Tuesday, 14 December 2010

CNN- NY governor pauses 'fracking' - (until July 2010)- Points to BioLargo Opportunity

By Sarah Hoye, CNN


New York governor signs order halting drilling process alleged to taint water until July 1

  • Also known as "fracking," it's a controversial method of drilling for natural gas
  • The EPA is reviewing position on whether fracking contaminates groundwater
  • Industry leaders say the process is safe

(CNN) -- New York Gov. David Paterson has signed an executive order halting the controversial natural gas drilling process called hydraulic fracturing until July 1.

The process --- also known as "fracking" -- has come under scrutiny because of its alleged harmful effects on underground drinking water and the environment -- although industry leaders have insisted it's safe.

The governor's order -- which was signed Saturday -- prohibits horizontal hydraulic fracturing in New York until the state Department of Environmental Conservation completes a comprehensive review.

The outgoing governor also vetoed legislation that would have placed a moratorium on high-volume, horizontal hydraulic drilling and more conventional vertical drilling.

Interactive: See how fracking works

In November, the New York Assembly voted 93-43 to halt hydraulic fracturing temporarily so the state could investigate the safety and environmental concerns. The state's Senate passed a similar bill in August.

Can shale gas be produced safely?

In the past, Paterson has expressed concern about hydraulic fracturing, which involves cracking thousands of feet beneath the Earth's surface to get at valuable natural gas.

The proposed moratorium in New York was described as "misguided" by Kathryn Klaber, who represents a large natural gas industry coalition in the Northeast.

"Tightly regulated, environmentally sound natural gas development in New York can and will deliver a much-needed and long-lasting economic shot in the arm ... for the entire state, just as it is in Pennsylvania, West Virginia and elsewhere," said a written statement from Klaber, president of the Marcellus Shale Coalition.

Using hydraulic fracturing, drillers pump large amounts of water mixed with sand and chemicals into the shale formation thousands of feet underground under high pressure. Fracturing the shale around the gas well then allows the natural gas to flow freely.

The process has raised concerns about whether those chemicals are contaminating the underground water. Some residents near hydraulic fracturing drill sites along the Delaware River Basin -- in Delaware, New Jersey, New York and Pennsylvania -- have been able to set their water on fire.

Watch residents set water on fireVideo

Several residents in rural Pennsylvania have filed a lawsuit against Cabot Oil & Gas Corp., blaming the company for the contamination.

The company has said the hydraulic fracturing process is "proven and safe," citing a 2004 hydraulic fracturing study by the Environmental Protection Agency that concluded the injection of hydraulic fracturing fluids "poses minimal threat" to underground sources of drinking water.

The EPA is reviewing its position and plans to issue its report in 2012.

Can the EPA regulate fracking?

New York City gets roughly half its water from the Delaware River Basin, which was recently named the country's most endangered river because of the threat of natural gas.

Last month, New York Mayor Michael Bloomberg called for a cautious approach to the drilling.

"The stakes are high," Bloomberg wrote in a November 17 letter to the Carol Collier, executive director of the Delaware River Basin Commission.

"The city has invested more than $1.5 billion in watershed protection programs that have resulted in improved water quality throughout our watershed, as well as to our releases downstream, which benefit all members of the commission, and the 15 million people who rely on the Delaware River watershed for clean drinking water," Bloomberg wrote.

Over the past few years, technological advances and increased profit margins have spurred increased use of hydraulic fracturing, according to the EPA. The U.S. Department of Energy estimates shale gas will make up more than 20 percent of the nation's total natural gas supply by 2020.

Currently, most natural gas is burned to produce electricity or heat and cool buildings. When burned, it emits about half the carbon dioxide as coal.

For that reason, most of the country's big environmental groups are cautiously supportive of increased shale gas development.

But, with the expansion of fracturing, there are increased concerns about its potential effects on the underground water table, public health and the environment.

Read Fortune magazine's special series on fracking

The concerns have prompted the EPA to look at the potential problems with fracturing, and public hearings to help decide how to conduct a study are almost finished.

The EPA -- which held public meetings this year in Binghamton, New York; Canonsburg, Pennsylvania; Fort Worth, Texas; and Denver -- plans to begin a study in 2011 and release initial results by late 2012.

Find this article at:

Sunday, 12 December 2010

Hydraulic Fracturing Facts Presented by Chesapeake Energy- Points to BioLargo Opportunity

About Hydraulic Fracturing

Hydraulic fracturing, commonly referred to as fracing, is a proven technological advancement which allows natural gas producers to safely recover natural gas from deep shale formations. This discovery has the potential to not only dramatically reduce our reliance on foreign fuel imports, but also to significantly reduce our national carbon dioxide (CO2) emissions and accelerate our transition to a carbon-light environment. Simply put, deep shale gas formation development is critical to America's energy needs and economic renewal.

Experts have known for years that natural gas deposits existed in deep shale formations, but until recently the vast quantities of natural gas in these formations were not thought to be recoverable. Today, through the use of hydraulic fracturing, combined with sophisticated horizontal drilling, extraordinary amounts of deep shale natural gas from across the United States are being safely produced.

Hydraulic fracturing has been used by the oil and gas industry since the 1940s and has become a key element of natural gas development worldwide. In fact, this process is used in nearly all natural gas wells drilled in the U.S. today. Properly conducted modern hydraulic fracturing is a safe, sophisticated, highly engineered and controlled procedure.

