Fracking brief: Experts study water needs for oil shale development.

The technology required for a future oil shale industry is uncertain. Thus, water demands for developing the resource is also uncertain, a newly published report said. The study, “Energy Development Water Needs Assessment Phase II — Final Report,” was produced for the Colorado River and Yampa/White River Basin Roundtables by an engineering consulting firm, AMEC Earth & Environmental.

The Colorado Water for the 21st Century Act in 2005, established nine Colorado roundtables to study future water needs for the state’s cities, agriculture, energy development and recreation. Grand Junction Utility and Streets manager Greg Trainor represented Mesa County municipalities on the Colorado River Basin Roundtable. He met with interested citizens Thursday, July 12, in the Mesa County government building, 544 Rood Ave. to discuss its study regarding future Western Slope water needs.

“Assuming that the state will double in population by 2050, municipalities will be looking for water,” Trainor said. “We need to get a handle on water estimates for energy development.”

Phase one of the report looked at water uses of all conventional energy sectors — oil shale, natural gas, coal and uranium. Much of the information for the report was collected from the Bureau of Land Management, and oil and gas companies.

“In phase one, we did not get as much coöperation from (the) industry as we wanted — particularly concerning oil shale development,” Trainor said. The initial phase of the report found oil shale would require 400,000 acre feet of water per year to support a long-term, high-production scenario that would produce a million-and-a-half barrels of oil shale a day by 2070. That amount of water was based on a Dutch Shell plan that required electrical generation (construction of 12 power plants) to fuel its energy production.

Such an operation would be huge; it would require the construction of power lines, pipelines, roads, additional housing and railroads, resulting in an unrecognizable Western Slope, Trainor said.

After the initial report was published, the commercial oil shale industry said the study’s water estimate was too high. The roundtables’ energy subcommittee agreed to reëxamine its estimated water demands from oil shale development — this time with industry sharing more of their information.

Phase two of the report showed a dramatically reduced water estimate of 120,000 acre-feet.

The report identified three water projects in the White River Basin that could meet an annual energy industry demand of 110,000 acre feet of water. Most years, the Colorado River could meet an additional demand of 10,000 acre feet,

The state projects a future water gap of between 600,000 and a million acre feet of water as the number of water users increase. Other demands for water — including municipality needs — would likely target agriculture, Trainor said. Small allocations from thousands of farmers could potentially be affected.

Policy makers are urging conservation before taking water from agriculture, Trainor added.

Read report: Water and oil shale don’t mix

By David O. Williams Written and published on Tuesday, December 02, 2008

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Possible contamination of drinking water from fracking operations

Can fracking operations contaminate drinking water? Findings of recent geological studies generate many disputes on the safety claims of the hydraulic fracturing industry.

Source: The Green Optimistic / by Maria Reyes on July 13, 2012

Hydraulic fracturing involves directing pressurized fluid onto deep shale of rocks to break them open in order to release the trapped methane gas inside. Geologists guauuuurantee this process will not contaminate the shallow aquifers that supply drinking water because there are several kilometers of rock that separates the fracking sites from the aquifers.

Avner Vengosh, from Duke University, says there is danger from another source. This source is a possible methane leak that poses a grave explosion risk.

Last year, his team claimed that drinking wells in Pennsylvania were contaminated with methane, possibly from nearby fracking operations. These claims were loudly criticized.

However, Vengosh reports new evidence of possible water contamination. Some 40 of 158 Pennsylvania aquifers analyzed by his team contained unusually high levels of salt.

These aquifers were contaminated with brine coming from salt aquifers at the same depth as fracking sites. Cracks in the rocks could have allowed the brine to travel hundreds of meters upwards. Methane gas could potentially travel the same way.

Mike Stephenson of the British Geological Survey says this process could take millions of years and does not present a serious problem.

Vengosh asserts, however, that the brine must be travelling upwards quite rapidly else the Pennsylvania heavy rainfall would wash it out of the shallow aquifers. He further asserts that a gas could move faster.

Richard Davies of Durham University proposes more possible ways for fracking to cause gas leaks. Boreholes that were not properly sealed can result to gas leaks. This could explain what happened in Dimock Pennsylvania, where residents are suing Calbot Oil & Gas Corporations for contaminating their drinking water. However, Calbot asserts that their test shows no water contamination in the area.

Davies argues that around 184,000 wells were drilled in Pennsylvania before records were kept. The locations of these wells are not known. If somebody operates near one of these sites, it could cause a gas leak.

A commercially funded study last December claimed that methane discovered in Pennsylvania aquifers had a different chemical signature from those released in the shale from hydraulic fracturing.

Source: The Green Optimistic (http://s.tt/1hKq0)

Fracking – Injection wells -An unseen leak, then boom.

Firefighters continue to watch the flame go at what used to be Woody’s Appliance store in downtown Hutchinson on January 21, 2001 four days after an explosion rocked the city. (Photo by Fernando Salazar)

Three miles away, a geyser of gas shot out of the earth, sending mud and rocks 30 feet into the air. Elsewhere, the ground popped open like the rotten hull of a boat, spraying brown briny water or catching fire.

The next morning, just when the earth seemed to recover its temper, a new plume of gas and water shot through the floor of a mobile home, killing two people. Hundreds of other Hutchinson residents were evacuated from their homes, many for months.

The mysterious disaster claimed national headlines, but there was little public discussion of the fact that it was caused by problems with underground injection wells.

Among a small community of geologists and regulators, however, the explosions in Hutchinson — which ranked among the worst injection-related accidents in history — exposed fundamental risks of underground leakage and prompted fresh doubts about the geological science of injection itself.

Geologists in Hutchinson determined that the eruptions had sprung from an underground gas storage field seven miles away. For years, a local utility had injected natural gas between 600 and 900 feet down into old salt caverns, storing it in a rock layer believed to be airtight so that it could later be pumped back out and sold. The gas had leaked out and migrated miles into abandoned injection wells once used to mine salt, then shot to the surface.

“It was an unusual event,” said Bill Bryson, a member of the Kansas Geological Survey and a former head of the Kansas Corporation Commission’s oil and gas conservation division. “Nobody really had a feeling that if there was a leak, it would travel seven miles and hit wells that were unknown.”

Though regulated under different laws than waste injection wells, gas storage wells operate under similar principles and assumptions: that deeply buried layers of rock will prevent injected substances from leaking into water supplies or back to the surface.

In this case the injected material had done everything that scientists usually describe as impossible: It migrated over a large distance, travelled upward through rock, reached the open air and then blew up.

The case, described as “a continuing series of geologic surprises and unexpected complexities” by the Kansas Geological Survey, flummoxed some of the leading injection experts in the world.

