Domestic Shale Gas Reserves Natural gas supplies 22% of US energy demand and 40% of electricity production US has 1744 tcf recoverable natural gas, enough for 100 years Lower 48 states have gas reserves in clay-like rock formations

Horizontal Drilling and Hydraulic Fracturing Horizontal drilling allows 1 well-pad to access the same reservoir volume as 16 vertical

wells Hydro fracking involves pumping of high pressure liquid into shale to generate cracks in

the rock formation and release natural gas Fracking liquids contain sand, water, and unknown chemicals Cement and casing are installed to protect groundwater supplies

Accessing the natural gas trapped in shale formations became economically feasible in the 1990s, with the advent of high-volume horizontal hydraulic fracturing, better known as hydrofracking. Before then, the low natural permeability of shale limited the production of shale gas resources because it only allows minor volumes of gas to flow naturally to a wellbore. The hydrofracking process allows this gas to be drilled economically. Between 1990 and 2009, the number of active natural gas wells in the US almost doubled to more than 493,000. Hydrofracking dominates the industry—hydrofracking has been used at approximately 90% of the wells to get the gas moving. As the shale gas industry has grown, far higher amounts of wastewater and other pollutants are being produced. Fracturing is accomplished in stages commencing at either end of the wellbore. Each stage will use between 300,000-600,000 gallons of fracturing fluid. There are 8-13 stages ranging between 300 and 500 feet in length. Each fracturing operation requires from 2-5 days and that high pressure (up to 10,000 psi) pumping at rates up to 3000 gpm.

Environmental activists want to support a transition to clean natural gas, which burns with 50% less carbon emissions than coal and 30% less carbon emissions than gasoline. Questions about the safety of shale gas drilling have not been answered, and the risks associated with drilling are not well understood.

Major Environmental Concerns:

Drinking water may be contaminated in the hydrofracking process by a number of potentially dangerous and carcinogenic substances and is the main focus of environmental groups.

Waste water (heavy metals, radioactive materials, benzene, and fracking chemicals) Fracking liquid that moves through the rock formations (sand, bactericides, and

chemicals in unknown quantities) Methane from the well-bore or underground seeps

Air pollution may occur due to drilling operations. Emissions of methane, propane, butane, NOx, SO2 at drilling sites are not accounted for.

Emissions result from poor construction, maintenance, and supervision. Air pollutants may react to produce other hazardous contaminants, such as ozone.

Water used for hydrofracking may aggravate scarcity problems. Up to 7.8 million gallons of water are used at each site. 2/3 of this water does not return,

and the other 1/3 may be too toxic to treat effectively This can be significant, especially in areas of the country that face water scarcity

problems or rely on water supplies that take years to replenish. A 5,000,000 gallon depletion is more than 15 domestic wells would remove in a year.

No studies have been done on the impact to aquatic life and local biomes.

Sources of Drinking Water Contamination

Drinking water contamination may occur in the short term by wastewater that is dumped as sewage, not properly treated, and then drunk. This wastewater can contain benzene, heavy metals, and radioactive materials leeched from the shale, as well as the chemicals added to fracking liquids. Traditional water treatment plants cannot effectively filter these wastes, so harmful chemicals can make it into the drinking supply. This issue is discussed extensively in the section on Pennsylvania.

Drinking water contamination may occur in the long term by fracking liquid that stays underground after the drilling process is over (approx. 65-80%) and seeps into underwater aquifers over time (500 years). It is possible that the fracking process itself creates or elongates fissures in the shale that can allow harmful liquids to flow more quickly. The USGS fact sheet wrongly states that all fracking liquid returns to the surface. Parts of the fractured Marcellus Shale may be especially permeable to water. This is explained more fully on the next page.

At the well-bore, methane and hydraulic fracturing liquid may enter aquifers during gas production or flowback. The primary cause of this is poor construction. Appropriate monitoring, clean up efforts, and setbacks could greatly reduce this source of water contamination. The NRDC believes that the current requirement for one year of sampling groundwater sources after drilling operations end is too low—this may not count slower-moving contaminants. Instead, they suggest five years as a more reasonable time frame. By some estimates, if tanks are not properly used during operations, and even 2% of the methane escapes, then the carbon benefits of natural gas are eliminated.