Fracturing Ingredients

In addition to water and sand, other additives are used in fracturing fluids to allow fracturing to be performed in a safe and effective manner. Additives used in hydraulic fracturing fluids include a number of compounds found in common consumer products.

Example of Typical Deep Shale Fracturing Mixture Makeup

A representation showing the percent by volume composition of typical deep shale gas hydraulic fracture components (see graphic) reveals that more than 99% of the fracturing mixture is comprised of freshwater and sand. This mixture is injected into deep shale gas formations and is typically confined by many thousands of feet of rock layers.

Link to Ingredients Information

Sunday, 5 December 2010

BioLargo's Odor-No-More Wins Horse Journal "Product of the Year" Award

Link to Horse Journal by Clicking Here

2010 Horse Journal Products of the Year

The most innovative, hardworking products from the past year's trials...

"A unique addition to stall odor control is "Odor-No-More". We used their dry flakes and found they absorbed wetness like no other product we've tried before. There was a noticeable difference in the stall after just a few days in both dampness and odor control...Ingredients are GRAS (generally recognized as safe). www.odornomore.com

Details of the First Award Found Here

(click the image below to enlarge the view)

Copy of Press Release here:

BioLargo's Odor-No-MoreTM Wins Horse Journal "Product of the Year" Award

Press Release Source: BioLargo, Inc. On Monday December 6, 2010, 9:00 am EST
LA MIRADA, CA--(Marketwire - 12/06/10) - BioLargo, Inc. (OTC.BB:BLGO - News) today announced that the Horse Journal awarded Odor-No-More its second "Editor's Choice" award -- this time as a "Product of the Year." The Horse Journal evaluated over 200 products during 2010. During its evaluation, the Horse Journal noted that in using Odor-No-More, they had found nearly a 50% reduction in bedding use. In awarding Odor-No-More one of ten products of the year, Horse Journal noted that it absorbed "wetness like no other product we've tried before."

"The choice of products of the year is one we take very seriously. Many times it comes down to what our testers have found they simply wouldn't be without again, and other times it's simply the best product we've found for the job."

"Being recognized as a most innovative, hardworking product for 2010 by an independent unbiased group of experts is quite an honor," stated Joe Provenzano, Odor-No-More, Inc. President. "We believe the opportunities ahead for other products that include the BioLargo technology will likely find similar accolades."

About BioLargo, Inc.
BioLargo's business strategy is to harness and deliver Nature's Best Solution™ -- free-iodine -- in a safe, efficient, environmentally sensitive and cost-effective manner. BioLargo's proprietary technology works by combining micro-nutrient salts with liquid from any source to deliver free-iodine on demand, in controlled dosages, in order to balance efficacy of performance with concerns about toxicity. BioLargo's technology has potential commercial applications within global industries, including but not limited to oil and gas, animal health, beach and soil environmental uses, consumer products, agriculture, food processing, medical, and water. It features solutions for odor & moisture control, disinfection and contaminated water treatment. BioLargo's strategic partner Ioteq IP Pty Ltd. was named a "Top 50 Water Company for the 21st Century" by The Artemis Project™; BioLargo markets Ioteq's iodine based water disinfection technology, the Isan system. The company's website is www.BioLargo.com. In 2010, Odor-No-More was awarded two Editor's Choice Awards, including a "Product of the Year" award, by the Horse Journal, a top industry award for excellence and are sold by BioLargo's wholly owned subsidiary, Odor-No-More, Inc. (www.OdorNoMore.com).

About Horse Journal
The goal of the Horse Journal is to provide practical solutions and hands-on information their readers can take into the barn and use. Horse Journal works to make bottom-line recommendations on products they believe will best serve readers. Evaluations are based on field trials, research and experience. Horse Journal does not accept commercial advertising. www.Horse-Journal.com

Safe Harbor Statement
The statements contained herein, which are not historical, are forward-looking statements that are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in the forward-looking statements, including, but not limited to, BioLargo's filings and future filings with the Securities and Exchange Commission, including those set forth in the BioLargo's Annual Report on Form 10-K for the year ended December 31, 2009.

Thursday, 14 October 2010

BioLargo's Odor-No-More (TM) wins coveted Editor's Choice Award after independent evaluation by the Horse Journal

Press Release

October 15, 2010

BioLargo’s Odor-No-MoreTM wins coveted Editor’s Choice Award after independent evaluation by the Horse Journal

Link to Award Information and Copy of Article Click Here

La Mirada, California (October 14, 2010) - BioLargo, Inc. (OTCBB: BLGO) today announced that its Odor-No-More Deodorizing Super-Absorbent Animal Bedding Additive™ received the top “Editor’s Choice” award from the prestigious “Horse Journal” publication, which is the industry’s leading independent and unbiased product, care and service guide for people who love horses.

“This award validates the effectiveness of our product at the highest level. Horse Journal put our product and claims through rigorous testing, directly comparing Odor-No-More against seven other leading products, concluding that they were no match for our product performance, and awarding us the top award,” stated Joe Provenzano, Odor-No-More, Inc. President. www.OdorNoMore.com “The testing highlights our product’s money-saving and improved-health benefits.”

The Horse Journal’s research found a 50% reduction in bedding use during the product test and reported: “Our previous top pick… remains a recommended product, however in bedding reduction it was no match for Odor-No-More. We decreased our bedding use by nearly 50%. That fact was re-affirmed when we stopped using the product and quickly noticed a huge difference in the stall wetness and bedding use… If your stall deodorizer also absorbs moisture, you’re going to save money.