Perhaps more troubling was that some of the officials assumed to be most knowledgeable about injection wells and the risks of underground storage seemed oblivious to the conditions that led to the accident.

“The existence of those widespread formations and old salt-solution wells was unknown to the operators of the storage facility, the Kansas State Geologic Survey, city personnel, and its inhabitants,” noted a 2006 paper authored by Sally Benson, a leading geoscientist at Lawrence Berkeley Lab’s earth sciences division, and others. “It is still not clear how long the leakage occurred.”

Bryson agrees that officials should have known more about the number of abandoned wells in the area, but he says that otherwise Kansas’ regulations worked as intended.

The cause of the accident was identified because workers were diligently monitoring pressure changes in the gas injection well, as they are required to do. Once in a while, accidents are going to happen, he said.

“How far do you go to make sure that nothing will ever happen?” he said. “Lets face it: Something is going to go wrong… states have to be trusted enough to let us deal with that.”

Facts: Ten scariest chemicals used in hydraulic fracking

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

You can read more: http://www.businessinsider.com/scary-chemicals-used-in-hydraulic-fracking-2012-3#ixzz1uJ18CTxD

Methanol

Flickr/prizepony
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

Flcikr/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

A 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.)

Lead

Flickr/matthileo
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

Flickr/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.

Naphthalene

Flickr/CraftyGoat
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

Flickr/yetanotherdave
A carcinogen found in lead-acid 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 one-half ounce.
 
 
 

Crystalline silica

Source: 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.
 
 
 
 

Formaldehyde

Flickr/Stadtkatze
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

Flickr/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 service companies were unable to identify these ‘proprietary’ chemicals,suggesting that the companies are injecting fluids containing chemicals that they themselves cannot identify.”

 

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Animated fracking news-Slickwater fracking.

This is the technological breakthrough that’s making people wildly bullish on America

Written by Rob Wile @ Business Insider/ Follow Rob Wile on Twitter.* Copyright © 2012 Business Insider, Inc.

This weekend, we told the story of three bears who are all bullish on America for one reason: Domestic oil and natural gas. In particular, Hugh Hendry fund manager for Scottish group Eclectica Asset Management, cited “the momentous nature of recent advances in shale oil and gas extraction.”

So what are these great breakthroughs?

As it turns out, the three great advances in shale resource extraction occurred more than a decade ago, according to Dan Steward, a geologist with Republic Energy and a former Vice President of Mitchell Energy.

The first was horizontal well drilling, which infinitely expanded the potential uses of fracking (which has actually been around since the 1949*). Here’s an animation showing exactly what that looks like:

The first commercially viable horizontal drills had already been executed in the 1980s.

But it was not until the late ’90s that mapping technology was created that could determine where fracking would prove most successful.

Microseismic technology (which were originally used to detect seismic activity around mines) involves lowering detectors into a listening well near a fracked well.

Once the well has been drilled, the seismic devices pick up the noise of where the rocks are breaking, and triangulates the sounds to map out the rest of the play.

Here’s an equally nifty animation that demonstrates microseismic mapping.

The final development was the advent of slickwater fracking, the technique now known for being so cheap, yet so controversial.

Slickwater fracks involve adding chemicals known as “friction reducers” to water to allow for more efficient gas extraction.According to Halliburton and Forest Oil Corp, slickwater fracks allow fluid to be pumped down the well-bore as fast as 100 barrels per minute. Without using slickwater the top speed of pumping is around 60 bbl/min. It also enables extraction in highly pressurized, deeper shales.

In 1997, Mitchell Energy executed the first slickwater frack (.pdf). Steward says it cut down the cost of drilling a well from $375,000 to $85,000.

The ensuing “natural gas revolution” has been more the result of revision after revision of potentially recoverable resources. For example, in 1999, a study estimated 8.4 trillion cubic feet of natural gas were recoverable in the mid-Atlantic Marcellus Shale. By 2006, that had been revised upward to 31.4. (Some some now argue we have reached a tipping point where has caused recoverability estimates to be revised back downward.)

Here’s how that evolution has played out, according to data from Drilling Info:

J. David Hughes

So the next time you read something about new innovations in shale extraction, remember this timeline, from Steward:

“By the year 2000, Mitchell Energy had proven shale as a workable and viable. The energy industry recognized it, but financial markets didn’t recognize until 2002, and politicians only realized it in 2006.”

It is these decade-old breakthroughs that have resulted in those cheap prices you keep hearing about.

tradingeconomics.com

*Update June 6, 2012: The article originally stated fracking has been around since the 1920s — this should have referred to slanted drilling — a precursor to horizontal drilling — first recorded in 1929. Read more @ Business Insider, Inc

Further reading:

Slickwater / Fracking historical perspective

By Theodore Gilliland, 04/19/2011
Horizontal drilling, hydraulic fracturing, and shale gas have received a ton of press lately. But what impacts do these unconventional techniques have on energy markets?
Neither hydraulic fracturing (fracking) nor horizontal drilling are new technologies—the first horizontal well was drilled in 1929 and Halliburton developed fracking in 1949.Shale gas extraction is even older—the first commercial well was drilled in 1821. However, when horizontal drilling and fracking were combined to drill in Texas’ Barnett Shale region in 2003, a natural gas boom was born. In the last decade, shale gas production has increased 14-fold.

Exhibit 1: Historical Milestones in Unconventional Gas Drilling

Definitions by Wikimarcellus

Slickwater fracking

Slickwater or slick water fracturing is a method or system of hydro-fracturing which involves adding chemicals to water to increase the fluid flow. Fluid can be pumped down the well-bore as fast as 100 bbl/min. to fracture the shale. Without using slickwater the top speed of pumping is around 60 bbl/min.

The process reportedly involves injecting friction reducers, usually a a polyacrylamide. Biocides, surfactants and scale inhibitors can also be in the fluid. Friction reducers speed the mixture. Biocides such as bromine prevent organisms from clogging the fissures and sliming things up downhole. Surfactants keep the sand suspended. Methanol and naphthalene can be used for biocides. Hydrochloric acid and ethylene glycol may be utilized as scale inhibitors. Butanol and ethylene glycol monobutyl ether (2-BE) are used in surfactants. Slickwater typically uses more water than earlier fracturing methods–between one and five million gallons per fracing operation.

Other chemical compounds sometimes used include benzene, chromium and a host of others. Many of these are known to be toxic and have raised widespread concern about potential water contamination. This is especially true when the wells recieving slickwater hydro-fracturing are located near aquifers that are being tapped into for local drinking water. However, reports of actual drinking water contamination appear either very scarce or else non-existent. Hydro-fracturing activity is heavily regulated by state agencies.

