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Permalink Reply by Jack Straw on August 29, 2014 at 10:31am

Source: http://mobile.reuters.com/article/idUSKBN0GT0B320140829?irpc=932

Top News

Exclusive: Morgan Stanley plans natural gas export plant in new commodities foray

Fri, Aug 29 01:07 AM EDT

By Anna Louie Sussman

NEW YORK (Reuters) - Morgan Stanley has quietly filed plans to build and run one of the first U.S. compressed natural gas export facilities, the first sign the bank is plunging back into physical commodity markets even as it sells its physical oil business.

In a 23-page application to the U.S. Department of Energy's Office of Fossil Energy submitted in May, the Wall Street bank outlined a proposal to build, own and operate a compression and container loading facility near Freeport, Texas, which will have capacity to ship 60 billion cubic feet a year of compressed natural gas (CNG).

While the size of the project is small compared with bigger liquefied natural gas (LNG) projects, the plan highlights the bank's ability to exploit its status as one of two Wall Street banks which are allowed to own and operate infrastructure for the manufacture, storage and operation of raw materials. The other one is Goldman Sachs.

Their physical commodities activities were both "grandfathered" in when they became bank holding companies during the financial crisis more than five years ago.

It also showcases a nimble and novel approach to exporting cheap domestic gas that could replace oil for power plants in Caribbean nations, as the United States pumps out record amounts of gas from its fracking revolution.

The strategy skirts the multibillion-dollar upfront investments, long lead times and stringent application processes associated with building liquefied natural gas (LNG) terminals in favor of using readily-available containers and inexpensive container ships, in one of the first projects of its kind.

The bank plans to ship CNG to countries with which the U.S. has free trade agreements, including the Dominican Republic, Panama, Guatemala, El Salvador, Honduras and Costa Rica, according to the filing, which has not been previously reported.

Those countries now mainly use oil for their power plants. Natural gas, which in the U.S. is often used to power trucks and buses, could provide a cheaper alternative.

"You can collect U.S. gas at $4, it costs you $1 to ship it and gasify it, you bring it in at $5 and the equivalent that they are paying for fuel is $20 plus," said a person familiar with the project. "There is a lot of money to be made."

A spokeswoman for Morgan Stanley declined to comment on the plan beyond the contents of the filing.

"VERY SIGNIFICANT"

The boom in natural gas production in the U.S. has pushed prices down to $4.02 per million British thermal units. Natural gas contracts sold outside of the U.S. are often linked to higher-priced oil, which can inflate the cost of the gas.

The U.S. Energy Information Administration projects total domestic natural gas production to hit 73.9 billion cubic feet per day, portending sustained low prices going forward. About 1,000 cubic feet of natural gas yields 1 million BTU. One barrel of oil is roughly equivalent to 5,800 cubic feet of natural gas.

Billions of dollars are being poured into sophisticated export terminals for LNG, which require specialized equipment to cool the fuel to turn it into a liquid, as well as infrastructure to warm it at the receiving end, and take years to build.

Cheniere Energy, for example, is investing $5.6 billion to expand its Sabine Pass terminal in Louisiana to export LNG, which is expected to be operational by 2015.

The permitting process is also lengthy, with almost two dozen applications awaiting approval.

By contrast, the source familiar with Morgan Stanley's plans estimated the cost of building the plant at $30 million to $50 million, with minimal investment needed on the receiving end. The bulk of the expenditure would be in buying thousands of containers to ship the gas.

"They'll lease some land, buy some cranes," he said. "But you need literally thousands of these containers."

It will take 12 months to complete the plant from the time Morgan Stanley receives final regulatory approvals, according to the filing.

In November 2013, Florida-based energy company Emera CNG LLC applied to export 9.125 billion square feet a year; the status of its application is not clear and its lawyers and executives did not return calls for comment in time for publication.

Andy Weissman, an energy lawyer at Haynes Boone in Washington, said the Morgan Stanley proposal was one of the first such CNG export projects he was aware of.

"This could be something very significant, and if it was done successfully, there would undoubtedly be more of these," he said.

LOGISTICS NIGHTMARE

The 50-acre proposed site in Texas is currently being inspected for suitability, according to a second source familiar with the plans. Freeport is a deepwater port on the Gulf of Mexico with a 45-foot draft, and already receives large container ships carrying tropical fruits imported by Dole and Chiquita.

Morgan Stanley will lease pre-existing loading docks there, but plans to supply the containers itself, said the second source.

According to the filing, gas would be piped into the proposed facility on an 11-mile third-party pipeline connected to the Brazoria Interconnector Gas Pipeline (BIG), which moves natural gas within Texas. Gas that travels in a pipeline is already compressed.

After further compressing and containerizing the gas, Morgan Stanley can load the pressurized natural gas containers on standard container ships.

"It's a logistics nightmare, putting [the gas] in containers and shipping them around - it's hard to do. Most people can't figure out how to make money doing it," said the second source.  "For once, the price of gas is low enough that it makes sense."

GRANDFATHER STATUS

The project marks a new foray into the physical commodity market for Morgan Stanley after it sold the bulk of its physical oil operations, ending its long run as the biggest physical oil trader on Wall Street amid intense regulatory pressure.