Provenzano added, “This award and related industry recognition opens up important new pet industry related product opportunities. We know that if you can handle the big animals, like we do, then small animals, birds and reptiles are really easy to manage with our products. With 93.6 million cats, 15 million birds, 15.9 million small animals and 13.6 million reptiles in the United States (according to the American Pet Products Manufacturers Association), we believe the commercial opportunities ahead are substantial.”

* Forward Looking and SEC Related Safe Harbor Disclosures are shown on the actual release copied here.

Tuesday, 5 October 2010

BioLargo's Odor-No-More (TM) Animal Bedding Additive Wins Top Award in Equine Industry - Horse-Journal.com - Editor's Choice Award

October 2010

(Link to Horse-Journal.com Here)

If your stall deodorizer also absorbs moisture, you’re going to save money.

Fresh Barns Are Healthier

Many people are unaware that one of the primary causes of "heaves," or recurrent airway obstruction (RAO), is exposure to bacterial products in the air, particularly from urine ammonia. This is especially problematic for horses that lie down frequently or those that are closer to the ground, such as foals and ponies. Anything you can do to reduce the ammonia is a step in the right direction.

Obviously, daily cleaning of your horse’s stall and removal of the wet spots is important. In addition, your barn should have maximum ventilation, with open doors and windows and high ceilings.

However, even if you thoroughly clean out the urine-soaked areas in a stall, there’s no way you can get every bit of it out of your stall. And, if you have a dirt or clay floor, the urine seeps into that, too.

Lime is a fine white powder and was heavily used years ago for odor control. You need to look for calcium carbonate (barn lime, garden lime). It will control odors and help dry an area, but it can form a slippery surface. Its greatest advantage is price, at about 5¢ a day. Its disadvantage is that it’s very dusty and easily gets into the air. The fine powder from lime can irritate respiratory tracts and eyes of horses and people.

We found three types of deodorizers: liquid, powder and flakes.
Pine oil is another "oldie but goodie" that is relatively inexpensive. A gallon of pine-oil disinfectant/cleaner/deodorizer is about $17. Mix 3 oz. to 1 gallon of water and sprinkle it with a garden sprinkler. Pine oil is a great odor controller, but it won’t dry the stalls. Be aware that it can cause respiratory and skin irritation as well.

Plain clay non-clumping kitty litter will dry the horse’s stall, but it won’t deodorize it. We’ve also tried clumping kitty litter, which absorbed urine better, but it’s much more expensive. Avoid organic litters that may be made from corn and wheat byproducts that might tempt the horse to eat it (bad, because it could be moldy).

You’ll use about a pound of kitty litter a day, at about 20¢ a pound for the generic clay. You can mix it 50-50 with lime to increase its odor control. (Don’t use scented kitty litter, because some horses may be sensitive to it.)

Baking soda is fine as a deodorizer and will also absorb some moisture. It’s inexpensive, and we keep it around the barn for a variety of tasks, including cleaning out the water tanks, buckets, bits and stirrups. However, like kitty litter, it can become slick.

Commercial Choices.

The number of commercial products on the market is growing for good reason. They are more powerful in odor control and, usually, reducing wet spots.

The easiest way to use the liquids was with a garden sprayer.

Absorption itself helps reduce ammonia by making the urea less available to bacteria. Stall fresheners are often mineral-based, usually clays, like zeolites or montmorillonites. In our previous trial, testers found that zeolites gave better ammonia control, while the montmorillonites absorbed more moisture.

Many products, like Stall Dry Plus, are also antimicrobial, which means it works to kill the bacteria. Sprays, on the other hand, use live bacteria or enzymes to eat up the ammonia, which stops the smell.

Field Trial.

In May 2008, our field trial included six stall deodorizers. Since that time, we found two new contenders that piqued our curiosity, and we decided to see how they stacked up. The test barn used wood-pellet bedding on stall mats, and the horses were in the barn approximately 16 hours a day.

All the products claimed to decrease odors, while several also offered help with moisture absorption. The goal with the moisture-absorbing products was to reduce the amount of dirty bedding that needed to be removed. Stalls were cleaned daily with all manure and saturated wet spots removed.

We found the sprays were a bit more work to use than the powders. They were easiest if you got a one-gallon pump garden sprayer and mixed up a batch from concentrate. Using the ready-to-use trigger sprayers became tiresome quickly. With the pump sprayer, we could get a couple of stalls done quickly.

The wet spray was also a big help with wood pellets, which can get dusty if they’re too dry, and eliminated wetting dusty pellets. The spray products, obviously, don’t absorb moisture.

However, we found liquids were more versatile than the dry products. We could deodorize virtually anything. We sprayed the stall bedding, walls, barn aisle, wheelbarrow and pitchforks. Within days of starting to use Bye-Bye Odor, our barn smelled terrific. The downside, of course, is that this method won’t work well below 32°F.

With the dry products, we used a plastic cup and sprinkled close to the surface of the stall. We concentrated on wet spots and usual manure areas, then bedded over it.

The fine powders could get dusty quickly, so we tended to bend down, closer to the surface when we sprinkled the wet areas. We didn’t have any difficulty with slick spots in our stalls with any of our dry products. They all did a good job reducing odor, but they varied in their ability to absorb moisture. We saw a difference in decreased bedding use from negligible to nearly 50%.

Bottom Line.

The amount of deodorizer needed depends upon the individual horse’s habits. Messier horses need more product.