In summary, slickwater is a water-based fluid and proppant combination that has low-viscosity. Slickwater fracturing was first used in the Barnett shale. Mitchell Energy introduced the very first slickwater frac that utilized 800,000 gal. of water and 200,000 lbs. of sand as proppant. It is typically used in highly-pressurized, deeper shales, while fracturing fluids using nitrogen foam are more common in more shallow shales and those that have lower reservoir pressure.

What is proppant?

Proppant is porous material such as sand or ceramic beads that are used to prevent newly created fissures and fractures in the shale rock from closing up once it has been hydro-fractured.

A typical hydro-fractured well uses between 300,000 and 500,000 lbs. of proppant.

The objective of hydro-fracturing is to enhance the deliverability of trapped gas by making pathways for the flow of natural gas and other hydrocarbons from the shale reservoir to the wellbore. Two chief factors that influence the flow of gas are permeability and proppant.

Stokes’ law can be used to define four variables that affect proppant settling velocity in a column of water:

1. fluid specific gravity
2. fluid viscosity
3. proppant size
4. proppant specific gravity

The cost of hydro-fracturing can be minimized by by reducing frac fluid viscosity. According to Stokes law, reducing the particle (proppant) size in half cuts the settling rate by a factor of four. However, particle size is also proportional to the conductivity of a proppant pack. Hence, in designing a fracing plan these factors must be weighed against each other in order to optimize the flow of gas from the shale reservoir.

Although naturally occurring sand is frequently utilized as proppant, specially engineered man-made proppants can be used too such as resin-coated sand or high-strength ceramic materials like sintered bauxite. Materials are carefully selected for size and sphericity to provide the most efficient conduit for production of gas and other hydrocarbons from reservoir to wellbore.

There are three main types of proppant that are in use in hydro-fracturing. Listed in order of their unit cost, these include:

• sand
• sand coated with resin
• ceramic proppant

The higher initial cost of ceramic proppant over sand may be justified by higher returns on investment in terms of greater well production rates and total overall recovery of oil and gas from the well. Higher production rates result from the greater strength of ceramic proppant and its more uniform shape and size.

Production engineers use fracture design models as a guide to optimizing fracturing by comparing treatment size versus fracture half-length. The purpose is to design a fracture stimulation plan that optimizes productivity. The lower the permeability of a reservoir the more fracture length determines the effectiveness of the stimulation. However, unless the fractures can be sustained unpropped, that is, unless the fracture length or height created by hydro-fracturing has residual conductivity without propping, it is a waste of fluid. That can reduce the return on investment of hydro-fracturing a well or even turn it into a loss situation.

Facts: Ten scariest chemicals used in hydraulic fracking

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

You can read more: http://www.businessinsider.com/scary-chemicals-used-in-hydraulic-fracking-2012-3#ixzz1uJ18CTxD

Methanol

Flickr/prizepony
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

Flcikr/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

A 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.)

Lead

Flickr/matthileo
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

Flickr/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.

Naphthalene

Flickr/CraftyGoat
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

Flickr/yetanotherdave
A carcinogen found in lead-acid 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 one-half ounce.
 
 
 

Crystalline silica

Source: 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.
 
 
 
 

Formaldehyde

Flickr/Stadtkatze
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

Flickr/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 service companies were unable to identify these ‘proprietary’ chemicals,suggesting that the companies are injecting fluids containing chemicals that they themselves cannot identify.”

 

Facts: List of chemicals now known to be used in fracking

 
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.

Back To Top

Chemical Name	CAS	Chemical Purpose	Product Function
Hydrochloric Acid	007647-01-0	Helps dissolve minerals and initiate cracks in the rock	Acid
Glutaraldehyde	000111-30-8	Eliminates bacteria in the water that produces corrosive by-products	Biocide
Quaternary Ammonium Chloride	012125-02-9	Eliminates bacteria in the water that produces corrosive by-products	Biocide
Quaternary Ammonium Chloride	061789-71-1	Eliminates bacteria in the water that produces corrosive by-products	Biocide
Tetrakis Hydroxymethyl-Phosphonium Sulfate	055566-30-8	Eliminates bacteria in the water that produces corrosive by-products	Biocide
Ammonium Persulfate	007727-54-0	Allows a delayed break down of the gel	Breaker
Sodium Chloride	007647-14-5	Product Stabilizer	Breaker
Magnesium Peroxide	014452-57-4	Allows a delayed break down the gel	Breaker
Magnesium Oxide	001309-48-4	Allows a delayed break down the gel	Breaker
Calcium Chloride	010043-52-4	Product Stabilizer	Breaker
Choline Chloride	000067-48-1	Prevents clays from swelling or shifting	Clay Stabilizer
Tetramethyl ammonium chloride	000075-57-0	Prevents clays from swelling or shifting	Clay Stabilizer
Sodium Chloride	007647-14-5	Prevents clays from swelling or shifting	Clay Stabilizer
Isopropanol	000067-63-0	Product stabilizer and / or winterizing agent	Corrosion Inhibitor
Methanol	000067-56-1	Product stabilizer and / or winterizing agent	Corrosion Inhibitor
Formic Acid	000064-18-6	Prevents the corrosion of the pipe	Corrosion Inhibitor
Acetaldehyde	000075-07-0	Prevents the corrosion of the pipe	Corrosion Inhibitor
Petroleum Distillate	064741-85-1	Carrier fluid for borate or zirconate crosslinker	Crosslinker
Hydrotreated Light Petroleum Distillate	064742-47-8	Carrier fluid for borate or zirconate crosslinker	Crosslinker
Potassium Metaborate	013709-94-9	Maintains fluid viscosity as temperature increases	Crosslinker
Triethanolamine Zirconate	101033-44-7	Maintains fluid viscosity as temperature increases	Crosslinker
Sodium Tetraborate	001303-96-4	Maintains fluid viscosity as temperature increases	Crosslinker
Boric Acid	001333-73-9	Maintains fluid viscosity as temperature increases	Crosslinker
Zirconium Complex	113184-20-6	Maintains fluid viscosity as temperature increases	Crosslinker
Borate Salts	N/A	Maintains fluid viscosity as temperature increases	Crosslinker
Ethylene Glycol	000107-21-1	Product stabilizer and / or winterizing agent.	Crosslinker
Methanol	000067-56-1	Product stabilizer and / or winterizing agent.	Crosslinker
Polyacrylamide	009003-05-8	“Slicks” the water to minimize friction	Friction Reducer
Petroleum Distillate	064741-85-1	Carrier fluid for polyacrylamide friction reducer	Friction Reducer
Hydrotreated Light Petroleum Distillate	064742-47-8	Carrier fluid for polyacrylamide friction reducer	Friction Reducer
Methanol	000067-56-1	Product stabilizer and / or winterizing agent.	Friction Reducer
Ethylene Glycol	000107-21-1	Product stabilizer and / or winterizing agent.	Friction Reducer
Guar Gum	009000-30-0	Thickens the water in order to suspend the sand	Gelling Agent
Petroleum Distillate	064741-85-1	Carrier fluid for guar gum in liquid gels	Gelling Agent
Hydrotreated Light Petroleum Distillate	064742-47-8	Carrier fluid for guar gum in liquid gels	Gelling Agent
Methanol	000067-56-1	Product stabilizer and / or winterizing agent.	Gelling Agent
Polysaccharide Blend	068130-15-4	Thickens the water in order to suspend the sand	Gelling Agent
Ethylene Glycol	000107-21-1	Product stabilizer and / or winterizing agent.	Gelling Agent
Citric Acid	000077-92-9	Prevents precipitation of metal oxides	Iron Control
Acetic Acid	000064-19-7	Prevents precipitation of metal oxides	Iron Control
Thioglycolic Acid	000068-11-1	Prevents precipitation of metal oxides	Iron Control
Sodium Erythorbate	006381-77-7	Prevents precipitation of metal oxides	Iron Control
Lauryl Sulfate	000151-21-3	Used to prevent the formation of emulsions in the fracture fluid	Non-Emulsifier
Isopropanol	000067-63-0	Product stabilizer and / or winterizing agent.	Non-Emulsifier
Ethylene Glycol	000107-21-1	Product stabilizer and / or winterizing agent.	Non-Emulsifier
Sodium Hydroxide	001310-73-2	Adjusts the pH of fluid to maintains the effectiveness of other components, such as crosslinkers	pH Adjusting Agent
Potassium Hydroxide	001310-58-3	Adjusts the pH of fluid to maintains the effectiveness of other components, such as crosslinkers	pH Adjusting Agent
Acetic Acid	000064-19-7	Adjusts the pH of fluid to maintains the effectiveness of other components, such as crosslinkers	pH Adjusting Agent
Sodium Carbonate	000497-19-8	Adjusts the pH of fluid to maintains the effectiveness of other components, such as crosslinkers	pH Adjusting Agent
Potassium Carbonate	000584-08-7	Adjusts the pH of fluid to maintains the effectiveness of other components, such as crosslinkers	pH Adjusting Agent
Copolymer of Acrylamide and Sodium Acrylate	025987-30-8	Prevents scale deposits in the pipe	Scale Inhibitor
Sodium Polycarboxylate	N/A	Prevents scale deposits in the pipe	Scale Inhibitor
Phosphonic Acid Salt	N/A	Prevents scale deposits in the pipe	Scale Inhibitor
Lauryl Sulfate	000151-21-3	Used to increase the viscosity of the fracture fluid	Surfactant
Ethanol	000064-17-5	Product stabilizer and / or winterizing agent.	Surfactant
Naphthalene	000091-20-3	Carrier fluid for the active surfactant ingredients	Surfactant
Methanol	000067-56-1	Product stabilizer and / or winterizing agent.	Surfactant
Isopropyl Alcohol	000067-63-0	Product stabilizer and / or winterizing agent.	Surfactant
2-Butoxyethanol	000111-76-2	Product stabilizer	Surfactant