The assets included oil storage and transport company TransMontaigne Inc [TMG.UL] as well as its global physical oil trading operation, which it has agreed to sell to Russia's Rosneft.

Thanks to a provision in the 15-year-old Gramm-Leach-Bliley Act, Morgan Stanley and Goldman Sachs alone among Wall Street banks enjoy "grandfather" status for any commodities activities they engaged in before 1997, although the provision has never been publicly interpreted by the banks' regulators at the Federal Reserve.

It was unclear whether the bank was using its grandfathered status to undertake the natural gas plant. However, the appointment of two of its commodities executives as officers of the natural gas subsidiaries indicates they could have more day-to-day control than in an arm's-length investment done under merchant banking authority.

The application is filed under the name Wentworth Gas Marketing LLC, a Delaware company with a business address in Purchase, New York, home to Morgan Stanley Capital Group, its commodities group.

Wentworth Gas Marketing and another company, Wentworth Compression LLC, are both wholly owned by Wentworth Holdings LLC, which is indirectly owned by Morgan Stanley.

The filing contains an agreement that Wentworth Compression will sell CNG to Wentworth Gas Marketing , which is signed by two Morgan Stanley commodities executives, Deborah Hart and Peter Sherk.

Hart, whose LinkedIn profile lists her as Morgan Stanley's chief operating officer North American Power & Gas, is a vice president of Wentworth Compression. Sherk, a managing director and co-head of commodities trading, is a vice president of Wentworth Gas Marketing.

The Federal Reserve declined to comment on the natural gas project, and Morgan Stanley did not answer questions about what authority it was using to pursue it.

The filing for the project landed just months before the bank bought Deutsche Bank's North American natural gas trading book.

(Reporting by Anna Louie Sussman, editing by Josephine Mason and John Pickering in New York)

Permalink Reply by 015334grltd9m on August 29, 2014 at 10:56am

What a concept! Once again jack you bring forth vision.

Permalink Reply by Nancy LeNau on August 29, 2014 at 10:40pm

WOW !!!!   Thank you JACK  STRAW !!!    Great Information !!!

Permalink Reply by Jack Straw on September 2, 2014 at 11:06am

Source: http://finance.yahoo.com/news/dominion-duke-build-5b-natural-123641...

Dominion, Duke propose $5B natural gas pipeline

Dominion, Duke propose huge new natural gas pipeline from West Virginia to North Carolina

By Jonathan Fahey, AP Energy Writer 1 hour ago

NEW YORK (AP) -- Dominion Resources, Duke Energy and other partners are proposing a $5 billion natural gas pipeline to connect the Southeast with the prodigious supplies of natural gas being produced in Pennsylvania, Ohio and West Virginia.

Gas is being relied upon to generate more of the nation's electricity in recent years because enormous new domestic supplies have drastically lowered its price and because natural gas burns cleaner than the nation's other most important fuel for electric power, coal.

The 550-mile project, called the Atlantic Coast Pipeline, would begin in Harrison County, West Virginia and stretch through Virginia and North Carolina to Robeson County, near the South Carolina border. It's designed to tap the rapidly growing supplies of gas produced in two geologic formations, known as the Marcellus and Utica shales, that are now generating more than a quarter of the nation's natural gas. In the past, the Southeast has received nearly all of its gas from more traditional gas-producing states of Louisiana, Texas and Oklahoma.

Utilities prefer having diverse sources of fuel to reduce shortages and price spikes that can arise in terms of high demand, such as hot summers or cold winters.

Clean air and clean water regulations — some already approved and some in the process of being finalized — are expected to make burning coal more difficult and expensive in the future. In response, utilities are preparing for increased use of natural gas.

Burning natural gas emits almost none of the toxic chemicals and particulate matter that burning coal produces, and about half of carbon dioxide, which scientists say is responsible for climate change.

Natural gas does have its own environmental drawbacks, however. When the gas leaks or is otherwise released directly into the atmosphere it heats the planet much faster than carbon dioxide. And the drilling technique that has led to increased U.S. supplies, called fracking, has raised concerns about water use, water contamination and other issues.

The pipeline is estimated to cost between $4.5 billion and $5 billion to build. It would carry 1.5 billion cubic feet of natural gas per day. By comparison, the U.S. consumed 71 billion cubic feet of gas per day last year, according to the Energy Department.

The pipeline requires approval from the Federal Energy Regulatory Commission. The pipeline partners, which include Piedmont Natural Gas and AGL Resources, expect to receive approval by mid-2016 and to start operating the pipeline in 2018.

The pipeline's customers will include six utilities, including Duke Energy subsidiaries, Piedmont Natural Gas, Dominion's Virginia Power and PSNC Energy, which will use the gas to generate electricity and to serve industrial and residential customers who need gas for manufacturing and heating.

Jonathan Fahey can be reached at http://twitter.com/JonathanFahey .

Permalink Reply by Jack Straw on September 3, 2014 at 9:52pm

Source: http://www.hardassetsinvestor.com/features/6207-fracking-makes-sand...

Written by Tom Vulcan  |

September 03, 2014

Fracking Makes Sand The New Hot Commodity; What You Need To Know

Frac sand is being produced and consumed in greater quantities by unconventional resources industries, and the trend looks set to continue. But what is frac sand?