Although odor control is the No. 1 priority, we are thrilled with anything that helps reduce bedding, not just because of the cost, but also because the more you toss out, the more you need to get rid of. If the product also helps composting that’s another plus.

Our previous top pick, Stall Fresh, remains a recommended product, however in bedding reduction it was no match for Odor-No-More. We decreased our bedding use by nearly 50%. That fact was re-affirmed when we stopped using the product and quickly noticed a huge difference in the stall wetness and bedding use.

Our Best Buy is Bye Bye Odor. It’s inexpensive and easy to use in a garden sprayer. A mixture of 2 ½ gallons lasted us about a month on one stall, making the cost pennies per day. If you’re looking for an economical deodorizer that’s dry for winter months, try the Kaeco Stall Power.

Horse Journal staff article.

Consider This . . .

  • The ammonia from urine can harm your horse’s respiratory tract, even to the point of causing "heaves."
  • Products that also absorb moisture can cut down on your bedding use significantly if used reguarly.
  • Lime, pine oil, kitty litter and baking soda are no match for the power of the commercial blends we used.
  • Stall Deodorizers

    (Click Image to Enlarge)

    Who is the Horse-Journal.com?


    The goal of the Horse Journal is to provide practical solutions and hands-on information our readers can take into the barn and use. Horse Journal works to make bottom-line recommendations on products we believe will best serve our readers while standing firm with a back-to-the-basics philosophy on training, nutrition and horse care. We base our evaluations on field trials, research and experience. Horse Journal does not accept commercial advertising.

    Monday, 27 September 2010

    Halliburton Hunts New Bacteria Killer to Protect Shale-Gas Boom (March 2010) - Points to BioLargo Opportunity- (11-10 Clash with EPA Escalates)

    Halliburton Hunts New Bacteria Killer to Protect Shale-Gas Boom
    March 29, 2010, 12:38 AM EDT

    Link Here

    By David Wethe

    March 29 (Bloomberg) -- Halliburton Co. and Schlumberger Ltd., trying to forestall a regulatory crackdown that would cut natural-gas drilling, are developing ways to eliminate the need for chemicals that may taint water supplies near wells.

    At risk is hydraulic fracturing, or fracking, a process that unlocked gas deposits in shale formations and drove gains in U.S. production of the fuel. Proposed regulations might slow drilling and add $3 billion a year in costs, a government study found. As one solution, energy companies are researching ways to kill bacteria in fracturing fluids without using harmful chemicals called biocides.

    “The most dangerous part in the shale frack is the biocide,” said Steve Mueller, chief executive officer at Southwestern Energy Co., the biggest producer in the Fayetteville Shale of Arkansas. “That’s the number-one thing the industry is trying to find a way around.”

    U.S. House and Senate bills introduced in 2009 would force producers to get federal permits for each well. That and other proposed environmental measures would cut drilling by as much as half and add compliance costs of as much as $75 billion over 25 years, according to a study done for the U.S. Energy Department.

    Biocides are employed because the watery fluids used to fracture rocks heat up when they’re pumped into the ground at high speed, causing bacteria and mold to multiply, Mueller said. The bacteria grow, inhibiting the flow of gas.

    “You basically get a black slime in your lines,” he said in an interview. “It just becomes a black ooze of this bacteria that grew very quickly.”

    Ultraviolet Rays

    Halliburton and Schlumberger, the world’s largest oilfield contractors, are among companies seeking biocide substitutes. Houston-based Halliburton said March 9 that it’s testing a process using ultraviolet light to kill bacteria in fracking fluid.

    About 80 percent of gas wells drilled in North America are stimulated or fractured in some way, Tim Probert, corporate- development chief at Halliburton, said in a telephone interview.

    “It’s incumbent on the industry to continue to develop tools and technologies that are compatible with minimizing the environmental impact of the stimulation process,” Probert said.

    Houston-based ConocoPhillips, the third-largest oil company, said March 9 that the world has centuries of gas supplies, largely in unconventional deposits such as shale.

    Schlumberger, based in Houston and Paris, spoke with Southwestern about testing a biocide that would last only a few hours before becoming nontoxic, Mueller said. “We have not tested it,” he said. “We only know they’re working on it.”

    Ultrasonic Fluid

    Schlumberger spokeswoman Mary Jo Caliandro, who confirmed the company is testing new technology, declined to comment on any advance before it’s “commercial.”

    Houston-based Southwestern has tested an ultrasonic technique that moves water faster than the speed of sound through a cone-shaped vortex to kill bacteria before the fluid is sent down the well, Mueller said.

    “At high speeds, something will happen called cavitation,” he said. “You’re basically smacking the bugs upside the head and killing them.”

    Chemicals, including biocides such as chlorine, make up less than 1 percent of fracking fluids. The rest is water and sand. Companies haven’t identified the chemicals they use, citing competitive reasons. Advocacy organizations such as the Environmental Working Group in Washington have called for lawmakers to require energy companies to disclose the chemicals.

    Disclosure Issue

    “I think the industry’s going to have to be more transparent,” Steven Farris, CEO at Houston-based Apache Corp., the biggest independent U.S. oil producer by market value, said March 22 at the Howard Weil Energy Conference in New Orleans. “‘You can’t say, ‘Trust me.’”

    Gas producers are realizing they have to find ways to clean and recycle the water used in hydraulic fracturing, said George P. Mitchell, the Houston billionaire who pioneered development of shale gas in the Barnett formation of North Texas.

    “I think a lot of action is going on to get that done,” Mitchell said in a telephone interview. “It’s not an insurmountable task.”