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New Fracking Research:

Disputes a fundamental industry claim.

Michael Kelley | Jul. 10, 2012, 11:04 AM | 1,509 | 16

A primary claim of the hydraulic fracking industry is that deeply buried rock layers will always seal and contain the dangerous chemicals that are injected thousands of feet underground.

But a new study released in the Proceedings of the National Academy of Sciences concluded that fracking for natural gas under Marcellus Shale in Pennsylvania may lead to harmful gas or liquids flowing upward and contaminating drinking-water supplies.

The study found that salty, mineral-rich fluids deep beneath Pennsylvania’s natural gas fields are seeping upward thousands of feet into drinking water supplies. Although it found no evidence of fracking chemicals doing the same, the findings suggest that there are paths that would let hazardous gas or fluids flow up after drilling:

“The biggest implication is the apparent presence of connections from deep underground to the surface,” Robert Jackson, a biology professor at Duke University and one of the study’s authors, told ProPublica. “It’s a suggestion based on good evidence that there are places that may be more at risk.”

The study supplements another recent study that used computer modeling to predict how fracking fluids would move over time and found that they could migrate toward drinking water supplies far more quickly than experts have previously predicted.

Critics of the study said that it doesn’t prove that fracking fluids have traveled up to aquifers and argue that gas and water from fracking will flow into the well and not up through fissures that may exist.

Hydraulic fracking is a process in which water, sand and chemicals are injected into deep shale formations to crack the rock and free trapped gas.

The natural gas in Marcellus Shale, which stretches from New York to Tennessee and may hold enough gas to supply the U.S. for three years, has led to permits for more than 11,000 wells. The practice had been an economic boon for Pennsylvania and has helped set decade-low natural gas prices nationwide.

But there is growing evidence of the hazards of fracking. Last year some of the same Duke researchers published findings that methane contamination of drinking water accompanied fracking.

Researchers at the Colorado School of Public Health recently found that air pollution caused by hydraulic fracturing raises the risk of acute and chronic health problems for those living near natural gas drilling sites.

The oil and gas industry doesn’t have to publicly disclose most of the chemicals it pumps into the ground, but we know the list contains several carcinogens. Even landfills have begun to reject fracking fluid waste.

The powers that be may know the risk of those chemicals being known as there is a new “doctor gag rule” law in Pennsylvania that provides doctors access to trade-secret chemicals used in natural gas drilling so that they can treat people who have been made sick but prohibits doctors from sharing that information with anyone, even other doctors.

No matter what science concludes, there is no doubt that the fracking industry has a powerful lobby to protect its interests. Read more:

Even Landfills Don't Want Fracking Fluid Waste

Rob Wile | Jun. 18, 2012, 1:00 PM |469 | Flickr/eggroll

o Kansas landfills near a fracking site have declined to take in the drilling fluid waste, citing a blanket ban on liquids that cannot be contained.

Gale Rose from The Pratt Tribune in Pratt, KS writes the Pratt County landfill rejected an unnamed drilling company's proposal after a nearby landfill with more advance control precautions, like a protective liner, also said no.

"If they (nearby Reno County) have concerns about it I definitely have concerns about it,” Dean Staab, director of Environmental Services for Pratt County, told Rose.

The fluid is actually a mud, Rose reports. If it were to be delivered dry, the landfills would consider storing it, she said.

Meanwhile New Jersey last week voted to ban the transport of fracking wastewater into the state.

Assemblywoman Valerie Vainieri Huttle, a Democrat who's one of the measure's sponsors, said in a statement that allowing fracking waste to come into New Jersey is too risky for public health.