What is the connection between delays on Amtrak's "Empire Builder" train between Chicago and Seattle and a $680 million equity and debt investment by KKR?

The answer: sand.

This is not any old sand we're talking about. It's not the sort of sand to send children quietly to sleep at night. It's the sort of sand that's now both raising hackles and money: frac sand.

Why is it so important? Because it's critical for fracking. And there's a fracking boom in the U.S.

Frac sand is what, in the industry, is called a "proppant." Essentially, proppants "prop" or keep open the cracks and pores in the rock after it has been fractured ("fracked") so that the oil, gas and natural gas liquids can be pumped out.

Shale Oil Extraction

Source: BBC.com

While raw sand is not the only proppant—e.g., ceramic beads of sintered bauxite, kaolin and alumina, and resin-coated sand and ceramics are also used as proppants—it's the most widely used.

U.S. silica estimates that around 90 percent of proppant volume is based on sand and, in March this year, Hi-Crush Partners, a premium monocrystalline sand producer and supplier, based on research from the Freedonia Group, indicated: "Raw sand [is] projected to increase as a percentage of proppant market, averaging at least 80 percent by volume." (With the explosion in fracking and the use of frac sand in just this last year, it's difficult to know how, with the higher consumption figures, the proportions of the different proppants may have changed. But these are useful as indications.)

Proppant Consumed by Volume

Source: Hi-Crush Partners, sourced from Freedonia Group, August 2013

There are a number of different types of raw fracking sand, including Brady, Brown Sand, Northern White and Texas Gold.

 

Sintered Bauxite

Alumina-Ceramic Beads

Source: EC21	Source: CBP Engineering Corp.

To be any good as a proppant, the silica/quartz, or frac, sand needs to be/have:

• Crush resistant, resisting pressures up of 4,000-6,000 pounds per square inch
• Low acid solubility – solubles are usually washed out when the sand is processed
• Low turbidity – silt-clay size minerals in the sand are also usually washed out when the sand is processed
• Round grained so that there is as little turbulence as possible when it is transported in the hydraulic fracturing liquid. (The current frac sand standard – RP 56 – set by the American Petroleum Institute (API), requires a roundness and sphericity ≥ 0.6 – based on the work of methodology of Krumbein & Sloss)
• High purity quartz (API: 99+ percent SiO₂)
• Of specified size fractions (see diagram below). Some 90 percent falls within the shaded range
  
  Size Fractions

 

Sieve Opening Sizes (µm)	3350/1700	2360/1180	1700/850	1180/600	850/425	600/300	425/212	212/106
Frac Sand Size Designations	b 6/12	b 8/16	a 12/20	b 16/30	a 20/40	b 30/50	a 40/70	b 70/140

 

It also needs to be matched to the particular job—fracs differ for many reasons, e.g., rock type, basin, etc., and having the right proppant is vital.

Any Old Sand and Frac Sand

Source: Wisconsin Academy

As the fracking industry grows, so does the need for sand, in big numbers: A single well may need anywhere between 1 and 4 million pounds of frac sand with which to be "stimulated." In other words, according to U.S. Silica's CEO, on average, 25 railcars of sand are needed to frack one well.

Why The Sand?

According to estimates from the U.S. Geological Survey (USGS), the U.S. is by far the world's largest producer of industrial sand and gravel. It's also a significant exporter of both, to the tune of some 8.4 percent of the country's domestic production.

 

Industrial Sand and Gravel: Estimated World Mine Production – 2013 (Million Tons)

Source: USGS

Also according to the USGS, currently the majority of all the sand and gravel the U.S. produces, some 62 percent, is "used as hydraulic fracking sand and well-packing and cementing sand," with industry and government experts estimating a production figure of 25-30 million metric tons for frac sand alone.

Domestic Consumption of Industrial Sand and Gravel in the USA - 2013

Source: USGS

In 2013, according to the USGS, this sand and gravel was produced in the U.S. by 120 companies with 177 operations in 31 states.

By tonnage produced, the leading states were:

 

 

• Wisconsin
• Illinois
• Texas
• Minnesota
• Oklahoma
• Arkansas
• Michigan
• Iowa

 

In its latest Minerals Yearbook (2012), the USGS describes the Ordovician St. Peter Sandstone in the Midwest as being "a primary source of silica sand for many end uses, including frac sand. Mined in five states, frac sand from the St. Peter Sandstone is within reasonable transport distance to numerous underground shale formations producing natural gas."

St Peter Sandstone Formation

Source: Industrial Minerals

 

A Growth Market – And Some!

In 2010, Wisconsin could boast only five sand mines and five processing plants. By the end of 2013, it was estimated that 100 sand mines, loading and processing facilities had received permits.

On a countrywide basis, in third quarter 2013, PacWest expected "…US land proppant consumption for well stimulation to increase from 51 billion pounds in 2011 to 83 billion pounds in 2015, equal to an 12.9 percent compound annual growth rate," with sand accounting for "most of the growth in market demand" and proppant consumption to grow at 9 percent per annum between 2013 and 2015.

Not even a full year later, The Wall Street Journal was reporting that "[f]rackers are expected to use nearly 95 billion pounds of sand this year, up nearly 30 percent from 2013 and up 50% from forecasts made by energy-consulting firm PacWest Consulting Partners a year ago."