    Environmental issues generally begin to be addressed after companies realize there will be a financial cost if they don’t act, said Geoff Kieburtz, an analyst at Weeden & Co. in Greenwich, Connecticut. “The oil industry is as good as any at recognizing those things change over time,” he said.

    EPA Permits

    House and Senate bills introduced in June would force producers to wait for the U.S. Environmental Protection Agency to develop a permitting process. They’d then have to get approval from the agency for each well. The EPA said March 18 it will spend $1.9 million to study risks associated with fracking.

    Environmental concerns over gas production go beyond biocides. Two of 94 monitoring sites at the Barnett Shale, the most productive U.S. shale formation, had elevated levels of the carcinogen benzene in the air, the Texas Commission on Environmental Quality said in January.

    “Now, when they have the possibility that something might stop the fracturing and stop the development of the shale, that’s what you have to worry about,” said Mitchell.

    --With assistance from Edward Klump in Houston. Editors: Tony Cox, Susan Warren.

    To contact the reporter on this story: David Wethe in Houston at dwethe@bloomberg.net.

    To contact the editor responsible for this story: Susan Warren at susanwarren@bloomberg.net.

    **** Link to Press Release- Former Halliburton CTO, Vik Rao- Joins BioLargo Management Team

    Sunday, 26 September 2010

    BBC Report- will shale revolutionise gas? - Points to BioLargo Technology Oportunity

    Link Here

    23 September 2010 Last updated at 19:19

    Q&A: will shale revolutionise gas?

    Will hopes of abundant shale gas supplies prove nothing more than a pipe dream?

    "If shale gas fails to deliver on current expectations, then in 10 years or so, gas supplies could face serious constraints."

    So says Paul Stevens, a senior fellow at the international affairs think tank, Chatham House.

    He's penned a report that raises serious doubts about whether shale gas will indeed deliver.

    So what is shale gas, why is it such a big deal, and what will happen if it turns out to be one big wild goose chase?

    What is shale gas?

    Shale is a type of rock, typically found in a layer above conventional oil and gas deposits.

    The rock contains natural gas that can be extracted.

    So why all the excitement?

    A core of shale rock from which gas is a natural by-product
    US energy companies have become very successful in recent years at extracting gas from the shale alongside their existing conventional gas wells.

    US shale gas production has increased from almost nothing in 2000 to a 20% share of gas production in 2009, with some analysts projecting a 50% share by 2035.

    Shale reserves are also abundant in other parts of the world.

    Is that why the gas price has fallen so much?


    Gas prices have fallen sharply since 2008, but a lot of this is because of the recession.

    And prices vary greatly from one region to another.

    It is noticeable that in the US and Canada - where shale is having the biggest immediate impact - prices fell by more than half in 2008-09, much more sharply than in Europe.

    Why has shale been such a big hit in the US?

    The Chatham House report points to several factors specific to the US:

    a high level of geological knowledge

    tax credits

    the technological innovation of "horizontal drilling"

    favourable environmental legislation

    a strong oil and gas service industry

    easy access to gas pipelines

    So why can't it happen elsewhere?

    Gazprom says that exploiting its gas shale deposits would be prohibitively expensive

    Drilling for shale gas is geologically complicated, and the geology varies greatly from one shale deposit to another.

    This means the success so far in the US may not be easy to replicate with other untapped deposits - even other deposits within the US.

    It is also expensive. Shale gas deposits are thinly spread and wells dry out very quickly, meaning a lot of wells are needed to capture the gas.

    And shale drilling is inefficient, typically capturing only 8-30% of a deposit, compared with 60-80% for conventional gas drilling.

    Gazprom estimates the cost of extracting shale gas in Siberia at about five times the cost of conventional gas, though the Russian company may be exaggerating the cost as shale gas represents a threat to its business.

    What about here in Europe?

    The UK already uses a lot of North Sea gas, and a switch to European shale gas would be a boon.

    However, the report sees several obstacles:

    European shale gas deposits are geologically much harder to extract than those in the US
    drilling is quite land intensive, and this could be very disruptive in densely populated Europe
    environmental legislation is much tougher than in the US

    there is no comparable onshore oil and gas service industry to provide drilling rigs and other equipment

    the gas transmission business in Europe is still dominated by giant national gas companies that may not welcome the new sources

    What happens if shale lives up to its billing?

    Pennsylvania called a three-year moratorium on the Marcellus gas project over environmental concerns

    Then it means cheap gas for everybody - or at least for everybody who has access to it.

    The gas industry is still very regionalised, due to high transportation costs, although "liquefied natural gas" (LNG) technology is making it possible to ship gas around the world, just like crude oil.

    However, a shale gas boom could lead to serious environmental problems.

    What are the environmental problems?

    The "horizontal" drilling technique used to extract shale involves pumping chemicals into the ground.

    Those chemicals could push salt water to the surface, and they could also poison drinking water.

    Already in the US there is a backlash against shale drilling, with Pennsylvania placing a moratorium on one major new project, while the US Congress is considering stricter legislation.

    Shale may also present a problem for global warming, because it is an abundant fossil fuel that could be a cheaper substitute than many renewable energy sources.

    However, carbon (and noxious gas) emissions from natural gas are much lower than from oil and coal.

    So what happens if shale falls flat?

    Uncertainty over shale is depressing investment in other gas facilities such as liquefied natural gas
    This is the big concern in the Chatham House report.

