Europe Has Much To Learn About Shale (Unconventional) Gas

Before anyone gets too excited about the potential for shale gas or what some term "unconventional" gas potential in Europe, it must be recognized that there are political and environmental issues in Europe that are greatly different from those existing in the United States.

However, with the worldwide attention the problems with deepwater oil production in the Gulf of Mexico is receiving, the potential for finding and producing clean-burning natural gas, onshore, is drawing increasingly greater attention. The demand is there. The technology to find and produce this gas exists. It is the other problems which need to be overcome. Many countries in Europe could use an economic boost right now.
Peter

Does Europe Have Unconventional Gas?

(source)

It provides about half of the U.S. domestic natural gas production. And the U.S. product has already begun to shake up the market for gas in Europe. But the production of unconventional gas, which is usually tightly trapped in rocks and hard to extract, doesn’t seem likely to have a bright immediate future in Europe.

From a geological viewpoint, you could extract unconventional gas in Europe, according to Don Gautier, from the U.S. Geological Service. But that’s not the only thing that matters. Unconventional gas fields, particularly those tapping so-called shale gas, are very large and require the development of hundreds of wells.

Bloomberg

Chesapeake Energy drills on the Barnett Shale.

A field in northern Texas called Barnett Shale has about 8,000 wells covering an area roughly comparable to Belgium, the Netherlands and Luxembourg combined, Mr. Gautier says. “You can’t look at these wells as one well at a time, you have to look at thousands as a development plan,” says Mr. Gautier.

That is almost impossible for Europe, given high population density, regulatory difficulties of getting permits to drill over large areas that sometimes cross borders, and likely opposition from environmentalists and affected residents.

A new technology of digging horizontal wells — drilling vertically drill and then pushing out parallel to the ground — might offer some leeway.

Of course, all of this begs the main question: How much unconventional gas does Europe have and where are the main concentrations?

The country which promises most is Poland, where the government has granted concessions for research. However, the first exploration well is just being started, and the first estimates of how much gas is really there won’t come for four to five years, with production in 10 to 15 years, according to Ewa Zalewska, director of the department of geology and geological concessions at the Polish environment ministry.

“Shale gas is the gold rush of the 21st century,” she says. However, “it is too early to answer all the questions.”

Update: Perhaps by the time the first gas emerges, Bronislaw Komorowski, Poland’s likely next president, will have figured out that you don’t dig unconventional gas out of the ground like brown coal.

Shale Gas Potential In Eastern U.S. Growing

As all geologists know, organic-rich "shale" rock is a common rock type found nearly everywhere there are sedimentary rocks. This raises the question, can gas be produced from any, all, or some of these shales, in addition to the now well known Barnett, Haynesville and Marcellus Shales? The answer, at least in the northeastern United States seems to be a tentative yes. If certain environmental issues can be resolved, the future for increased drilling and production in these areas looks positive.

The energy the U.S. needs to heat our homes, generate our electricity, and power our vehicles must come from somewhere. Windmills and solar panels are gravely lacking in capacity for a host of reasons. Now with terrible problems caused by one notorious leaking offshore oil well and an outright ban on offshore drilling in deep water, the need for clean-burning natural gas is greater than ever.
Peter

Drillers testing other shale formations above and below the Marcellus strata

By Michael Bradwell, Business editor, mbradwell@observer-reporter.com

This article has been read 2210 times. (source)

Pennsylvania's geology has the potential of delivering natural gas from a variety of shale formations beyond the Marcellus strata, a geologist said last week.

But Dr. Terry Engelder, professor of geosciences at Penn State, who has spent 30 years studying the Marcellus, said the "super giant" shale formation is in no danger of losing its position as one of the world's largest gas fields.

"It's not just the Marcellus," Engelder acknowledged when asked about recent announcements by two drilling companies working in Pennsylvania that test wells have been completed in two other shale formations which lie above and below the Marcellus strata.

Range Resources spokesman Matt Pitzarella said the company has drilled some test wells into the "Rhinestreet" formation, which is part of the Upper Devonian shale that sits about 1,000 feet above the Marcellus strata. The company has also tested the depths below the Marcellus where the Utica formation lies.

"The tests were encouraging enought that they could be stand-alone shale plays in their own right," he said.

In Northeastern Pennsylvania, Cabot Oil & Gas Corp. told analysts last year it had drilled a successful horizontal well through the Purcell Limestone sandwiched between two layers of its Marcellus acreage.

Engelder noted that all of the shale formations can yield gas. He added that while reports of test wells in the other strata are just now emerging in Pennsylvania, some of them have been drilled in other parts of the country for some time.

He said Pittsburgh-based EQT has been drilling in Upper Devonian shale in Kentucky's Big Sandy play for some time.

The emergence of the other shale formations in Pennsylvania are so new, that no one yet knows their impact on the gas exploration industry or their economic impact.

"It's just really early now," Pitzarella said. "No one's really given much detail in terms of production data."

When the authors of a Penn State study detailing the projected economic impacts of the Marcellus Shale gas play released an update two weeks ago, they noted that their report did not consider development of other shale formations that exist above and beneath the Marcellus.

There are also some regulatory factors that could affect the future extraction of gas from shale.