"Given the relative newness of this practice, the total damage inflicted during and after drilling is still unknown," Huttle said. "But the evidence is already mounting that fracking comes with serious environmental consequences."Read more: [/toggle]

Geochemical evidence for possible natural migration

Geochemical evidence for possible natural migration of Marcellus Formation brine to shallow aquifers in Pennsylvania

1. Nathaniel R. Warner^a,
2. Robert B. Jackson^a,^b,
3. Thomas H. Darrah^a,
4. Stephen G. Osborn^c,
5. Adrian Down^b,
6. Kaiguang Zhao^b,
7. Alissa White^a, and
8. Avner Vengosh^a,¹

Author Affiliations

1. ^aDivision of Earth and Ocean Sciences, Nicholas School of the Environment, Duke University, Durham, NC 27708;

2. ^bCenter on Global Change, Nicholas School of the Environment, Duke University, Durham, NC 27708; and

3. ^cGeological Sciences Department, California State Polytechnic University, Pomona, CA 91768

1. Edited by Karl K. Turekian, Yale University, North Haven, CT, and approved May 10, 2012 (received for review January 5, 2012)

Abstract

The debate surrounding the safety of shale gas development in the Appalachian Basin has generated increased awareness of drinking water quality in rural communities. Concerns include the potential for migration of stray gas, metal-rich formation brines, and hydraulic fracturing and/or flowback fluids to drinking water aquifers. A critical question common to these environmental risks is the hydraulic connectivity between the shale gas formations and the overlying shallow drinking water aquifers. We present geochemical evidence from northeastern Pennsylvania showing that pathways, unrelated to recent drilling activities, exist in some locations between deep underlying formations and shallow drinking water aquifers. Integration of chemical data (Br, Cl, Na, Ba, Sr, and Li) and isotopic ratios (⁸⁷Sr/⁸⁶Sr, ²H/H, ¹⁸O/¹⁶O, and ²²⁸Ra/²²⁶Ra) from this and previous studies in 426 shallow groundwater samples and 83 northern Appalachian brine samples suggest that mixing relationships between shallow ground water and a deep formation brine causes groundwater salinization in some locations. The strong geochemical fingerprint in the salinized (Cl > 20 mg/L) groundwater sampled from the Alluvium, Catskill, and Lock Haven aquifers suggests possible migration of Marcellus brine through naturally occurring pathways. The occurrences of saline water do not correlate with the location of shale-gas wells and are consistent with reported data before rapid shale-gas development in the region; however, the presence of these fluids suggests conductive pathways and specific geostructural and/or hydrodynamic regimes in northeastern Pennsylvania that are at increased risk for contamination of shallow drinking water resources, particularly by fugitive gases, because of natural hydraulic connections to deeper formations.

• formation water
• isotopes
• Marcellus Shale
• water chemistry

Footnotes

• To whom correspondence should be addressed. E-mail: vengosh@duke.edu.

• Author contributions: N.R.W., R.B.J., and A.V. designed research; N.R.W., R.B.J., S.G.O., A.D., A.W., and A.V. performed research; N.R.W., R.B.J., T.H.D., K.Z., and A.V. analyzed data; and N.R.W., R.B.J., T.H.D., and A.V. wrote the paper.
• The authors declare no conflict of interest.

New twist in fracking debate

upi.com/Business DURHAM, N.C., July 10 (UPI) -- A U.S. study found there may be some natural processes occurring with the contamination of water supplies in a shale play in Pennsylvania.

A study conducted by researchers at Duke University and California State Polytechnic University found natural processes were leading to some levels of contamination in drinking water wells and aquifers in northeastern Pennsylvania.

Pennsylvania hosts a portion of the Marcellus shale play, one of the largest sources of natural gas in the United States.

Shale natural gas extraction is controversial. There are concerns that some of the waste associated with the extraction methods could find their way into drinking water supplies.

Scientists found that salty water laced with certain chemicals like barium or compounds like methane were from natural pathways of contamination.

Robert Jackson, an ecologist at Duke University and one of the report's authors, said the mineral-rich fluids are seeping upwards through the shale layer.

He told National Public Radio scientists were working to figure out what was coming from shale gas extraction and what was from natural processes.

"They are a possible conduit for movement of salts or fracking chemicals or even gases up to the surface," he said. "But we just don't know how likely that is."

The study was published in the journal Proceedings of the National Academy of Sciences.

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• Obama aide: 'Fracking' rules on track
• NWF reviews Ohio, Mich. fracking laws

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Question: Can fracking be cleaned up?

Fracking site: Trucks at a well in Pennsylvania pump high-pressure fracking fluid down the well to free natural gas from the shale formation far below the surface.Les Stone/ Corbis

The International Energy Agency says yes, but it will take tougher regulations that force producers to apply the latest technologies.

Tuesday, June 5, 2012/By Kevin Bullis

Fracking, aka hydraulic fracturing, a process for freeing natural gas locked in shale deposits, has caused a boom in natural-gas production in the United States. But some experts worry that the practice results in contaminated drinking water and the release of methane, prompting some localities to limit shale-gas production.

A new analysis by the International Energy Agency says technologies exist—or are in development—that could largely address these concerns. If they’re adopted, fracking could be more widely accepted by governments around the world, leading to lower greenhouse-gas emissions and lower energy prices. It they’re not, governments could balk, and coal would maintain its dominant place in electricity generation.

The most well-known issue associated with fracking is concern over water use and contamination. Fracking consumes large amounts of water; roughly 20 million liters under high pressure are sent down each well to create the fractures in the rock that free the natural gas. That water use is a huge concern in places such as Texas and some areas of China that have large shale-gas resources and are prone to droughts.

Disposal of that wastewater is another concern. Fracking also has the potential to contaminate drinking water supplies and increase air pollution. And there are concerns that it could actually increase greenhouse-gas emissions due to methane leaks.

But the IEA report concludes that fracking, like many other practices in industries that involve hazardous chemicals, can be made relatively safe with regulation. The IEA estimates that the measures needed to make fracking safer would add about 7 percent to the cost of an average well.

Significant levels of methane, the main component of natural gas, have been found in drinking-water supplies near some fracking sites. Some environmentalists have suggested that the fracking process, which creates fractures in shale, could create a path for natural gas and other chemicals to reach aquifers and mix with drinking water.

But according to the IEA report, that doesn’t seem to be the problem in most cases. Fracking usually takes place hundreds of meters below aquifers, and it’s easy to stop the propagation of fractures. Cracking the rock requires high pressures. Stop applying the pressure, and the rock fracturing stops. However, some fracking sites are relatively near to the level of drinking water, and the IEA suggests it might make sense to ban the procedure at such locations.