    They think that the low gas prices and the uncertainty caused by shale are weighing down investment in the gas industry.

    Gas companies may be afraid to invest in new conventional gas wells or LNG facilities if they think future shale supplies could render them redundant.

    Given the long lead-times on gas projects, investment decisions now will affect gas supplies in 10 years' time.

    This means a shortfall of investment now could lead to a shortfall of gas - and higher gas prices - by 2020.

    The Chatham House report also thinks the uncertainty about shale is undermining investment in renewable energy sources.

    Sunday, 19 September 2010

    How many wells are there in the USA? - Industry Points to Another BioLargo Technology Opportunity

    • Number of Oil Wells 363,107
    • Number of Gas Wells 460,261
    • Number of Injection Wells Estimated to Exceed: 1,500,000
    • Volume of Produced Water / Barrel of Oil Produced Water-to-Oil Ratio > 7.5 X

    (** Summary Not Complete- Additional Information Coming Soon)

    Number of Gas and Oil Wells Source: The US Energy Information Administration - 2008 Data
    Link Here

    Lee et al. (2002) report that U.S. wells produce an average of more than 7 bbl of water
    for each barrel of oil produced. API’s produced water surveys in 1985 and 1995 (see Table 3-1 [of report linked below]) also demonstrated that the volume of water produced increases with the age of the crude oil production. In these surveys, API had calculated a water-to-oil ratio of approximately 7.5 barrels of water for each barrel of oil produced. For the survey of 2002 production prepared for this white paper, the water-to-oil ratio was calculated to have increased to approximately 9.5. For crude oil wells nearing the end of their productive lives, Weideman (1996) reports that water can compromise as much as 98% of the material brought to the surface. In these stripper wells, the amount of water produced can be 10 to 20 bbl for each barrel of crude oil produced. Argonne Labs Report

    DOE's National Energy Tehcnology Lab - Injection Wells - An Overview- Another BioLargo Technology Opportunity

    The National Energy Technology Laboratory (NETL), part of DOE’s national laboratory system, is owned and operated by the U.S. Department of Energy (DOE). NETL supports DOE’s mission to advance the national, economic, and energy security of the United States.

    Fact Sheet - Underground Injection for Disposal
    Link to Site Here

    Intro to Produced Water

    Injection into underground formations represents the most common approach for onshore management of produced water. Under U.S. Environmental Protection Agency (EPA) rules, produced water injection wells are classified as Class II wells. Class II wells are further subdivided into II-R (enhanced recovery), II-D (disposal), or II-H (hydrocarbon storage). Most produced water is injected to maintain reservoir pressure and hydraulically drive oil toward a producing well. This type of injection for "enhanced recovery" is discussed in a separate fact sheet. This fact sheet describes underground injection of produced water solely for disposal. The figure )below) shows a typical injection wellhead.

    Injection well at Texas waste disposal facility; Source: J. Veil, Argonne National Laboratory.
    Significant volumes of produced water are injected in the United States. Virtually all states with oil and gas production operations also have produced water injection wells. According to the Ground Water Protection Council, approximately 170,000 Class II wells are found in 31 states (GWPC undated). In early 2003, Argonne interviewed staff from oil and gas agencies in three large oil- and gas-producing states (California, New Mexico, and Texas) to learn the number of injection wells in each state, and what percentage were used for enhanced oil recovery or for disposal. The numbers of wells and water volumes injected are estimates. Nevertheless, they highlight the importance of injection as a produced water management option.

    California had nearly 25,000 produced water injection wells. The annual injected volume is approximately 1.8 billion bbl, with about 20% injected for disposal.
    New Mexico had 903 permitted disposal wells, with 264 of them active. Approximately 190 million bbl of produced water is injected for disposal.

    Texas had 11,988 permitted disposal wells, with 7,405 of them active. In 2000, approximately 1.2 billion bbl of produced water were injected into nonproducing formations, and 1 billion bbl were injected into producing formations. In sum, operators in these three states inject more than 4 billion bbl of produced water per year for disposal.

    Injection Well Siting and Construction
    Operators injecting for disposal will typically seek formations that exhibit the right combination of permeability, porosity, injectivity, and other geologic features enabling the injected water to enter the formation under pressures lower than fracture pressure. The injection formation should be geologically isolated from any underground source of drinking water (USDW) and from hydrocarbon-producing formations (unless the injection is for enhanced recovery). Operators should avoid areas with excessive faulting, fractures that extend vertically, or other improperly cemented well bores.

    Cross-section drawing of an injection well; Source: U.S. Environmental Protection Agency.
    Class II injection wells are constructed so that injected fluids are conveyed to the authorized injection zone and do not migrate into USDWs. Class II wells are drilled and constructed with steel pipe (called casing) cemented in place to prevent the migration of fluids into USDWs. Surface casing is cemented from below the lowermost USDW up to the surface to prevent fluid movement. Cement is also placed behind the injection casing at critical sections to confine injected fluids to the authorized injection zone. A typical produced water injection well is also equipped with injection tubing, through which the fluids are pumped from the surface down into the receiving geologic formations (GWPC undated). The figure below shows a cross-section drawing of an injection well with casing, cement, and tubing.

    Treatment Prior to Injection
    It is important to ensure that the produced water injectate is compatible with the receiving formations to prevent premature plugging of the formation or damage to equipment. It may therefore be necessary to treat the water prior to injection to control excessive solids, dissolved oil, corrosion, chemical reactions, or growth of microbes.

