Water contamination news: Fracking – Study has raised concerns about the safety of gas drilling in the Marcellus Shale.

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June 19 2012
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Water contamination news

New study predicts fracking fluids will seep into aquifers within years.

This story was originally published by ProPublica.

As part of its continuing advocacy to protect NYC’s water supply from contamination, the WCC submitted comments to  Hon. Joe Martens, Commissioner of the New York State Department of Environmental Conservation on the issue of hydrofracking in New York State

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.

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, [the rock layers] 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.”

This story was originally published by ProPublica.http://www.propublica.org/article/new-study-predicts-frack-fluids-can-migrate-to-aquifers-within-years/single#republish#ixzz1uDGSWKIA” target=”_blank”>Read more:

Proppants and fracking fluids

Last updated June 5th 2012 From Wikipedia, the free encyclopedia

A proppant is a material that will keep a induced hydraulic fracture open, during or following a fracturing treatment, while the fracking fluid itself varies in composition depending on the type of fracturing used, and can be gel, foam or slickwater-based.
[toggle title=” Proppants and fracking fluids: click” height=”auto”]

Proppants and fracking fluids

Last updated June 5th 2012 From Wikipedia, the free encyclopedia

A proppant is a material that will keep a induced hydraulic fracture open, during or following a fracturing treatment, while the fracking fluid itself varies in composition depending on the type of fracturing used, and can be gel, foam or slickwater-based. In addition, there may be unconventional fracking fluids. Fluids make tradeoffs in such material properties as viscosity, where more viscous fluids can carry more concentrated proppant; the energy or pressure demands to maintain a certain flux pump rate (flow velocity) that will conduct the proppant appropriately; pH, various rheological factors, among others. In addition, fluids may be used in low-volume well stimulation of high-permeability sandstone wells (20k to 80k gallons per well) to the high-volume operations such as shale gas and tight gas that use millions of gallons of water per well.

Conventional wisdom has often vascillated about the relative superiority of gel, foam and slickwater fluids with respect to each other, which is in turn related to proppant choice. For example, Zuber, Kuskraa and Sawyer (1988) found that gel-based fluids seemed to achieve the best results for coalbed methane operations, [1], but as of 2012, slickwater treatments are more popular.

Ignoring proppant, slickwater fracturing fluids are mostly water, generally 99% or more by volume, but gel-based fluids can see polymers and surfactants comprising as much as 7 vol% of a gel-based fluid, ignoring other additives. [2] Other common additives include hydrochloric acid (low pH can etch certain rocks, dissolving limestone for instance), friction reducers, biocides, and emulsifiers.

Radioactive tracer isotopes are sometimes included in the hydrofracturing fluid to determine the injection profile and location of fractures created by hydraulic fracturing.[3] Patents describe in detail how several tracers are typically used in the same well. Wells are hydraulically fractured in different stages.[4] Tracers with different half-lives are used for each stage.[4][5] Their half-lives range from 40.2 hours (Lanthanum-140) to 5.27 years (Cobalt-60).[6] Amounts per injection of radionuclide are listed in the The US Nuclear Regulatory Commission (NRC) guidelines.[7]The NRC guidelines also list a wide range or radioactive materials in solid, liquid and gaseous forms that are used as field flood or enhanced oil and gas recovery study applications tracers used in single and multiple wells.[7]

Except for diesel-based additive fracturing fluids, noted by the American Environmental Protection Agency to have a higher proportion of volatile organic compounds and carcinogenic BTEX, use of fracturing fluids in hydraulic fracturing operations was explicitly excluded from regulation under the American Clean Water Act in 2005, a legislative move that has since attracted controversy for being the product of special interests lobbying.

Proppant permeability and mesh size

Proppants used should be permeable or permittive to gas under high pressures; the interstitial space between particles should be sufficiently large, yet have the mechanical strength to withstand closure stresses to hold fractures open after the fracturing pressure is withdrawn. Large mesh proppants have greater permeability than small mesh proppants at low closure stresses, but will mechanically fail (i.e. get crushed) and produce very fine particulates (“fines”) at high closure stresses such that smaller-mesh proppants overtake large-mesh proppants in permeability after a certain threshold stress.[8]

Though sand is a common proppant, untreated sand is prone to significant fines generation; fines generation is often measured in wt% of initial feed. A commercial newsletter from Hexion cites untreated sand fines production to be 23.9% compared with 8.2% for lightweight ceramic and 0.5% for their product. [9] One way to maintain an ideal mesh size (i.e. permeability) while having sufficient strength is to choose proppants of sufficient strength; sand might be coated with resin, or a different proppant material might be chosen altogether– popular alternatives include ceramic, glass, and sintered bauxite.