The IEA says the contaminated water is most likely the result of producers building substandard natural-gas wells, which are lined with metal casings and cement to keep the natural gas from contaminating aquifers. But in some cases, producers have done a poor job of cementing, allowing channels for natural gas to form. “Whenever there was a gas leakage, it came out because the cement was not well done,” says Franz-Josef Ulm, a civil and environmental engineering professor at MIT. That problem could be solved by cementing properly and then carefully monitoring the well’s integrity. “When it comes to cementing, the solutions are out there. The question is whether they are being applied,” Ulm says.

New technology could greatly reduce the amount of pressure needed for fracking, making it far easier to build safe wells, Ulm says. Researchers are learning that shale is particularly fracture-resistant because of the presence of a small amount of organic material that binds together inorganic particles. Targeting these materials by applying a special solvent could weaken the shale and make it far easier to free the natural gas.

There are also opportunities to reduce water use by using fluids other than water—such as propane (which brings its own environmental challenges)—or mixing carbon dioxide or nitrogen with water to create foams. Eventually it may be possible to mix small amounts of water with solid particles designed to easily flow, Ulm says.

Another contamination fear involves the chemicals that fracking companies add to the water. The biggest concern isn’t the chemicals once they’re mixed with the water, since they’re so dilute, but rather the handling of the chemicals in concentrated form. Spills on the surface could soak into the ground and contaminate drinking water. The solution is to line the area where chemicals are handled with plastic and monitor any leaks. Researchers are also developing less-toxic chemicals, or techniques to eliminate the need for them.

Yet even if these chemicals can be dealt with, wastewater remains a challenge. The water that flows back to the surface is contaminated not only with the chemicals originally mixed in at the surface, but also with chemicals, heavy metals, and, in some cases, naturally occurring radioactive materials from deep underground.

As the water returns to the surface, natural gas and other hydrocarbons that were released by the fracking come with it. In many cases, that gas is allowed to escape into the atmosphere until the water stops flowing. The main component of natural gas—methane—is a greenhouse gas many times more powerful than carbon dioxide, so this practice could offset any greenhouse-gas emissions reductions that would come from burning natural gas rather than coal. However, simple technology exists to capture the natural gas at this stage.

Implementing these technologies will likely require regulation. “It can’t just be counting on companies to adopt best practices, because you’ll only have a certain percentage of the well operators doing it,” says Mark Boling, president of V+ Development Solutions, which is part of Southwestern Energy, a natural-gas producer. “You have to go the rest of the way and get regulations in place so that you have a level playing field and everyone is required to do the same thing.”

If done right, those regulations could drive innovation by creating a market for new technologies. Ulm recommends caps on emissions that give companies flexibility to choose the best technology. The IEA calls for a combination of such caps, and in some cases specific technology requirements. “With such regulations, you could force innovation to be implemented at a high pace. Technology is what it will take to make shale gas a sustainable resource,” Ulm says.

Definitions From Wikipedia

Save the Water™ does not represent or endorse the definitions posted herein or reliability of any advice, opinion, statement, or other information furnished by the author. It is meant for further research by you the reader.

Hydraulic fracturing

From Wikipedia, the free encyclopedia

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“Fracking” redirects here. For the expletive, see Frak (expletive).

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Hydraulic fracturing
Process type	Mechanical
Industrial sector(s)	Mining
Main technologies or sub-processes	Fluid pressure
Product(s)	Natural gas Petroleum
Inventor	Floyd Farris; J.B. Clark (Stanolind Oil and Gas Corporation)
Year of invention	1947

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 rocks. Induced hydraulic fracturing or hydrofracking, commonly known as fracking, is a technique used to release petroleum, natural gas (including shale gas, tight 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 highly-pressurized 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.

Geology

Mechanics

Fracturing in rocks at depth is suppressed by the confining 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 vein-filled fractures, their orientations can be used to infer past stress states.^[9]

Veins

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 ‘crack-seal’ 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 long-lasting 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 fluid-filled fractures during earthquakes. This process is referred to as ‘seismic pumping’.^[11]

Dikes

High-level minor intrusions such as dikes propagate through the crust in the form of fluid-filled 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]

History

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 gas-bearing 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 public-private hydro-fracturing 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.

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

Predicts frack toxins can migrate to aquifers within years

Save the Water™ does not represent or endorse the postings herein or reliability of any advice, opinion, statement, or other information furnished by the author.

Study shows more immediate drilling danger

NEW YORK — A new study has raised fresh concerns about the safety of gas drilling in the Marcellus Shale, concluding that fracking chemicals injected into the ground could migrate toward drinking water supplies far more quickly than experts have previously predicted, the investigative news site, ProPublica.com reports.

More than 5,000 wells were drilled in the Marcellus between mid-2009 and mid-2010, according to the study, which was published in the journal Ground Water two weeks ago. Operators inject up to 4 million gallons of fluid, under more than 10,000 pounds of pressure, to drill and frack each well.

Scientists have theorized that impermeable layers of rock would keep the fluid, which contains benzene and other dangerous chemicals, safely locked nearly a mile below water supplies. This view of the earth’s underground geology is a cornerstone of the industry’s argument that fracking poses minimal threats to the environment.

But the study, using computer modeling, concluded that natural faults and fractures in the Marcellus, exacerbated by the effects of fracking itself, could allow chemicals to reach the surface in as little as “just a few years.”

“Simply put, are not impermeable,” said the study’s author, Tom Myers, an independent hydrogeologist whose clients include the federal government and environmental groups.

“The Marcellus shale is being fracked into a very high permeability,” he said. “Fluids could move from most any injection process.”

The research for the study was paid for by Catskill Mountainkeeper and the Park Foundation, two upstate New York organizations that have opposed gas drilling and fracking in the Marcellus.

Much of the debate about the environmental risks of gas drilling has centered on the risk that spills could pollute surface water or that structural failures would cause wells to leak.

Though some scientists believed it was possible for fracking to contaminate underground water supplies, those risks have been considered secondary. The study in Ground Water is the first peer-reviewed research evaluating this possibility.

The study did not use sampling or case histories to assess contamination risks. Rather, it used software and computer modeling to predict how fracking fluids would move over time. The simulations sought to account for the natural fractures and faults in the underground rock formations and the effects of fracking.

The models predict that fracking will dramatically speed up the movement of chemicals injected into the ground. Fluids traveled distances within 100 years that would take tens of thousands of years under natural conditions. And when the models factored in the Marcellus’ natural faults and fractures, fluids could move 10 times as fast as that.

Where man-made fractures intersect with natural faults, or break out of the Marcellus layer into the stone layer above it, the study found, “contaminants could reach the surface areas in tens of years, or less.”

The study also concluded that the force that fracking exerts does not immediately let up when the process ends. It can take nearly a year to ease.

As a result, chemicals left underground are still being pushed away from the drill site long after drilling is finished. It can take five or six years before the natural balance of pressure in the underground system is fully restored, the study found.