Drillers face the incresed scrutiny from the Environmental Protection Agency, which is studying the effects of water pollution used in hydraulic fracturing used to release the gas from the tight shale formations. There are also several legislative proposals in Harrisburg to enact a severance tax on gas extracted from the Marcellus shale.

Both Engelder and Pitzarella said the other shale formations could be places that drillers could return to after the Marcellus acreage is more fully developed.

Despite the promise of gas yields from the other formations, Pitzarella said Range still views the Marcellus as its primary goal.

"The Marcellus is the best of the best" formations, he said.

Alberta Claims 1.5 TRILLION Barrels Of Oil

1.5 TRILLION barrels of oil is an eye-opening figure. Of course much of this is "heavy" oil, thick and viscous, and trapped in "tar sands" and carbonate rocks, waiting on "new technology" to be economically feasible. However, when compared with the now obvious perils of deepwater offshore drilling, it is looking better all the time.
Peter

Alberta sitting on nearly 1.5 trillion barrels, says ERCB

Province hikes bitumen estimate

By Shaun Polczer, Calgary HeraldJune 4, 2010 (Source)

CALGARY - A re-evaluation of emerging oilsands areas and advances in production technology have pushed Alberta’s bitumen resources toward 1.5 trillion barrels in 2009, according to a report by the Energy Resources Conservation Board.

According to the ERCB’s annual reserve report, which will be officially released today, the increase was driven by a re-evaluation of the largely untapped Grosmont deposit, which is now said to contain 406 billion barrels in the ground waiting for the right technology to extract it.

In situ oilsands production grew 14 per cent last year, along with a 14 per cent increase in mining output due in large part to the startup of Canadian Natural Resources’ Horizon mine, the report notes. But in situ is expected to be the strongest driver of future activity, said Carol Crowfoot, the board’s chief economist and report co-author.

“Particularly on the in situ side, we’re forecasting quite a growth rate for the next 10 years, due to the SAGD (steam assisted gravity drainage),” she said.

In situ oilsands production now accounts for about half of the 1.49 million barrels of bitumen produced per day, a figure that is expected to double to 3.2 million barrels per day by the end of the decade, the report said.

The Grosmont is a lesser-known fourth oilsands area — after Athabasca, Peace River and Cold Lake — that is unique because the bitumen is contained in limestone instead of sand. Producers have known about the Grosmont carbonates for decades, but lacked practical ways of getting it out of the ground.

Although the resource potential rose nearly 30 per cent in the first evaluation of the Grosmont reserves since 1990, no commercial reserves were assigned due to the lack of production.

That could change later this year when in situ players such as Laricina Energy begin constructing pilot projects aimed at testing new production technologies, including the application of solvents, to the previously unattainable bitumen.

The company is moving ahead with a commercial pilot at Saleski and hopes to be producing oil by the end of the year, Laricina president Glen Schmidt told the Herald on Friday.

He said he wasn’t aware of the revised resource numbers, but confirmed his company worked with the ERCB to help prepare the estimates.

“It is very exciting to see the ERCB start talking about the Grosmont,” he said.

“It is clearly the second-largest in situ play, by far. We like to give ourselves some credit for leading the charge.”

Companies such as Unocal attempted pilot projects in the 1970s and ’80s to no avail. In 2006, Sure Northern, a subsidiary of Royal Dutch Shell, spent more than

$500 million to buy Grosmont rights adjacent to 75,000 hectares controlled by Husky Energy.

Unlike a conventional in situ development, Schmidt said carbonates require less steam at lower temperature and pressure to drain the oil. Laricina is hoping that will in turn translate into lower operating costs.

“The better Grosmont projects will do every bit as good as the McMurray,” he said.

In other highlights of the report, the more commonly known McMurray-Wabiskaw deposit — characterized by truck and shovel mining — declined 0.4 per cent to 959 million barrels. Cold Lake was also re-evaluated for the first time since 1999, resulting in a 20 per cent drop in available resources to

33.8 billion barrels. The region is host to Alberta’s largest and oldest in situ development, operated by Imperial Oil.

The report notes Alberta has produced about seven billion barrels of raw bitumen since oilsands production first began in 1967, or less than half of one per cent of the available resource, compared with 16 billion barrels of conventional crude oil since 1914.

While oilsands production continues to rise, conventional oil declined almost nine per cent in 2009 to 461,300 barrels per day. About

3.5 billion barrels of conventional oil remain to be developed, although the report notes that new technology is starting to unlock “tight oil” in places such as the Pembina Cardium play.

Other big revisions were made to the province’s inventory of coal bed methane, which increased

90 per cent. Gas from coal accounted for seven per cent of Alberta’s total gas production in 2009, a figure that is expected to rise to

20 per cent by 2019, the report said.

Shale gas was expanded in the 2009 report, but no reserves were assigned to what could be a major new supply source in Alberta. As part of the Alberta government’s royalty holiday on new shale gas wells, the province last week initiated a study by the Alberta Geological Survey to determine the exact size and location of a resource that could top

850 trillion cubic feet.

“At the moment we don’t actually see enough data to do a calculation,” said Kevin Parks, who oversees the AGS. “But you have to start somewhere. We’re ramping up to generate our own reasonable numbers, what’s out there are kind of bold estimates.”

spolczer@theherald.canwest.com