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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Fracking-injection wells-Polluted water fuels a battle for answers.

by Abrahm Lustgarten ProPublica, June 21, 2012, 10:01 a.m.

DeBerry lies in the heart of the Haynesville Shale natural gas development. When Hudson moved in, the area was littered with injection wells used to deposit waste from oil and gas drilling deep beneath the earth.

The well sites – often located just a few yards from residents’ doorsteps – were busy industrial zones clogged with truck traffic and holding tanks. Oil stains spattered the ground around pipes where waste was pumped underground.

Hudson said he soon noticed that his well water had a metallic flavor and a sharp smell. Congregants in his church told him theirs was cloudy and salty to taste, leaving rings in toilets and sinks. They said they had been complaining to Texas officials since 1996, yet no one had investigated.

“Our cries, they just fall on deaf ears,” Hudson said.

Shortly after moving to DeBerry, Hudson sent water from his well and four of his neighbors’ to be tested for pollutants. The results showed high levels of chlorides, chemicals found in drilling waste, a federal report said.

According to the report, Hudson shared the tests with Basic Energy Services, the company that operated the waste wells nearby, which sent them to the Railroad Commission of Texas, the agency that regulates disposal wells for oil and gas drilling waste.

Nearly a year after receiving the material, commission officials tested DeBerry’s water themselves, confirming that it contained arsenic, cadmium, lead, benzene and other substances. The contamination was extensive enough that they advised DeBerry residents not to drink their water, leaving Hudson and others to purchase bottled water.

In 2004, Texas officials ordered the injection wells in DeBerry to be permanently shut down. A series of 30-foot monitoring wells were drilled to test for leaking waste around the area, and one deeper well was drilled to take samples from 170 feet below. None of the data collected enabled the Railroad Commission to determine the cause of the pollution, however.

To Hudson and others, there were powerful clues in the commission’s own records, which showed that one of the injection wells had a history of problems. In 2000, a Louisiana trucking company illegally dumped thousands of gallons of hazardous waste from an oil refinery into it, material far more dangerous than the well was allowed to accept under government regulations. Five years later, a mechanical integrity test detected a crack in the well structure that allowed waste to leak.

“Produced water was observed flowing from between the surface casing and the production casing,” a Railroad Commission official wrote to Basic Energy Services in Feb. 2006. “RRC staff requests that Basic immediately evaluate the need for further environmental investigation of groundwater.”

Still, federal and state regulators struggled to obtain a definitive answer about what caused the pollution.

According to a 2007 report by the U.S. Environmental Protection Agency’s inspector general, the Railroad Commission had a difficult time getting Basic Energy to cooperate. The agency ordered the company to drill additional deep disposal wells to monitor DeBerry’s water, but the company refused.

“Basic Energy Services informed the State that it did not believe the contamination was its responsibility, and since the freshwater well had been plugged, deeper groundwater testing could not be conducted,” the inspector general’s report said.

Basic Energy Services did not return a call requesting comment.

The Railroad Commission told ProPublica that it had done everything it could to solve the mystery.

“The commission investigation did not identify a large plume of hydrocarbon and saltwater in the groundwater that connected the former… facility to residents’ water wells,” said Ramona Nye, a spokeswoman for the agency. “Commission staff address all water well complaints promptly and base their decisions on science and fact.”

Unsatisfied with the state’s progress, federal EPA officials took over the investigation in 2005 under the Superfund program, ordering more water sampling around the injection wells. For the first time, a decade after the saga began, the EPA also began supplying bottled water to DeBerry residents.

By 2007, however, the EPA also concluded that injection wells played no part in DeBerry’s water contamination.

“A range of surface activities including septic systems, surface spills and/or agricultural and domestic practices caused the ground water contamination,” an EPA spokesperson told ProPublica in an April, 2012 email. “Comprehensive review of the admin record for the injection wells in question indicated no ground water contamination from the wells.”

The EPA declined to allow any of its staff in Texas to be interviewed for this story, sending written responses to several questions.

The 2007 inspector general report suggested the EPA’s conclusion may have been premature, however.

“Region 6 personnel told us they believe evidence shows the contamination did not originate from the injection well,” the inspector general’s report states. “Neither the State nor EPA has conclusively determined the source of the contamination… The full extent of the contamination, its lateral limits, its depth, and its migration patterns or movement along the groundwater plume is not known.”

Earlier this month, EPA officials returned to DeBerry to sample five public drinking water wells, in “response to community concerns,” according to a statement sent to ProPublica by the agency Wednesday. The agency did not respond to questions about whether it was reconsidering its previous conclusions.

Hudson has little hope that the renewed scrutiny will yield closure.

“We will always have a problem proving the contaminants are coming from injection wells. You’d have to have a camera underneath the ground somewhere,” Hudson said. “Even if they find oil and gas carcinogens in the water, they are going to find another way to say it came from somewhere else. Nobody wants to say what the cause was.”

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.”

 

Help our mission

How to navigate STW ™ postings:
View monthly posting’s calendar, become a subscriber or obtain RSS feed by going to the bottom index of this page.

Explanation of Index:

This Months Postings: Calendar on left displays articles and pages posted on a given day.

Current and Archived Postings: Click on the month you want to view. Most current article for the month will appear at top of screen.

RSS Links : Obtain your RSS feeds.

Subscribe: Subscribe to postings by entering your e-mail address and confirming your e-mail.