On a smaller scale, drinking water contamination may also occur through the improper storage of fracking water and some recovered wastewater on site. According to NYSDEC, most flowback occurs within 2 to 8 weeks, with 60% returning in the first 4 days. Flowback from wells in PA have ranged from 60 to 130 gpm. The ability of industry to effectively capture, store, and treat this high-pressure liquid is questionable. This storage currently takes place in centralized impoundment tanks or on-site pools that may leak or spill and allow chemicals to enter the groundwater. The NRDC reports that the pools currently being used allow a very high rate of leakage (100 gpd per acre of pond) without any leak detection system. Some of the pools use a geosynthetic clay liner rather than impacted clay, though it has a higher and more variable

ionic conductivity—with up to 5 orders of magnitude difference. The NRDC estimates that flow could pass though in less than a year. The NRDC would like these replaced by closed-loop steel tanks and piping systems, or at least double-layered pools.

Questions about Fracking Liquids

Up to 7.8 million gallons of water are used at each drilling site as fracking liquids. Fracking liquids must be stored on site and mixed during drilling operations, though are currently no procedures outlining how this must be carried out, and there is great potential for spills. In order to store 7.8 million gallons of water on site, the NRDC estimates that 350 “500-barrel steel tanks,” which can each hold up to 21,000 gallons of water would be needed.

Fracking liquids are reported to be 98% water and sand, but their composition is unregulated and unknown to the public. (The DOE’s list of fracking liquid chemicals is on p. 9. It is similar to the NRDC list.) Fracking liquids commonly contain food additives, lubricants, binding materials, and biocides to prevent corrosion, among other chemicals. Sites use their own mixture of chemicals, which are not released to the public. Environmental groups are concerned that these chemicals may enter the groundwater supply through spills, wastewater dumping, and seepage.

According to the US Department of Energy, “ground water is protected during the shale gas fracturing process by a combination of the casing and cement that is installed when the well is drilled and the thousands of feet of rock between the fracture zone and any fresh or treatable aquifers.” The environmental community continues to have concerns about the 65-80% of the hydrofracking liquid that never returns to the surface. This water may stay in underground pores, adhere to rocks, or migrate over time, though its movement has not been well tracked thus far. In addition, the ability of the cement and casings to prevent water seepage over time has not been shown.

Shale gas drilling generally takes place over 2,000 ft below ground, with underground aquifers that are not lower than 1,000 ft below ground. The shale gas industry has said that this 1,000 ft separation by “sands and shales of moderate to low conductivity” will protect the water supply. In most cases, the distance is significantly longer, perhaps 5,000 ft. It is unclear whether the fracking process creates or expands vertical and horizontal fissures in the rock formations that could allow fracking liquids to travel more quickly. It is also possible that networks of fissures could facilitate water movement. Although these are low-probability individual events, given the large number of wells, we do not have models that can calculate the aggregate risk to the water supply in the time frame of 500 years.

The Marcellus Shale porosity varies to 18%. Un-fractured shale an “aquitard” that is relatively impermeable to water. Matrix permeabilities rage from .01 to .00001 milidarcies. For water at 15.6°C, this range is .000027 to .00000007 ft/d2. The properties of fractured shale—such as the Marcellus formation—are different and less well known. The conductivity range given by the DSGEIS samples would be .000011 to .00059 ft/d. At the larger end of this range, the Darcian flow over a unit gradient for 100 years would be 21.5 feet. Other samples of the shale are likely

to give higher conductivity values. A calculation done by the NRDC estimated that the potential distance traveled over 100 years could be as large as 2100 feet. Oil and gas companies have stated that a barrier of 1,000 feet between the shale gas drilling zone and the underground aquifers provides will prevent contamination of water supplies, though the necessary studies have not been performed.

The NRDC recommends vertical setbacks for wells that would prevent water contamination for at least 500 years. These should be based on vertical gradient maps that show areas of upward movement and not on the current arbitrary standard of 1,000 ft. Since motion also occurs horizontally, the NRDC recommends horizontal setbacks that include an absorbent berm around the well pad to create a detention volume of at least 25,000 gallons. (Calculations suggest that flowback volumes could be 23,000 gallons in three hours, which could easily flow into nearby rivers or streams to enter water supplies.) Regulations of hydrofracking should be based on a conceptual and numerical flow model that accurately describes the motion of fracking liquid through the shale over time. Increased sampling and computer simulations must occur to determine maximum flow rates and guide regulation.