Myers’ research focused exclusively on the Marcellus, but he said his findings may have broader relevance. Many regions where oil and gas is being drilled have more permeable underground environments than the one he analyzed, he said.

“One would have to say that the possible travel times for a similar thing in Arkansas or Northeast Texas is probably faster than what I’ve come up with,” Myers said.

Ground Water is the journal of the National Ground Water Association, a non-profit group that represents scientists, engineers and businesses in the groundwater industry.

Several scientists called Myers’ approach unsophisticated and said that the assumptions he used for his models didn’t reflect what they knew about the geology of the Marcellus Shale. If fluids could flow as quickly as Myers asserts, said Terry Engelder, a professor of geosciences at Penn State University who has been a proponent of shale development, fracking wouldn’t be necessary to open up the gas deposits.

“This would be a huge fracture porosity,” Engelder said. “So I read this and I say, ‘Golly, does this guy really understand anything about what these shales look like?’ The concern then arises from using a model rather than observations.”

Myers likened the shale to a cracked window, saying that samples showing it didn’t contain fractures were small in size and were akin to only examining an intact section of glass, while a broader, scaled out view would capture the faults and fractures that could leak.

Both scientists agreed that direct evidence of fluid migration is needed, but little sampling has been done to analyze where fracking fluids go after being injected underground.

Myers says monitoring systems could be installed around gas well sites to measure for changes in water quality, a measure required for some gold mines, for example. Until that happens, Myers said, theoretical modeling has to substitute for hard data.

“We were trying to use the basic concepts of groundwater and hydrology and geology and say can this happen?” he said. “And that had basically never been done.”

— Abrahm Lustgarten
Editors note: View stories in the ProPublica series at www.propublica.org/series/fracking.

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• The American Indian Environmental Office (AIEO) at EPA is responsible for overseeing many environmental programs that benefit Tribal populations.
• Native American Water Association
• The Indian Health Service also has programs that promote public health.

Tribal PWSS & UIC Programs

Tribal PWSS & UIC Programs

 

History of the Tribal PWSS and UIC Programs

In 1974 the United States Congress passed legislation, the Safe Drinking Water Act (SDWA), designed to maintain and improve the quality of the nation’s drinking waters. Two major regulatory programs were created in the SDWA: the Public Water System Supervision (PWSS) and the Underground Injection Control (UIC) programs.

Congress authorized EPA to delegate responsibilities to states for implementing and enforcing national standards within their jurisdiction. States must apply to EPA if they want this “primacy” responsibility and must develop PWSS or UIC programs that meet national requirements. EPA is still responsible for developing national regulations, overseeing state primacy programs and implementing programs in states without primacy.

Because of their unique status, Indian tribes were not eligible to assume primacy in the original Act. Instead EPA regions were responsible for primary enforcement authority of PWSS and UIC programs on Tribal lands. This changed in 1986 when the Amendments to the SDWA added provisions that allow federally recognized tribes to assume primacy for the PWSS and UIC programs. Section 1451 (“Indian Tribes”) of SDWA authorizes the EPA to treat Indian tribes in a manner similar to states and to assign primary enforcement responsibility (primacy) to qualified tribes.

The PWSS and UIC programs are very complex and costly to operate. For many tribes (especially those that do not have a large number of public water systems or underground injection wells), the costs and resources required to achieve and maintain a regulatory program may far exceed the benefits from achieving primacy. Due to such difficulties, currently the only tribe that has sought and obtained primacy for the PWSS program is the Navajo Nation. There are a few tribes that are pursuing primacy in the PWSS and UIC programs.

Today´s Tribal Direct Implementation Program

States and tribes that do not obtain PWSS and UIC program delegation continue to be directly implemented by the EPA region in which the State or reservation is located. All EPA regions, excluding Region III (which has no federally recognized tribes), operate tribal PWSS and UIC programs to manage public water systems or underground injection wells on Indian lands.

EPA’s 1997 inventory shows that there are nearly 1000 public water systems (740 community water systems, 90 nontransient noncommunity water systems and 130 transient noncommunity water systems) that the EPA regional offices manage on Indian lands serving a population of nearly 500,000. There are also over 5,300 injection wells (one Class I well, 4,300 Class II wells, 0 Class III wells and 1,042 Class V wells) on tribal lands that are managed by regional UIC staff.

As the primary enforcement authority for tribal public water systems, EPA regions are responsible for enforcing against those systems that do not comply with federal drinking water regulations. A formal enforcement action is taken as a last measure. EPA regions dedicate a great deal of resources to provide tribes with technical assistance to help their systems or wells comply with federal standards. Regional staff visit reservations as often as possible to provide compliance assistance on site. Many Regions also fund circuit rider programs which enable other qualified persons the opportunity to provide technical assistance and training directly to tribes.

For more information on the Tribal PWSS and UIC programs, please contact your program representative.

Source water assessment and protection programs

Source Water Assessment and Protection Programs

The Safe Drinking Water Act (SDWA) Amendments of 1996 required states to develop and implement source water assessment programs (SWAPs) to analyze existing and potential threats to the quality of the public drinking water throughout the state. Using these programs, most states have completed source water assessments for every public water system — from major metropolitan areas to the smallest towns. Even schools, restaurants, and other public facilities that have wells or surface water supplies have been assessed. A source water assessment is a study and report, unique to a water system, that provides basic information about the water used to provide drinking water. States are working with local communities and public water systems to identify protection measures to address potential threats to sources of drinking water.

• Source Water Assessment page
• Source Water Regional Contacts
  

EPA publications and resources

• Source Water Assessment and Protection Programs Final Guidance (PDF) (160 pp, 486K)
  Describes the elements of an EPA-approved state Source Water Assessment Program (SWAP), as well as EPA’s recommendations for what should be included in a state Source Water Protection (SWP) Program. The document also provides an overview of how source water assessment and protection integrates with other Safe Drinking Water Act programs and efforts and how other EPA and other federal programs can assist states in developing and implementing assessment and protection programs, and vice versa.
  EPA 816-R-97-009
• Office of Inspector General Report: Source Water Assessment and Protection Programs Show Initial Promise, But Obstacles Remain (PDF) (56 pp, 625K)
• Source Water Protection Training through the Drinking Water Academy
• Delineation tools
• Potential contaminant source inventory tools
• Susceptibility determination tools
• Protection tools

Wellhead protection program

Wellhead Protection Program

The Wellhead Protection Program (WHPP) is a pollution prevention and management program used to protect underground sources of drinking water. The national WHPP was established under section 1428 of the 1986 SDWA amendments. The law specified that certain program activities, such as delineation, contaminant source inventory, contingency planning and source management, be incorporated into state WHPPs, which are approved by EPA prior to implementation. All states have EPA-approved state WHPPs. Although section 1428 applies only to states, a number of tribes are implementing the program as well.