Supporting water research and the education program’s growth of Save the Water™ is vital to our future generation’s health, your funding is needed.

Fracking-Injection wells
Whiff of phenol spells trouble.

But the phenol – a deadly chemical used in Aristech’s processes that is known to cause internal burns, muscle spasms and organ failure – indicated that something might have gone wrong.

Environmental regulators suspected that the chemical had somehow drifted upward from the first two wells, travelling as much as 1,400 feet through the very rock expected to contain it.

If confirmed, their suspicions had broader implications: The type of disposal wells Aristech was using were among the most stringently regulated and monitored in the country.

To get permission for the new well — the first of its kind drilled after new national environmental rules went into effect — Aristech needed to prove to the Environmental Protection Agency that its waste would remain trapped for at least 10,000 years. The company had made that case for the two existing wells, using some of the most advanced computer modeling and the best geological science available at the time.

A leak would mean that even subject to the strictest regulations might not be as safe as scientists thought.

At first, Aristech’s managers denied that any leak had occurred. In letters written to Ohio’s Environmental Protection Agency, they said the pollution – still 4,000 feet below ground – could have been caused by other injection wells in the area, or by spills on the surface. They accused the state EPA of botching its investigation. The company even appealed to the agency’s director to intercede, without success.

“Your close personal attention to this proceeding has become essential,” Paul Kaplow, Aristech’s environment and safety manager, wrote to Ohio’s chief environmental official, Richard Shank, in July 1989. Kaplow said that Ohio’s “lower-level” environmental regulators were acting in a way that was “wholly inappropriate.”

Federal and state investigators turned the half-drilled well into a monitoring station to collect underground data, and took samples of rock from nearby to examine it for fractures that could have allowed waste to leak.

By the mid-1990s, investigators confirmed that waste had indeed migrated upwards from Aristech’s older wells, probably through a network of small fractures in the rock. Scientists thought the pressure used to force waste deep into the wells had helped crack the rock and push the contaminants back up.

Their inquiry turned to the future: It had taken 23 years for the waste – leaking at a rate of 2.5 gallons a minute — to move 1,400 feet. Would the chemicals travel thousands of feet further and wind up in drinking water supplies? How long would that take? More than 1.4 billion gallons of chemicals were dissipating beneath the site.

For another decade, the EPA and the state of Ohio studied the site for signs that the waste was still on the move. During that time, the concentration of the contaminants increased in the deep monitoring well, according to Ohio records obtained by ProPublica. Pressure readings taken in that well continued to increase, another sign that the force of injection could still be pushing the waste upward, even after injections into the two original wells ceased in 1996.

Contaminants also began to appear in a shallow drinking water monitoring well drilled to 80 feet below the surface: chloride, barium, iron. Ohio officials wondered whether these compounds, which occur naturally but far beneath the surface, also resulted from the changes deep underground.

Despite the concerns, in March 2005, Aristech petitioned for the investigation, and the wells, to be closed. Years of testing and sampling proved the contaminants could never be a risk to people, the company argued.

Ohio’s regulators weren’t ready to budge. Under a 1996 compliance agreement, regulators required Aristech to test the monitoring wells and provide the results to the state to demonstrate that the conditions were stable. According to correspondence with state officials, however, Aristech often fell behind on tests or failed to deliver the results to the state.

In May 2005, state records show, one of the lead regulators learned that a near-surface water sample taken by Aristech the previous December had tested positive for phenol, the same deadly contaminant in the injection wells.

“Turns out there was a positive hit for phenols in the USDW well,” Jess Stottsberry wrote to a colleague.

According to Stottsberry’s emails, the company had delayed turning the data over to the state so that it could re-sample the well.

The second round, Stottsberry wrote, came back clean. But the circumstances were puzzling: Aristech had waited more than two months before re-sampling the well, Stottsberry learned, and when it did, it used a different lab to test the results. It was another 10 weeks before that data was shared with Ohio’s EPA.

“Why did they change labs?” Stottsberry asked in a May 12, 2005 email to a colleague. “Not happy.”

Aristech was bought by Sunoco in 2001 then sold to Haverhill Chemicals in 2011. A Sunoco spokesman said he could not answer questions about the waste well issue because the employees involved no longer worked for the company.

Stottsberry confirmed the email’s authenticity, but Ohio EPA would not allow him to be interviewed by ProPublica.

The test results in question — among the most significant documents in the entire investigation — are missing. They were not among roughly 40,000 pages of records about the case Ohio provided to ProPublica. State officials said the pages had been lost or destroyed because of a shortage of storage space.

On the same day as Stottsberry’s email questioning the re-sampling, Ohio’s chief drinking and groundwater official, Michael Baker, sent a letter to Aristech management stating that there was not enough evidence to support closing the case.

“The increasing concentrations of waste parameters in Rose Run (the geological formation above the injection point) would suggest that upward migration of waste is continuing,” he wrote. Even after a decade of data-gathering, he wrote, “There is no evidence to support” the idea that the pollution was contained and that the chemicals would not wind up in drinking water.

Yet, just six weeks later, after meeting in person with Aristech executives in Columbus, Ohio regulators closed the case.

Baker – who is now Ohio EPA’s director — said he now believes the sample detecting phenol was a mistake, and says he no longer believes that underground migration is continuing.

“They quite conclusively convinced us that there was no substantial risk” to the underground source of drinking water, he said in an interview.

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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