Air Quality Management

Of the environmental issues associated with natural gas drilling, the issue of emissions has been the least publicized. However, at the wellhead, significant amounts of methane, propane, butane, NOx, and SO2 may be released locally. The various combinations of gases vary by site and require separate strategies for air quality management. Estimated shale gas emissions are likely too low. Emissions are not being fully counted right now because an individual well counts as a small “point source” that produces small quantities of air pollution. Hundreds of thousands of wells, however, produce a significant emissions total. Calculations that aggregate the sources are needed to guide regulations.

In 2009, Wyoming failed to meet federal air quality standards for the first time in its history. 27,000 wells, most of which have been built in the past 5 years, have been releasing fumes containing benzene and toluene. In some regions, these vapors react with sunlight, producing levels of ozone as high as in Houston and Los Angeles. In Texas, where there are now 93,000 gas wells (up from about 50,000 in 2000), a hospital system found a 25% asthma rate for children in the 6 counties with most drilling. The state average is 7%. Gas has seeped into underground drinking water supplies in at least five states—Colorado, Ohio, Pennsylvania, Texas, and West Virginia.

Computing the total air emissions is not a trivial question—there are many steps in the process that have not been properly accounted for yet. For example, US hydrofracking operations use sand shipped by rail from Canada and Illinois; this transportation raises total carbon dioxide emissions.

Marcellus Shale Properties 15% of estimated US shale gas reserves Fractured shale with highly variable formation and water permeability Located near major watersheds in 6 northeastern states

The Marcellus Shale is the country’s most expansive shale gas play, spanning six northeastern states. Estimated gas estimates are up to 1,500 tcf, or about 15% of the US total. The Marcellus Shale covers an area 95,000 square miles at an average thickness 50-200 ft. The estimated depth of production is 4,000-8,500 ft. Importantly, the Marcellus Shale is varied in its composition; the field samples taken from one spot may not adequately represent another region.

Pennsylvania Case Study Natural gas in the Marcellus Shale provides opportunity for huge economic development Lack of appropriate safeguards and regulation led to environmental damage and erosion

of public trust Research is needed to develop risk-balanced regulations

Pennsylvania presents an interesting case study in the benefits and risks of shale gas drilling. The state has a long history of energy production and fossil fuel extraction—starting in 1859 when Colonel Drake drilled the famous Drake well in Titusville. The last few years have seen a huge boom in shale gas drilling, as it presents an attractive way for the recession-hit state to generate income. There are roughly 71,000 active gas wells, up from about 36,000 in 2000. This has brought thousands of jobs to the region, as well as tens of thousands of dollars to residents who lease their land for drilling. Last year, drilling companies received 3,300 permits to drill in the Marcellus Shale. At the same time, the Pennsylvania landscape has changed, and there has been significant environmental damage to various localities. Natural gas trade groups and representatives say their wells now produce much less wastewater because they are recycling it rather than disposing of it after each job. However, the industry projects 50,000 new wells will be built in Pennsylvania in the next 20 years, increasing the likely total amount of wastewater produced. Republican governor Tom Corbett has promised to re-open state land to new drilling, reversing the decision of former Democratic governor Ed Rendell. This clears the way for as many as 10,000 wells on public land.

The Pennsylvania Department of Environmental Protection investigates complaints about natural gas migration. Some of these complaints are due to stray gas from microbial processes, landfills, mining activity, etc. Natural gas drilling presents a danger of water contamination and methane seepage from wellbores (via either improperly constructed or old, deteriorated wells). These complaints are categorized according the likely type of well that produced them: new wells that are being drilled or re-drilled; active or operating wells that are producing gas or are unplugged; legacy or abandoned wells, and underground storage of natural gas. Between 2000-2009, there were 14 stray gas migration complaints originating from new wells, 11 stray gas migration complaints originating from operating wells, 39 stray gas migration cases originating from legacy or abandoned wells, and 2 complaints from underground methane storage units. Many of these incidents involve methane that has entered the drinking water supply—wells or

aquifers—or has been detected in soil. Investigations discovered gas wells were over-pressured; well casings were compromised, and sites had been abandoned without being properly plugged. In some cases, the methane accumulated indoors and exploded, resulting in a few fatalities. Sometimes, the sources are known, sometimes not. There are documented cases of methane contamination thousands of feet away from the source. For example, the “Ohio DNR (2008) documents the effects of not properly constructing the well and that gas was found in a well 4700 feet away within about a month.”