But even these figures may underestimate the size of the market that PropTester in an update back in June, to its 2013 proppant market report, noted:

"North America, which consumes a vast majority of proppant worldwide, experienced robust activity during the first two quarters of 2014. Despite significant weather related issues during 1Q 2014, demand is trending over 25 percent of annualized 2013 demand and well over 50 percent in select regions. Increases of 30 percent or more in base proppant demand are now expected through the remainder of 2014 in North America (as compared to 2013 annualized demand)."

Its 2013 Proppant Market Report indicated "the proppant market exceeded 45 million tons (90 billion pounds) in 2013, a 28 percent increase compared to 2012."

One reason projected consumption has been jacked up significantly is the discovery that if more sand is used, output rises. And according to energy analysts at RBC Capital Markets (quoted in the same WSJ piece), while "[a]bout a fifth of onshore wells are now being fracked with extra sand, …the technique could expand to 80 percent of all shale wells."

As consumption has increased, so too have sand prices. Back in 2008, most types of industrial silica sand cost an average of $30.82 per ton. By 2012, the price of such sand was an average of $44.78 per ton, with high-quality frac sand costing as much as $55 per ton.

In 2013, the price of this high-quality sand rose to an average of average of $75 per metric ton. According to another article in The Wall Street Journal, having already risen this year, "Laura Fulton, chief financial officer of Hi-Crush Partners L.P., is predicting another 5 percent to 10 percent increase in sand prices before year's end."

 

Opportunities?

Sand and gravel producers in the U.S. are a mixture of both private and public companies. Among the largest are:

 

Company	Ticker
Badger Mining Corporation	Privately owned
Fairmount Santrol (Fairmount Minerals)	Majority owned by American Securities Capital Partners
Hi-Crush Partners LP	HCLP:US
Pattison Sand Co., LLC	Privately owned
Preferred Sands	Privately owned (recent major investment by KKR)
Premier Silica LLC	Privately owned
Proppant Specialists, LLC	Privately owned
U.S. Silica Holdings, Inc	SLCA:US
Unimin Corp	Privately owned by Sibelco Group, Belgium

If you're looking at a direct investment in frac sands, currently there are only a few public companies of any size: Hi-Crush Partners and U.S. Silica. Emerge Energy Services LP (EMES:US), owner of Superior Silica Sands, which, very successfully, went public on the NYSE last year, is both a fuel processing and distribution company and a silica sand producer. But there have been rumors that Fairmount may be looking at an IPO.

 

Large ceramic proppant producers include CARBO Ceramics Inc. (CRR:US) and Saint-Gobain (SGO:FP).

Smaller frac sand producers include:

• Chieftain Sand, Inc.
• Heemskirk Canada Limited (Owned by Australian company Heemskirk Consolidated Limited (HSK:AU)
• Northern Frac Proppants
• Smart Sand Inc.
• St Peter Sand Company LLC

 

Some other companies in the frac sand "space" that may be worth watching are:

• Atlas Resin Proppants, LLC
• Canadian Sand & Proppants LP
• Canfrac Sands Ltd
• Erna Frac Sand, L.C.
• J5Global, LLC
• Jayhawk Frontier Exploration Ltd (Exploration)
• Manley Bros. of Indiana, Inc.
• Mississippi Sand, LLC.
• Pattison Sand Company, LLC
• Sargent Sand Co.
• Stikine Energy Corp. (SKY:CN)
• Taylor Frac

 

 

There are also, now, a number of Chinese ceramic proppant manufacturers, Sichuan FultonTec Co. Ltd, for example, which may also be worth keeping an eye on.

As for that debt and equity investment recently made by KKR, that was the $680 million its special situations fund announced at the end of July was going to be pumped into Preferred Sands, one of North America's largest frac sands producers, to keep it in business.

While opportunities to invest directly in frac sands may be circumscribed by the dearth of publicly quoted companies out there, indirect investment opportunities in the frac sands "phenomenon" may not be so circumscribed.

On a number of occasions, particularly in the press, frac sand has been equated in one way or another with gold, and current demand for it a "gold rush." If that's the case, there should be indirect opportunities in the services necessary to support it—as there have been in previous "gold rushes."

Two such services that may offer opportunities are:

Shipping & Logistics

Frac sand resources are often located at a distance from where they are actually needed, e.g., in New Mexico, North Dakota and Pennsylvania. However, oil drillers' preferences may also dictate obtaining frac sand from a particular region and of a particular type such as Wisconsin White, the grains of which are especially round—even if the source of the sand may be nowhere near where they are operating.

However, the sand needs to get to the wells. And the railways in North America are getting it there. Whether Class 1 like BNSF, the Canadian National Railway Company, Union Pacific Railroad or the very much smaller Progressive Railroad, rail companies in the U.S. are shipping many—often thousands—of railcars of frac sand each year. The volume is rising and so, often, is their investment in the sand "boom" among other things in cars, new lines and infrastructure.

That said, though, those who ship by rail are starting to express concerns "that the U.S. rail network won't be able to handle rapidly rising traffic volumes, resulting in higher transportation costs and lost sales." Not least because "[g]rowth in frac sand and oil shipments connected with the domestic energy boom is further pressuring the network."