WHPPs provided the foundation for many of the state source water assessment programs required under the 1996 SDWA amendments. Most states also use the wellhead protection program as a foundation for assessing and protecting ground water systems. State WHPPs vary greatly. For example, some states require community water systems to develop management plans, while others rely on education and technical assistance to encourage voluntary action. Other states have mandatory requirements for wellhead protection at the local level. Guidance, publications and other resources are available on state source water web sites.

EPA publications and resources

• Citizen’s Guide To Ground Water Protection (PDF) (34 pp, 2M)
• 1995-1997 Wellhead Biennial Report (PDF) (111 pp, 231K)
• Private Wells
• Septic Systems and Source Water Protection
• Locate Wellhead Protection Case Studies from Across the Country
  

Non-EPA publications and resources

• Ground Water Foundation Workshop Guide:
  An Introduction to Drinking Water Source Assessment and Protection
• U.S. Department of Agriculture: Home*A*Syst/Farm*A*Syst

State ground water protection program

State Ground Water Protection Programs

Many states have also developed programs that are focused specifically on ground water protection. Several states developed formal Comprehensive State Ground Water Protection Programs (CSGWPP), which were designed as a management tool for states to use to integrate all programs that affect ground water quality, thus allowing better decisions to be made. Although most states are no longer pursuing formal approval of a CSGW pp, virtually all states are pursuing at least some of the individual elements necessary for comprehensive ground water protection. Within EPA, the source water protection program is working with the underground storage tank program to address potential threats to ground water posed by leaking tanks.

Publications and resources

• Protecting the Nation’s Ground Water: EPA Strategy for the 1990s (PDF) (11 pp, 1M)
• State 305(b) reports
• National Water Quality Inventory, 1998 Report to Congress, Ground Water and Drinking Water Chapters
  Report that is the primary vehicle for informing Congress and the public about general water quality conditions in the Untied States.
  • Ground Water Protection Programs Chapter (PDF) (47 pp, 584K)
  • Complete Report (PDF) (99 pp, 2M)
  • Drinking Water Quality Programs Chapter (PDF) (11 pp, 196K)
  • Ground Water Quality Chapter (PDF) (35 pp, 730K)

Sole source aquifer protection program

Sole Source Aquifer Protection Program

A sole source aquifer supplies 50 percent or more of the drinking water for a given aquifer service area for which there are no reasonably available alternative sources, should the aquifer become contaminated. Designation as a sole source aquifer protects an area’s ground water resources by requiring EPA to review any proposed projects within the designated area that are receiving federal financial assistance.

• Sole Source Aquifer page

Watershed-based protection program

Watershed-Based Protection Program

The goal of source water protection is to protect the drinking water resource by protecting and preserving the environmental quality of the watershed above the intake (or the aquifer around the well). The assessment is the first step in the process to protect the resource. Once a watershed has been assessed to determine its current condition and the extent of the threats to the system, a watershed plan can be developed and implemented.

EPA’s Office of Water has numerous programs that focus on watershed protection under the Clean Water Act (CWA). The Act includes programs such as the Nonpoint Source Program, National Estuary Program, the Total Maximum Daily Load (TMDL) Program, and the National Pollution Discharge Elimination System (NPDES) program. Each of these programs encourage states to develop programs to promote watershed-based protection, and they have elements that support watershed-based planning and implementation. The federal programs are generally implemented at the state level.

• Office of Wetlands, Oceans, and Watersheds
• Nonpoint Source Pollution
• National Estuary Program
• Total Maximum Daily Loads
• National Pollutant Discharge Elimination System (NPDES)

EPA,Federal /non-governmental programs

EPA, Federal / Non-governmental Programs

There is no single federal program for implementing source water protection plans and activities. However, many federal, tribal, regional, and local programs have tools and resources that can be used to focus on protecting drinking water. Source water protection can benefit, and benefit from, other EPA programs, other federal programs and non-governmental programs:

• Other programs can use source water assessments and identified protection areas to set priorities for ongoing prevention efforts.
• Identifying source water protection areas increases federal, state and local managers’ awareness of other programs where participation might increase the protection of human health.
• Protecting sources of drinking water can help various federal programs, states, organizations and communities meet other environmental and social goals, such as green space conservation, stormwater planning, management of nonpoint source pollution and brownfields redevelopment.
• The benefits that EPA and other federal programs can provide to state and local source water assessment and protection efforts are potentially very large. These include information, technical and financial resources, and communication networks and enforcement authorities.

EPA program links

• EPA’s Office of Ground Water and Drinking Water
• • Public Drinking Water Systems Programs
  • Underground Injection Control Program
    
• EPA’s Office of Water
• • Office of Wastewater Management
  • Office of Wetlands, Oceans, and Watersheds
  • Office of Science and Technology
    
• Non-Water Program Links
• • American Indian Environmental Office
  • Office of Underground Storage Tanks: Source Water Areas and Underground storage tanks
  • Office of Pesticides
  • Office of Pollution Prevention
  • Environmental Finance Program
  • Office of Smart Growth
    
• EPA program and regional offices

Other Federal Programs and Non-Governmental Organizations

• Related links: Includes links to non-EPA organizations that are related to source water protection.
• • Federal government web sites
    
  • State drinking water web sites
  • Non-governmental web sites
  • Contacts for non-EPA organizations links
  • Publications by other organizations links

Tribal programs

Tribal Programs

EPA is firmly committed to helping tribes to assess the rivers, lakes, springs and aquifers that serve as tribal public water supplies and to implement measures to protect against contamination of these water resources.

• Protecting Drinking Water: A Workbook for Tribes
  The Water Education Foundation recently completed this national water quality publication using a grant from EPA. The Workbook includes background information on the importance of protecting source water from pollution and includes a step-by-step work plan for tribes interested in developing a plan for protecting their drinking water.
• Source water protection fact sheet and EPA regional contacts for tribes (PDF) (4 pp, 80K)
  Provides more information on source water protection, how to get started, and funding available.
• Tribal drinking water programs and UIC program
  
• Other water pollution control funding sources
  Provides information on drinking water, wastewater and watershed protection funding sources.
• Nonpoint source pollution control grants to tribes
  Describes opportunities to fund projects to control polluted runoff.
  

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Water contamination – Fracking

What fracking is all about – Fracking defined Part 2

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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 so-called “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.

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Water contamination news – Fracking

Using diesel fuel in oil and gas hydraulic fracturing.

Kansas City infoZine / Saturday, May 05, 2012 ::

More information: The EPA Offers the following information

Hydraulic Fracturing Under the Safe Drinking Water Act

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