According to the Pennsylvania Department of Environmental Protection, one of the more egregious examples of methane seepage occurred in Dimock, PA:

“Dimock Migration, Dimock Twp., Susquehanna County - Cabot Oil and Gas – NCRO - 2009: The Department is actively monitoring domestic water supplies and investigating potential cause(s) of a significant gas migration that has been documented in several homes along Carter Road. Free gas has been encountered in six domestic water supplies and dissolved has (sic) been found in several of the wells. The operator has placed pilot water treatment systems on three water supplies. Of particular note is that this area has not experienced previous drilling and recent gas drilling in the vicinity has targeted the Marcellus Shale.”

Drilling contamination has also occurred in Pennsylvania through spills. At least 16 wells whose records showed high levels of radioactivity in their wastewater also reported spills, leaks, or failures of pits where hydrofracking fluid or waste is stored. Gas producers are generally left to deal with spills without regulatory oversight. They report their own spills, write their own spill response plans, and lead their own cleanup effort. In Pennsylvania, regulators do not perform unannounced inspections to check for signs of spills.

From the NRDC review, PADEP (2009) noted that they required Cabot Oil and Gas to cease operations in Dimock Township, PA, due to “three separate spills … in less than one week”. Cabot signed a consent order, agreeing to pay a $120,000 fine, that outlined many instances of leaks and spills. . . .

Cabot had spilled carcinogenic chemicals into surface waters in Dimock, according to ProPublica: According to a Material Safety Data Sheet provided to the state this week by Halliburton, the spilled drilling fluid contained a liquid gel concentrate consisting of a paraffinic solvent and polysaccharide, chemicals listed as possible carcinogens for people. The MSDS form – for Halliburton’s proprietary product called LGC-35 CBM – does not list the entire makeup of the gel or the quantity of its constituents, but it warns that the substances have led to skin cancer in animals and "may cause headache, dizziness and other central nervous system effects" to anyone who breathes or swallows the fluids. (http://www.propublica.org/feature/frack-fluid-spill-in-dimock-contaminatesstream- killing-fish-921

The issue that has received the most attention in Pennsylvania (and one of the main concerns of the environmental community) is the fate of wastewater treatment. There is no comprehensive federal standard for what constitutes safe levels of radiation in drilling wastewater. In most states where shale gas drilling occurs, the wastewater is kept in underground storage wells below less permeable rock layers to prevent it from entering municipal supplies. Regulations are out of date in Pennsylvania, where some of the worst accidents have occurred. Pennsylvania is the only state where drilling companies are allowed to cart wastewater to municipal sewage plants for treatment. More than 1.3 billion gallons of wastewater was produced by Pennsylvania wells—far more than previously disclosed—in the past three years. In 2008-2009, at least half of the wastewater produced was trucked to 12 public sewage treatment plants in Pennsylvania, New York, and West Virginia. The wastewater may contain levels of radiation hundreds or thousands of times the legal limit, which makes it unsafe for the regular sewage treatment plants to handle, according to federal regulators.

The New York Times did a review of the publicly available data on Pennsylvania water contamination (http://www.nytimes.com/interactive/2011/02/27/us/natural-gas-map.html) and discovered that:

42 wells exceeded federal drinking water standard for radium, at least 5 by 1000-3000 X federal limit (which is 5pCi/L for radium).

4 wells exceeded federal drinking water standard for uranium by 2-10 X federal limit (which is 30 microG/L).

128 wells exceeded federal drinking water standard for gross alpha exposure. It is hard to tell from the graphic, but at least 20% seem to have exceeded the federal limit of 15pCi/L by 300-1000X.

41 wells exceeded federal drinking water standard for benzene, which is 5 ppb. One well had a measured benzene level of 880 ppb. Many sites on the map did not have measurements for benzene levels.

Although the plants are not designed to treat water with such high levels of salts and radioactive particles, they accept the water and then return it partially cleaned into rivers that supply drinking water for major cities. Radioactive contaminants are more difficult for sewage treatment plants to remove than other toxic substances, and most of these facilities cannot remove enough of the radioactive materials that the water they return meets federal drinking standards. Discharged wastewater has made it into some of the state’s biggest rivers: the Monongahela, which provides drinking water to more than 800,000 people including Pittsburgh; the Susquehanna, which provides drinking water to more than 6 million people, including some in Harrisburg and Baltimore, and less has made it into the Delaware River, which provides drinking water to more than 15 million people. In 2008, during a prolonged drought, local officials advised Pittsburgh residents to drink bottled water because waste from shale gas drilling and coalmines had so polluted the Monongahela.