However, it's not only the freight customers of the railways who are concerned; those who like or need to travel by train are also feeling the effects of this increase in traffic.

 

 

A case in point is the current plight of passengers on Amtrak's "Empire Builder." Effective until Sept. 30 this year, Amtrak has the following advisory on its website: "Passengers traveling aboard Empire Builder trains can encounter significant delays due to very high volumes of freight train traffic along the route. During the two week period ending August 2, 2014, trains encountered delays of approximately three to six hours. While delays to the Empire Builder have primarily been occurring west of St. Paul, MN, passengers should anticipate delays in both directions." As ever, passengers rank behind freight.

Shipping sand, however, is not just railroads: Trains may take it from point C to point D, but the sand might be mined at point A, processed at point B and go down the well at point E.

Getting from A to E may involve such other stages as transfer and transport by truck from processor to rail head (transloading), transfer and transport from rail head to well (transloading), intermediate storage, etc.

Very often these other stages will be the responsibility of specialist logistics companies, for example, Enserco Midstream LLC which, to address just such market opportunities, bought Frac Resources, LLC in January of this year.

Indeed, frac sands logistics is such a booming business that the 2nd Annual Frac Sand Logistics & Market Forecast Summit USA 2014 is will take place in Houston at the end of October.

Conclusion

The fracking boom is going to be here in the U.S. for a while. And frac sand will continue to play an integral part in the exploitation of unconventional resources, as will all the infrastructure that supports it on its journey from mine to well.

There is also every likelihood that the exploitation of unconventional energy resources—particularly fracking—will become more prevalent outside the U.S. If it does, the demand for frac sand will increase further.

Looking for the right opportunities, at the right time, and in the most promising segment(s) of the market should be very interesting.

Permalink Reply by Jack Straw on September 5, 2014 at 12:36pm

Source: http://www.eia.gov/energy_in_brief/article/shale_in_the_united_stat...

Shale in the United States

Last Updated: September 4, 2014

Over the past decade, the combination of horizontal drilling and hydraulic fracturing has provided access to large volumes of oil and natural gas that were previously uneconomic to produce from low permeability geological formations composed of shale, sandstone, and carbonate (e.g., limestone).

Shale is a fine-grained sedimentary rock that forms from the compaction of silt and clay-size mineral particles. Black shale contains organic material that can generate oil and natural gas, and that can also trap the generated oil and natural gas within its pores.

Where are shale gas and oil resources found?

Shale oil and natural gas resources are found in shale formations that contain significant accumulations of natural gas and/or oil. The Barnett Shale in Texas has been producing natural gas for more than a decade. Information gained from developing the Barnett Shale provided the initial technology template for developing other shale plays in the United States. Another important shale gas play is the Marcellus Shale in the eastern United States. While the Barnett and Marcellus formations are well-known shale gas plays in the United States, more than 30 U.S. states overlie shale formations.

Within an individual shale play, geophysicists and geologists identify suitable well locations in areas that have the greatest potential to produce commercial volumes of natural gas and oil. These areas are identified using rock core samples and geophysical and seismic technologies to generate maps of the subsurface hydrocarbon resources in a shale formation.

Shale gas, tight gas, and tight oil

The oil and natural gas industry generally distinguishes between three categories of low-permeability formations:

• Shale natural gas
• Tight natural gas
• Tight oil (can be produced from shale or other low-permeability reservoirs)

Shale natural gas

The advent of large-scale natural gas production from shale began around 2000, when shale gas production became a commercial reality in the Barnett Shale located in north-central Texas. The production of Barnett Shale natural gas was pioneered by the Mitchell Energy and Development Corporation. During the 1980s and 1990s, Mitchell Energy experimented with alternative methods of hydraulically fracturing the Barnett Shale. By 2000, the company had developed a hydraulic fracturing technique that produced commercial volumes of shale gas. As the commercial success of the Barnett Shale became apparent, other companies started drilling wells in this formation so that by 2005, the Barnett Shale was producing almost half a trillion cubic feet (Tcf) of natural gas per year. As natural gas producers gained confidence in their ability to profitably produce natural gas in the Barnett Shale, with additional confirmation provided by well results in the Fayetteville Shale in northern Arkansas, producers started developing other shale formations, including the Haynesville in eastern Texas and north Louisiana, the Woodford in Oklahoma, the Eagle Ford in southern Texas, and the Marcellus and Utica shales in northern Appalachia.

Tight natural gas

The identification of tight natural gas as a separate production category began with the passage of the Natural Gas Policy Act of 1978 (NGPA), which established tight natural gas as a separate wellhead natural gas pricing category that was permitted to obtain unregulated market-determined prices. The tight natural gas category was designed to give producers an incentive to produce high-cost natural gas resources when U.S. natural gas resources were believed to be increasingly scarce.

As a result of the NGPA tight natural gas price incentive, these resources have been in production since the early 1980s, primarily from low-permeability sandstones and carbonate formations, with a small production volume coming from eastern Devonian shale. With the full deregulation of wellhead natural gas prices and the repeal of the associated Federal Energy Regulatory Commission (FERC) regulations, tight natural gas no longer had a specifically defined meaning, but generically still pertains to natural gas produced from low-permeability sandstone and carbonate reservoirs.

