (EPA)

[May 19th 2012]


FLUORIDE & the BRAIN (Click for more detail)

Fluoride’s ability to damage the brain represents one of the most active areas of research on fluoride toxicity today.

Concern about fluoride’s impact on the brain has been fueled by 18 human studies (from China, Mexico, India, and Iran) reporting IQ deficits among children exposed to excess fluoride, by 4 human studies indicating that fluoride can enter, and damage, the fetal brain; and by a growing number of animal studies finding damage to brain tissue (at levels as low as 1 ppm) and impairment of learning and memory among fluoride­treated groups.

According to the US National Research Council, “it is apparent that fluorides have the ability to interfere with the functions of the brain.”

 (Click for more detail)

Summation – Fluoride & Pineal Gland:

Up until the 1990s, no research had ever been conducted to determine the impact of fluoride on the pineal gland – a small gland located between the two hemispheres of the brain that regulates the production of the hormone melatonin. Melatonin is a hormone that helps regulate the onset of puberty and helps protect the body from cell damage caused by free radicals.

It is now known – thanks to the meticulous research of Dr. Jennifer Luke from the University of Surrey in England – that the pineal gland is the primary target of fluoride accumulation within the body.


FLUORIDE & BONE DISEASE (Click for more detail)

Excessive exposure to fluoride is well known to cause a bone disease called skeletal fluorosis.

Skeletal fluorosis, especially in its early stages, is a difficult disease to diagnose, and can be readily confused with various forms of arthritis including osteoa rthritis and rheumatoid arthritis.

In its advanced stages, fluorosis can resemble a mul
 of bone/joint diseases.

In individuals with kidney disease, fluoride exposure can contribute to, and/or exacerbate, renal osteodystrophy.


FLUORIDE & the KIDNEYS (Click for more detail)

The kidneys play a vital role in preventing the build­up of excessive fluoride in the body. Among healthy individuals, the kidneys excrete approximately 50% of the daily fluoride intake. However, among individuals with kidney disease, the kidneys’ ability to excrete becomes markedly impaired, resulting in a build­up of fluoride within the body.

It is well recognized that individuals with kidney disease have a heightened susceptibility to the cumulative toxic effects of fluoride.

Of particular concern is the potential for fluoride, when accumulated in the skeletal system, to cause, or exacerbate, renal osteodystrophy – a bone disease commonly found among people with advanced kidney disease.


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