Regulators and gas companies have repeatedly claimed that the radiation is diluted to safe levels once it enters the rivers, though the available data do not supported this. Indeed, a confidential American Petroleum Institute study from 1990 concluded that “using conservative assumptions” radium in drilling wastewater dumped off the Louisiana coast into the Gulf

of Mexico posed “potentially significant risks” of cancer for people who regularly eat fish from those waters. The Gulf of Mexico would dilute the radium levels far more than Pennsylvania rivers. In 2009, EPA scientists determined that certain Pennsylvania rivers unable to sufficiently dilute the radium in drilling wastewater to safe levels.

The EPA has not intervened; federal and state regulators allow most sewage treatment plants that accept drilling wastewater not to test for radioactivity. Most drinking-water intake plants downstream of the drilling wells have not tested for radioactivity since 2005, though the shale gas drilling boom began in 2008. (Federal and state laws regulators have allowed Pennsylvania drinking-water intake facilities to rest their water only once every 6-9 years.) It is unclear if water treatment plants are able to treat this water at all. Wastewater from shale gas drilling can contain heavy metals, radioactive materials, benzene, and other organic chemicals in high concentrations. Without proper oversight, this wastewater has been dumped into municipal water supplies.

More than 179 wells produced wastewater with high levels of radiation; at least 116 wells reported levels of radium or other radioactive materials 100 times the limit for acceptable drinking water. Of these, at least 15 wells produced wastewater with radioactive contaminants at 1000 times the legal limit. In 2009-2010, public sewage treatment plants directly upstream of drinking-water intake facilities accepted wastewater with radioactivity levels as high as 2,122 times the federal drinking standard. EPA scientists recommended to the State of New York that sewage treatment plants not accept drilling waste with radium levels 12 or more times the federal drinking standard. Increased testing, improved means for wastewater cleanup, and more sophisticated regulations are necessary to prevent the kinds of accidents that have occurred in Pennsylvania.

Severance Taxes:

In this era of questionable federal financing, states stand to gain tax revenue from shale gas drilling. Severance taxes are levied on industry groups for the extraction of valuable materials, such as coal, oil, or natural gas. These taxes are not uniform at the state level and do not yet exist on the federal level. The federal government allows leasing of mineral rights, but it does not tax extraction. A federal model for these taxes would have to start with state examples because there is no foreign model. In other countries, all minerals are viewed as state property; companies are allowed to develop them for a profit—like some of the US utilities—without owning them. Some environmental groups support severance taxes as a more acceptable, backdoor carbon tax.

There is no consistency between different states’ severance tax rates. Within a state, different minerals may each have a separate tax on its extraction. States with more mineral reserves (Alaska and Texas, for example) tend to have higher severance tax rates, as they have significant experience with energy extraction. States without traditional reserves do not usually have severance taxes. The passage of severance taxes in New York State would be an indicator of significant natural gas drilling in the Marcellus Shale.

Proposed Research Small-scale sampling at multiple drill sites to learn specific geology to improve

computer simulations: Mentioned before, the Marcellus Shale is a fractured shale with variable permeability. The few samples that have been taken for analysis are unlikely to represent the geology of the whole formation. This basic information is necessary in order to build more accurate models.

Advanced computer simulations of wastewater and fracking liquid motion over time: The goal is to determine the speed of fracking liquid movement through various shale types. The current estimates for seepage rates vary widely and have different policy implications for fracking liquid storage underground. Various chemicals may move or adhere to the rock at different rates. It is important to remember that, once it has been used for fracking, this liquid may have concentrations of radioactive particles and heavy metal salts thousands of times the legal limit. While the need for this type of research is most obvious for the un-recovered fracking liquid belowground, it is also necessary to learn how quickly fracking liquids can travel above-ground (from spill sites or leaking storage pools) to municipal water supplies.