Notable tight natural gas formations include, but are not confined to

• Clinton, Medina, and Tuscarora formations in Appalachia
• Berea sandstone in Michigan
• Bossier, Cotton Valley, Olmos, Vicksburg, and Wilcox Lobo along the Gulf Coast
• Granite Wash and Atoka formations in the Midcontinent
• Canyon formation in the Permian Basin
• Mesaverde and Niobrara formations in multiple the Rocky Mountain basins

Does the United States have abundant shale resources?

Yes, the United States has access to significant shale resources. In the Annual Energy Outlook 2014, EIA estimated that the United States has approximately 610 Tcf of technically recoverable shale natural gas resources and 59 billion barrels of technically recoverable tight oil resources. As a result, the United States is ranked second globally after Russia in shale oil resources and is ranked fourth globally after China, Argentina and Algeria in shale natural gas resources.

Learn more

• Related articles and animated maps
• Annual Energy Outlook 2014 Early Release
• Annual Energy Outlook 2013
• Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays
• Modern Shale Gas Development in the United States: A Primer
• Technically Recoverable Shale Oil and Shale Gas Resources: An Asses...
• EIA Oil and Gas Maps
• EIA Natural Gas Data

Permalink Reply by Jack Straw on September 5, 2014 at 6:05pm

Source: http://fuelfix.com/blog/2014/09/05/enterprise-and-kinder-morgan-to-...

Enterprise and Kinder Morgan to gauge demand for new pipelines

Posted on September 5, 2014 at 10:23 am by Robert Grattan in Crude oil, Natural gas liquids, Pipelines

HOUSTON — Enterprise Product Partners and Kinder Morgan Energy Partners are evaluating demand for two proposed pipelines serving the Utica region in Ohio and the Williston Basin region of North Dakota.

Enterprise said late Thursday it would begin taking commitments from shippers for a proposed pipeline running from North Dakota’s Williston Basin to the trading hub in Cushing, Oklahoma. The 1,200 mile project is a 30-inch line that would move 340,000 barrels per day of crude oil. If expanded, capacity could rise to more than 700,000 barrels per day, the company said in a statement.

The pipe would also serve the Powder River and Denver-Julesburg Basins.

The Bakken-to-Cushing pipeline could transport six grades of crude oil and products, including Rockies condensate and processed condensate. If Enterprise determines there’s significant demand, the first section of the pipeline — stretching from the Denver-Julesburg basin to Cushing — could be operational by the fourth quarter of 2016, with the rest following by the third quarter of 2017, the company said.

The Kinder Morgan project, its previously announced Utica to Ontario Pipeline Access project, will focus on ethane and ethane-propane mixture coming from the Utica area. The 240-mile, 12-inch pipeline could run from Harris County, Ohio to Kinder Morgan’s Cochin Pipeline near Riga, Michigan. Once in Michigan, the product would flow east to Ontario.

The Kinder Morgan project could transport an initial 50,000 barrels per day of refined natural gas liquids, with an option to expand to 75,000 barrels per day.

If the Kinder Morgan judges there’s enough demand for the line and the project gets regulatory approval, the new pipeline could be operational by 2018.

Both Kinder Morgan and Enterprise Product Partners are based in Houston.

Permalink Reply by Jack Straw on September 11, 2014 at 12:37am

Source: http://phys.org/news/2014-09-residual-hydraulic-fracturing-groundwa...

Residual hydraulic fracturing water not a risk to groundwater, study says

13 hours ago

 
Read more at: http://phys.org/news/2014-09-residual-hydraulic-fracturing-groundwa...

Sixty-one minutes of imbibition and evaporation of a 154 microliter bead of tap water on a 2.3 gram chip of the Union Springs Member of the Marcellus Formation. The drop disappeared in approximately 100 minutes. The photograph labeled 0 min was taken about 10 seconds after the bead was dropped on the Marcellus chip. Counter-current imbibition is indicated by methane bubbles floating up into the water bead from the Marcellus chip, starting on the left side of the bead at time = 0 min. This experiment was started 5 days after receiving fresh cuttings of the Union Springs from a horizontal well in PA. Credit: Engelder, Penn State

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Hydraulic fracturing—fracking or hydrofracturing—raises many concerns about potential environmental impacts, especially water contamination. Currently, data show that the majority of water injected into wells stays underground, triggering fears that it might find its way into groundwater. New research by a team of scientists should help allay those fears.

In a paper published in the current issue of the Journal of Unconventional Oil and Gas Resources, Terry Engelder, professor of geosciences, Penn State; Lawrence Cathles, professor of earth and atmospheric sciences, Cornell University; and Taras Bryndzia, geologist, Shell International Exploration and Production Inc., report that injected waterthat remains underground is sequestered in the rock formation and therefore does not pose a serious risk to water supplies.

Hydraulic fracturing is a drilling technique commonly used to extract gas from previously inaccessible "tight" gas reserves, including gas trapped in shale formations such as the Marcellus. During this technique between 1.2 and 5 million gallons of water mixed with sand and chemical additives are injected at high pressure into each well to fracture the rock and release the gas.