    Solids are usually treated by gravity settling or filtration. Residual amounts of oil in the produced water not only represent lost profit for producers, but can also contribute to plugging of receiving formations. Various treatment chemicals are available to break emulsions or make dissolved oil more amenable to oil removal treatment.

    Corrosion can be exacerbated by various dissolved gases - primarily oxygen, carbon dioxide, and hydrogen sulfide. Oxygen scavengers and other treatment chemicals are available to minimize levels of undesirable dissolved gases.

    The water chemistry of a produced water sample does not necessarily match the receiving formation. For example, various substances dissolved in produced water could react with the rock or other fluids in the receiving formation, and trigger undesirable consequences. Before beginning a water flood operation, it is important to analyze the constituents of the produced water with the purpose of avoiding chemical reactions that form precipitates. If necessary, treatment chemicals can minimize undesirable reactions.

    Bacteria, algae, and fungi can be present in produced water. They can also be introduced in the course of water handling at the surface. Bacteria, algae, and fungi are generally controlled through filtration or the addition of biocides.

    GWPC, undated, "Injection Wells, An Introduction to Their Use, Operation, and Regulation," prepared by the Ground Water Protection Council, Oklahoma City, OK. Available at http://www.gwpc.org/e-library/documents/general/Injection%20Wells-%20An%20Introduction%20to%20Their%20Use,%20Operation%20and%20Regulation.pdf [PDF].

    Veil, J.A., M.G. Puder, D. Elcock, and R.J. Redweik, Jr., 2004, "A White Paper Describing Produced Water from Production of Crude Oil, Natural Gas, and Coal Bed Methane," prepared by Argonne National Laboratory for the U.S. Department of Energy, National Energy Technology Laboratory, January. Available at http://www.evs.anl.gov/pub/dsp_detail.cfm?PubID=1715.

    Related Treatment Technology Descriptions
    Basic Separation
    Mechanical Blocking Devices
    Water Shut-Off Chemicals
    Downhole Separation
    Sea Floor Separation
    Injection for Oil Recovery
    Injection for Future Water Use
    Injection-Hydrologic Purposes
    Agricultural Use
    Industrial Use
    Domestic Use
    Offsite Commercial Disposal
    Membrane Processes
    Ion Exchange
    Capacitive Deionization
    Thermal Distillation
    Physical Separation
    Physical/Chemical Processes
    Solvent Extraction

    EPA Web Site Provides Additional Summary Information About Injection Wells

    DOE's National Energy Technology Lab - What is Produced Water? - Link to Argonne National Lab White Paper - Points to BioLargo Tech Opportunity

    The National Energy Technology Laboratory (NETL), part of DOE’s national laboratory system, is owned and operated by the U.S. Department of Energy (DOE). NETL supports DOE’s mission to advance the national, economic, and energy security of the United States.

    Produced Water Management Information System

    Introduction to Produced Water (Link to Site)

    What Is Produced Water?

    Produced water is water trapped in underground formations that is brought to the surface along with oil or gas. Because the water has been in contact with the hydrocarbon-bearing formation for centuries, it contains some of the chemical characteristics of the formation and the hydrocarbon itself. It may include water from the reservoir, water injected into the formation, and any chemicals added during the production and treatment processes. Produced water is also called “brine” and “formation water.” The major constituents of concern in produced water are:

    Salt content (salinity, total dissolved solids, electrical conductivity)
    Oil and grease (this is a measure of the organic chemical compounds)
    Various natural inorganic and organic compounds or chemical additives used in drilling and operating the well
    Naturally occurring radioactive material (NORM)

    Produced water is not a single commodity. The physical and chemical properties of produced water vary considerably depending on the geographic location of the field, the geological host formation, and the type of hydrocarbon product being produced. Produced water properties and volume can even vary throughout the lifetime of a reservoir.

    How Much Produced Water Is Generated?

    Produced water is by far the largest volume byproduct or waste stream associated with oil and gas exploration and production.

    Approximately 15-20 billion bbl (barrels; 1 bbl = 42 U.S. gallons) of produced water are generated each year in the United States from nearly a million wells

    More than 50 billion bbl of produced water are generated each year at thousands of wells in other countries.

    Early in the life of an oil well, the oil production is high and water production is low. Over time the oil production decreases and the water production increases. Another way of looking at this is to examine the ratio of water-to-oil:

    Worldwide estimate – 2:1 to 3:1
    U.S. estimate – 7:1, because many U.S. fields are mature and past their peak production
    Many older U.S. wells have ratios > 50:1
    At some point the cost of managing the produced water exceeds the profit from selling the oil. When this point is reached, the well is shut in.

    In contrast, a coal bed methane well initially produces a large volume of water, which declines over time. The methane production starts low, builds to a peak, and then decreases.

    This information and much of the background material used throughout the PWMIS site is based on Argonne’s produced water white paper [external site].

    Veil, J.A., M.G. Puder, D. Elcock, and R.J. Redweik, Jr., 2004, “A White Paper Describing Produced Water from Production of Crude Oil, Natural Gas, and Coal Bed Methane,” prepared by Argonne National Laboratory for the U.S. Department of Energy, National Energy Technology Laboratory, January.

    About NETL

    The National Energy Technology Laboratory (NETL), part of DOE’s national laboratory system, is owned and operated by the U.S. Department of Energy (DOE). NETL supports DOE’s mission to advance the national, economic, and energy security of the United States.