Analysis and treatment of wastewater: The case study of hydraulic fracturing in Pennsylvania has demonstrated that the amount of wastewater produced and its levels of contamination are greater than previously thought. In some cases, existing sewage treatment facilities are unable to clean this wastewater enough for it to meet federal drinking standards. Mandatory testing must occur upstream and downstream of municipal sewage treatment plants and water-intake plants to determine whether water supplies are safe to drink. If not, alternate means of water treatment (perhaps on-site by the gas companies) or storage must occur. Most states with significant hydrofracking activity store the water thousands of feet below ground in containers to prevent it from contaminating drinking water. Research is needed to determine which of these approaches is the most effective.

Analysis and development of fracking liquids that can be easily and economically treated: For many reasons, it would be beneficial to develop fracking liquids that can be treated or recycled more easily. This would reduce the fresh water needs of future drilling wells and take pressure off of delicate ecosystems. It would also improve the public perception of shale gas drilling if fracking liquids and wastewater could be made safe for public consumption. The first step in this process is determining the real composition of fracking liquids, which has been kept an industry secret so far. Ultimately, it may be possible to improve these fracking liquids to increase liquid separation and gas yield.

Assessment of total airborne emissions: Treating individual wells as point sources of carbon production that produce negligible sources of air pollutants leads to calculated emissions that are far too low. While natural gas is cleaner burning than coal and oil, it is important to know what quantities of greenhouse gases and other airborne chemicals are being released. Benzene and toluene concentrations, for example, have risen in areas with heavy drilling. In addition, it is possible for methane and other gases to travel thousands

of feet from insecure wellbores and improperly constructed storage units to cause contamination of local aquifers and soil. More stringent testing and reporting of gas emissions must occur to properly regulate the shale gas industry. Computer simulations would aid in the aggregation of these totals.

Materials testing of storage materials: The durability of cement and casing materials used in the hydrofracking process are not currently known, even though these structures are being trusted to contain water contaminated with radioactive particles, organic compounds, heavy metal salts, and other chemicals for hundreds of years. Standards for cement and casing would be improved through testing and computer simulations. Similar methods should apply to the development of effective aboveground storage—the NRDC currently recommends double-layer pools or closed-loop containment in steel casks.

FRACTURING FLUID ADDITIVES, MAIN COMPOUNDS, AND COMMON USES.

Additive TypeMain Compound(s) Purpose Common Use of Main Compound

Diluted Acid (15%)

Hydrochloric acid or muriatic acid

Help dissolve minerals and initiate cracks in the rock Swimming pool chemical and cleaner

Biocide GlutaraldehydeEliminates bacteria in the water that produce corrosive byproducts

Disinfectant, sterilize medical and dental equipment

BreakerAmmonium persulfate

Allows a delayed break down of the gel polymer chains

Bleaching agent in detergent and hair cosmetics, manufacture of household plastics

Corrosion Inhibitor

N,n-dimethyl formamide Prevents the corrosion of the pipe

Used in pharmaceuticals, acrylic fibers, plastics

Crosslinker Borate saltsMaintains fluid viscosity as temperature increases

Laundry detergents, hand soaps, and cosmetics

Friction Reducer PolyacrylamideMinimizes friction between the fluid and the pipe Water treatment, soil conditioner

Friction Reducer Mineral oilMinimizes friction between the fluid and the pipe

Make-up remover, laxatives, and candy

Gel

Guar gum or hydroxyethyl cellulose

Thickens the water in order to suspend the sand

Cosmetics, toothpaste, sauces, baked goods, ice cream

Iron Control Citric acid Prevents precipitation of metal oxides

Food additive, flavoring in food and beverages, Lemon Juice ~7% Citric Acid

KClPotassium chloride Creates a brine carrier fluid Low sodium table salt substitute

Oxygen Scavenger

Ammonium bisulfite

Removes oxygen from the water to protect the pipe from corrosion

Cosmetics, food and beverage processing, water treatment

pH Adjusting Agent

Sodium or potassium carbonate

Maintains the effectiveness of other components, such as crosslinkers

Washing soda, detergents, soap, water softener, glass and ceramics

ProppantSilica, quartz sand

Allows the fractures to remain open so the gas can escape

Drinking water filtration, play sand, concrete, brick mortar

Scale Inhibitor Ethylene glycol Prevents scale deposits in the pipeAutomotive antifreeze, household cleansers, and deicing agent

Surfactant IsopropanolUsed to increase the viscosity of the fracture fluid

Glass cleaner, antiperspirant, and hair color

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