Typically less than half of the injected water returns to the surface as "flowback" or, later, production brine, and in many cases recovery is less than 30 percent. In addition to the chemical additives, flowback water contains natural components of the gas shale including salt, some metals, and radionuclides and could impair water quality if released without proper treatment. While flowback water can be managed and treated at the surface, the fate of the water left in place, called residual treatment water or RTW, was previously uncertain.

Some have suggested that RTW may be able to flow upward along natural pathways, mainly fractures and faults, and contaminate overlying groundwater. Others have proposed that natural leakage of the Marcellus is occurring without human assistance through high-permeability fractures connecting the Marcellus directly to the water table and that hydraulic fracturing could worsen this situation.

The researchers report that ground water contamination is not likely because contaminant delivery rate would be too small even if leakage were possible, but more importantly, upward migration of RTW is not plausible due to capillary and osmotic forces that propel RTW into, not out of, the shale. Their study indicates that RTW will be stably retained within the shale formation due to multiphase capillary phenomena.

"Capillary forces and coupled diffusion–osmosis processes are the reasons the brines and the RTW are not free to escape from gas shale," said Engelder. "The most direct evidence of these forces is the observation that more than half the treatment waters are not recovered. Introducing treatment water causes gas shale to act like a sponge based on the principles of imbibition.

"Imbibition into gas shale is made possible by the high capillary suction that a fine-grained, water-wet shale matrix can exert on water. As water is wicked into gas shale, the natural gas in the shale is pushed out. The capillary forces that suck the RTW into the gas shale keep it there."

Estimating imbibition is complicated, but simple experiments conducted by the researchers show that water can be readily imbibed into gas shale in quantities fully capable of sequestering RTW. The researchers demonstrated this process in a series of experiments on cuttings recovered from the Union Springs Member of the Marcellus gas shale in Pennsylvania and on core plugs of Haynesville gas shale from NW Louisiana.

"The hydraulic fracturing fluid consists mostly of very low-salinity surface water, while the shale contains high concentrations of water soluble inorganic cations and anions," said Engelder. "During hydraulic fracturing water is lost to the formation while inorganic cations and anions are transferred from the formation to the hydraulic fracture. Diffusion osmosis assists the rapid imbibition of water by the shale and diffusion of ions into the treatment water causing the high salinities observed in flowback fluids. The point to be emphasized here is that this osmotic pressure pushes the hydraulic fracture fluids into the shale matrix, expelling gas and cations to make high-salinity flowback in the process."

The researchers believe that in addition to there not being enough water in the shale to contaminate groundwater, the most important point of their work is that multiphase capillary phenomena must be considered in cases where a non-aqueous fluid is present in the subsurface pore space. The vadose zone—the area from the surface to the groundwater—and oil and gas migration cannot be understood using single-phase, porous-media flow methods, and any policy insights or prescriptions based on single-phase considerations will be fatally flawed, they argue.

"The practical implication is that hydrofracture fluids will be locked into the same 'permeability jail' that sequestered overpressured gas for over 200 million years," said Engelder. "If one wants to dispose of fracking waters, one could probably not choose a safer way to do so than to inject them into a gas shale."

Permalink Reply by pg guy on September 11, 2014 at 8:45am

Thanks for posting this, Jack.  An abbreviated version appeared in the local newspaper this morning.  I encourage you to start a new thread with this article, as IMHO it is one the most significant research projects in the last several years.  It will be interesting to see how the anti-gas crowd twists themselves into knots trying to discredit or minimize this bit of science.  They've already made up their minds, so these are more facts to confuse them.

Permalink Reply by Jack Straw on September 11, 2014 at 11:35am

Source: http://in.reuters.com/article/2014/09/11/iea-oil-usa-saudi-idINL5N0...

U.S. shale squeezing out Saudi oil imports, boosting gasoline exports-IEA

By Libby George

LONDON, Sept 11 Thu Sep 11, 2014 5:41pm IST

(Reuters) - North America's shale oil boom has started to squeeze Saudi Arabian oil out of the U.S. market in the same way it did with West African crude, the West's energy agency said on Thursday.

The International Energy Agency also predicted a flood of U.S. gasoline exports to world market.

"In recent years, surging light tight oil production has backed out U.S. imports of West African crude, which are now moving to Asia," the IEA said in a monthly report.

"Saudi exports seem to be showing the beginning of a similar shift," it said, estimating that Saudi exports have likely run below 7 million barrels per day for the last four months, their lowest level since September 2011.

"Exports to the U.S. led the drop amid rising Saudi domestic demand for crude burn and refinery runs," the IEA said. Saudi Arabia was pricing oil out of the U.S. markets by keeping official selling prices high while adjusting them down for Asia, it added.

The North American supply boom has not only cut crude imports into the United States but also turned it into a net products exporter - in sharp contrast with previous decades when it was the largest importer in the world.

"In coming years... U.S. light distillate exports will reach increasingly far-flung markets," said the IEA, which estimates that Canada and the United States could have a surplus of naphtha and gasoline of around 1.3 million barrels per day by 2019.

Planned expansion at Valero and Marathon refineries to process more of the light tight oil extracted from U.S. fields will add to the glut, the IEA said.

Most of Europe's refineries were designed to produce gasoline for American drivers.