    NETL implements a broad spectrum of energy and environmental research and development (R&D) programs that will return benefits for generations to come:

    Enabling domestic coal, natural gas, and oil to economically power our Nation’s homes, industries, businesses, and transportation …
    While protecting our environment and enhancing our energy independence.
    NETL has expertise in coal, natural gas, and oil technologies, contract and project management, analysis of energy systems, and international energy issues.

    In addition to research conducted onsite, NETL’s project portfolio includes R&D conducted through partnerships, cooperative research and development agreements, financial assistance, and contractual arrangements with universities and the private sector. Together, these efforts focus a wealth of scientific and engineering talent on creating commercially viable solutions to national energy and environmental problems.

    Saturday, 18 September 2010

    Wall Street Journal Report- Fracking chemicals in NE Pa. water well - Points to BioLargo Opportunity

    Link Here

    Report: Fracking chemicals in NE Pa. water well

    DIMOCK, Pa. — A private consulting firm says it found toxic chemicals in the drinking water of a Pennsylvania community already dealing with methane contamination from natural gas drilling.

    Environmental engineer Daniel Farnham said Thursday that his tests, which were verified by three laboratories, found industrial solvents such as toluene and ethylbenzene in "virtually every sample" taken from water wells in Dimock Township, Susquehanna County.

    Farnham, who has tested water for both gas interests and for local residents, said it would be impossible to say that the chemicals he found were caused by gas drilling.

    The chemicals, at least one of which, ethylbenzene, may cause cancer, are among dozens used to hydraulically fracture shale deposits to unlock natural gas trapped thousands of feet underground. The chemicals are also used in an array of products ranging from paint thinner to gasoline.

    The contaminated Dimock wells are in the gas-rich Marcellus Shale, where a rush to tap the vast stores has set off intense debate over the environmental and public health impact of the drilling process. Millions of gallons of water mixed with numerous chemicals and sand are blasted deep into the earth to free gas from the shale rock. As much as 90 percent of the mixture is left underground.

    Dimock residents sued Houston-based Cabot Oil&Gas Corp. last year, alleging the drilling company polluted their wells with methane gas and other contaminants. Pennsylvania's Department of Environmental Protection said defective casings on at least three of Cabot's wells allowed gas to pollute groundwater. Cabot was fined more than $240,000 and ordered to clean up the pollution.

    On Thursday, DEP said it would spend about $10.5 million to provide safe water for the affected Dimock residents, connecting their homes to a municipal water supply in Montrose, about six miles away. The residents balked at an earlier fix that would have placed large, whole-house water treatment systems in each of the 14 affected homes.

    DEP chief John Hanger told The Associated Press that the connection to public water is "the best, and really only, solution" and that if Cabot balks at paying the tab, the state will pay for the work itself — then go after Cabot for the money.

    Officials and residents had discussed another option — drilling a well or wells and piping that water to the homes — but Hanger said it was dropped because "we don't believe that will ensure a permanent, safe supply of water."

    A person who took part in the discussions said Hanger told residents the entire aquifer might be polluted by gas drilling operations.

    "He said, 'I cannot guarantee that there is any water in the aquifer that is clean today, that will be clean next week, that will be clean six months after the whole system is put in, because of the drilling activity and the damage to the aquifer.' It was repeated twice," said the person, who spoke on condition of anonymity to discuss a private meeting.

    Later Tuesday, Hanger denied through a spokeswoman making the statement. DEP spokeswoman Helen Humphries said Hanger believes the threat of stray gas migration is the chief problem with drilling new water wells.

    "We want to ensure there's not a chance for methane gas to migrate into the water wells. The best way of doing that is to install a water line to provide public water," she said.

    On Tuesday, 13 families in Lenox Township, about eight miles from Dimock, sued another Houston driller, Southwestern Energy Co., claiming their wells were contaminated with fracking fluids. Southwestern denied any problems with its well.

    In Dimock, Farnham said the water samples were tested independently by three labs, all of which showed the same results.

    But Farnham said it's impossible to tell where the chemicals came from.

    "Can anybody say that this came from fracking, or from frack flowback? There's no way a true scientist would be able to make that determination based on the data that we have," he told The Associated Press on Thursday. "Until and unless we are able to put a die or marker in the frack liquid, it's going to be awfully difficult to prove irrefutably that it's coming from frack."

    Cabot spokesman George Stark said the chemicals existed in some wells before drilling began.

    "We have asked for samples of the affected well water so we can do an independent analysis," he said.

    Dimock residents have claimed their wells were contaminated shortly after Cabot started drilling near their homes, saying the water that came out of their faucets suddenly became cloudy, foamy and discolored, and smelled and tasted foul.

    One resident's well exploded on New Year's Day 2009, prompting a state investigation that found Cabot had allowed combustible gas to escape into the region's groundwater supplies.

    Cabot says the methane in the residents' wells might be naturally occurring.

    Farnham — hired by Cabot in 2008 to perform pre-drill testing of residential water wells in Dimock — said those tests did not turn up any problems, adding he did not even test for the chemicals that Cabot claims existed prior to drilling.

    After the drilling began, Farnham was asked by residents to test their water, and was later hired by plaintiffs' attorneys.

    "It doesn't take me or any scientist to see some of the impacts on the drinking water," he said. "Your drinking water goes from clear and fine, to a week later being yellow-colored, sediment on the bottom, foam on the top and an oily smell to it. It's not a figment of anybody's imagination."

    The Dimock test results were first reported by The Times-Tribune of Scranton.

    —Copyright 2010 Associated Press