Proppant weight and strength

Increased strength often comes at a cost of increased density, which in turn demands higher flow rates, viscosities or pressures during fracturing, which translates to increased fracturing costs, both environmentally and economically. [10] Lightweight proppants conversely are designed to be lighter than sand (~2.5 g/cc) and thus allow pumping at lower pressures or fluid velocities. Light proppants are less likely to settle. Porous materials can break the strength-density trend, or even afford greater gas permeability. Proppant geometry is also important; certain shapes or forms amplify stress on proppant particles making them especially vulnerable to crushing (a sharp discontinuity can classically allow infinite stresses in linear elastic materials). [11]

Proppant deposition and post-treatment behaviours

Proppant mesh size also impacts fracture length: proppants can be “bridged out” if the fracture width decreases to less than twice the size of the diameter of the proppant. [21] As proppants are deposited in a fracture, proppants can resist further fluid flow or the flow of other proppants, inhibiting further growth of the fracture. In addition, closure stresses (once external fluid pressure is released) may cause proppants to reorganise or “squeeze out” proppants, even if no fines are generated, resulting in smaller effective width of the fracture and decreased permeability. Some companies try to cause weak bonding at rest between proppant particles in order to prevent such reorganisation. [9] The modelling of fluid dynamics and rheology of fracturing fluid and its carried proppants is a subject of active research by the industry.

Proppant costs

Though good proppant choice positively impacts output rate and overall ultimate recovery of a well; commercial proppants are also constrained by cost. Transport costs from supplier to site form a significant component of the cost of proppants.


  1. ^ Mader, Detlef (1989). Hydraulic proppant fracturing and gravel packing. Amsterdam: Elsevier. ISBN 0-444-87352-X. http://books.google.com/books?id=FyGcOI42oBMC&pg=PA473&lpg=PA473.
  2. ^ Hodge, Richard. “Crosslinked and Linear Gel Comparison”. EPA HF Study Technical Workshop. Environmental Protection Agency. http://www.epa.gov/hfstudy/cross-linkandlineargelcomposition.pdf. Retrieved 8 February 2012.
  3. ^ Reis, John C. (1976). Environmental Control in Petroleum Engineering. Gulf Professional Publishers.
  4. ^ a b [1] Scott III, George L. (03-June-1997) US Patent No. 5635712: Method for monitoring the hydraulic fracturing of a subterranean formation. US Patent Publications.
  5. ^ [2] Scott III, George L. (15-Aug-1995) US Patent No. US5441110: System and method for monitoring fracture growth during hydraulic fracture treatment. US Patent Publications.
  6. ^ [3] Gadeken, Larry L., Halliburton Company (08-Nov-1989). Radioactive well logging method.
  7. ^ a b Jack E. Whitten, Steven R. Courtemanche, Andrea R. Jones, Richard E. Penrod, and David B. Fogl (Division of Industrial and Medical Nuclear Safety, Office of Nuclear Material Safety and Safeguards (June 2000). “Consolidated Guidance About Materials Licenses: Program-Specific Guidance About Well Logging, Tracer, and Field Flood Study Licenses (NUREG-1556, Volume 14)”. US Nuclear Regulatory Commission. http://www.nrc.gov/reading-rm/doc-collections/nuregs/staff/sr1556/v14/#_1_26. Retrieved 19 April 2012. “labeled Frac Sand…Sc-46, Br-82, Ag-110m, Sb-124, Ir-192”
  8. ^ “Physical Properties of Proppants”. CarboCeramics Topical Reference. CarboCeramics. http://archive.carboceramics.com/English/tools/topical_ref/tr_physical.html. Retrieved 24 January 2012.
  9. ^ a b “Critical Proppant Selection Factors”. Fracline. Hexion. http://www.momentivefracline.com/critical-proppant-selection-factors.
  10. ^ Rickards, Allan; et al (May 2006). “High Strength, Ultralightweight Proppant Lends New Dimensions to Hydraulic Fracturing Applications”. SPE Production & Operations 21 (2): 212–221. http://www.spe.org/ejournals/jsp/journalapp.jsp?pageType=Preview&jid=EPF&mid=SPE-84308-PA.
  11. ^ Guimaraes, M. S.; et al. (2007). “Aggregate production: Fines generation during rock crushing”. Journal of Mineral Processing. http://pmrl.ce.gatech.edu/papers/Guimaraes_2007a.pdf.


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