For a factbox on closed European refineries see (Editing by William Hardy)

Permalink Reply by Jack Straw on September 11, 2014 at 3:12pm

Mexico is substituting CHEAP U.S. Natural Gas for (more) valuable Oil (allowing more Oil to be exported). JS

Source: http://www.wallstreetdaily.com/2014/09/03/mexico-natural-gas/

U.S. Natural Gas Export Boom Quietly Begins

Published Wed, Sep 3, 2014  |  Tim Maverick, Staff Writer

While many are breathlessly waiting for liquefied natural gas (LNG) exports from the United States to begin in 2015, there’s a natural gas export boom already happening right under the noses of most investors.

I’m talking about rapidly growing gas exports from the United States to our southern neighbor, Mexico. LNG exports, which are travelling via pipeline, are at their highest levels ever and growing.

Soaring Demand South of the Boarder

Mexico’s national energy secretary (SENER) reports that U.S. natural gas exports to Mexico doubled between 2009 and 2013. Exports in 2013 alone averaged 1.8 billion cubic feet (bcf) per day, and SENER predicts that will more than double by 2018 to 3.8 bcf per day.

Citigroup (C) is even more aggressive with its forecast, saying that Mexico will import approximately 5 bcf of U.S. natural gas per day by 2018.

The exact amount will likely depend on how quick Mexico’s new energy revolution unfolds.

The chart below shows Mexico’s projected natural gas imports for the next 25 years. All imports from the United States are expected to steadily rise.

The main reason for the uptick in imports is increased demand. Mexico plans to add at least 28 gigawatts of power generating capacity over the next 12 years.

This alone should boost natural gas demand by 5 bcf a day, since Mexico is adding a lot of gas-fired electric generating capacity. The country’s Federal Electricity Commission (CFE), confirms that natural gas will provide 72% of the total electricity generated by the country by 2027.

The New Manufacturing Powerhouse

Mexico’s need for additional power stems from the fact that more and more global manufacturers are moving operations there to take advantage of cheap energy prices. Boston Consulting Group says imports of cheap U.S. shale gas have reduced energy costs for companies in Mexico by 37% over the past decade.

Mexico is now a cheaper manufacturing hub than China!

The auto industry is one major manufacturer taking advantage of this new production environment. Mexico now makes a quarter of all vehicles imported into the United States.

Last year, Daimler AG (DDAIY) and Nissan Motor ADR (NSANY) announced plans to invest $1.4 billion to build compact luxury cars in Mexico. And on August 27, Kia Motors Corporation (KSE) announced a plan to build a $1 billion plant there.

Nissan already opened a $2-billion small-car plant there in 2012.

Many other auto companies are jumping onboard. In the past six months, BMW, Renault, Audi, Honda (HMC), and Mazda (MZDAF) have either begun manufacturing vehicles in Mexico or announced plans to do so.

The Biggest Beneficiary

But it’s not international manufacturers that are set to benefit the most from the natural gas export boom from the United States to Mexico.

The companies that are set to win this race will be the pipeline companies that transport gas from Texas gas fields – mainly the Eagle Ford Shale – to Mexico.

Mexico’s state-owned energy giant, Pemex, is building a $3.3-billion pipeline from the Eagle Ford to Mexico.

Among U.S. companies, Energy Transfer Partners, LP (ETP) recently received approval for an extension to an existing pipeline that will bring 140 million cubic feet of gas into Mexico a day. And the international unit of Sempra Energy (SRE) has a contract in Mexico to construct and operate a $1-billion gas pipeline.

But the biggest beneficiary here is Kinder Morgan (KMI), which already ships most of the gas going to Mexico, either directly or through its subsidiary, El Paso Natural Gas, and its Sierrita pipeline.

The company forecasts that it’ll spend approximately $3 billion over the next 15 years in order to build out the sufficient pipeline capacity to meet Mexico’s growing natural gas needs.

The reason?

KMI believes that Mexico will focus its energy on expanding its oil production instead of natural gas.

If KMI leadership is right, its midstream business in Mexico will be a bright spot for years to come.

And “the chase” continues,

Tim Maverick

Tim Maverick boasts decades of experience in the investment world. He spent 20 years at a major brokerage firm - as a trading supervisor and broker working directly with clients. Learn More >>

Permalink Reply by Jack Straw on September 11, 2014 at 10:03pm

The below link is to a rather nice tutorial on "Why investors closely monitor natural gas inventories"

Actually, in six parts, it goes beyond the above title.

It is too long to 'cut and paste' .... so I will simply supply the link (for those who wish to follow it):

http://marketrealist.com/2014/09/investors-closely-monitor-natural-...

It does give a (a very up to date)  simplified explanation of what is happening ... as an example ... the VERY EARLY Alberta Clipper that is presently heading down through Montana, the Dakotas, Eastern Colorado and Nebraska  means an early corn and grain harvest ... meaning the need for a lot of propane for drying of corn and grain (the less in dries in the field, the more it needs to be dried with propane).

The Natural Gas and NGL business is still very much driven by weather .... making sense of things (as an investor in O&G) is all about trying to figure out the 'circles within circles' .

The fore mentioned is a (well done) simplistic explanation of some of the types of things which professional (and amateur) investors take into consideration in making their investments ..... maybe some of you future Shaleionaires will soon want to look at becoming investors ;-)

JS

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