Never mind that hydraulic fracturing was once again linked to an earthquake, this time a 4.0 tremor in Ohio on New Year’s Eve, the year 2012 kicked off in impressive fashion for the shale industry, which has been revolutionized by the controversial drilling practice.

Undaunted by the environmental and geological challenges, two oil giants signed shale deals in the United States for a combined US$4.5-billion ($4.58-billion) in one day. On January 3, France’s Total SA bought a 25% interest in Chesapeake Energy’s Utica shale play worth US$2.3-billion, while China Petroleum & Chemical Corp., or Sinopec, took up a one-third interest in Devon Energy’s shale projects for US$2.2-billion.

It’s a trend that’s set to continue and go beyond North American borders, says Moody’s Investor Services, as majors catch up with independent developers.

“Independent E&Ps have led the way in shale drilling, developing expertise in natural gas,” Moody’s said in a note. “The majors came late to the game in North America, but have begun pursuing E&Ps for their expertise in the new development techniques.”

Shale activity took off in earnest in 2011: ExxonMobil Corp. bought two companies in the Marcellus basin in Pennsylvania, and Marathon Oil Co. acquired Eagle Ford properties in south Texas from Hilcorp Resources Holdings LP. Mining giant BHP Billiton Ltd. acquired Petrohawk Energy Corp., a major player in the Haynesville and Eagle Ford, plus some Fayetteville shale properties, for US$15.1-billion. Norway’s Statoil ASA spent US$4.7-billion to buy Brigham Exploration Co. with operations concentrated in North Dakota’s Bakken Shale and Three Forks in Montana. Overall, shale acquisitions helped push overseas offers for U.S. oil and gas fields to US$51-billion last year, the most in at least 12 years, according to data compiled by Bloomberg.

“In Canada, the Montney Shale — a large natural gas basin in British Columbia and Alberta — has sparked interest for its proximity to a number of proposed projects to export LNG to Asia, and for potential gas-to-liquids (GTL) plants,” Moody’s says. “Sasol has two JVs with Talisman Energy and has begun studying a future GTL plant in western Canada that would use its proprietary technology. Petronas, Malaysia’s state oil company, created its first Montney JV with Progress Energy Resources — possibly with an eye on exporting LNG to Asia.”

GOING GLOBAL

Despite the ban in promising jurisdictions such as France, major companies are looking outside North America for growth. “These companies will strive to apply their expertise and mature cash flows toward other basins— particularly in Argentina, Brazil, China, Mexico, Poland and South Africa. The NOCs also hope shale development will help them improve energy security and self-sufficiency,” Moody’s says.

On Wednesday, China approved shale gas as an independent mining resource, a legal status that it hopes will encourage smaller Chinese energy firms to develop the unconventional energy source. The energy-hungry giant is expected to announce a new round of shale-gas tenders in early 2012, and although foreign companies can’t participate directly, they can team up with local firms.

Poland, which holds the most active and best areas geologically for shale in Europe, where governments want to diversify their natural-gas supplies away from Russia, is another promising play. The country has drawn investment from JVs involving ExxonMobil/Total, Marathon/Nexen, ConocoPhillips and OMV Petrom, among others.

But Moody’s says the development of these shale resources will not be quick or straightforward, and will face numerous obstacles similar to those seen in North America.

“Hydraulic fracturing has led to widespread environmental concerns over such issues as water contamination, wastewater disposal, land subsidence, earthquakes, and noise pollution. Areas more densely populated than sparsely inhabited North Dakota will present further challenges — particularly in Europe, where resistance to shale development has emerged,” the ratings agency says.

Source: Financial Post

BHP made its first big splash in the unconventional hydrocarbons with a deal to buy Chesapeake Energy’s Arkansas-based gas business for $4.75bn this past February.

The transaction would provide BHP Billiton with positions in the three world class resource plays: the Eagle Ford and Haynesville shales in Texas and Louisiana and the oil-rich shale Permian Basin in Texas.

Petrohawk’s assets cover approximately 1,000,000 net acres in Texas and Louisiana, with estimated 2011 net production of approximately 950 million cubic feet equivalent per day (MMcfe/d), or 158 thousand barrels of oil equivalent per day (Mboe/d).

BHP Billiton Petroleum Chief Executive, J. Michael Yeager, said the Petrohawk acquisition would add high quality growth to the company. “Petrohawk has a focused portfolio of three world class onshore natural gas and liquids rich shale assets. With over a decade of significant investment and volume growth ahead, this transaction would build on our recent acquisition of the Fayetteville shale in Arkansas and provides the potential to more than double our existing resource base.

Source: BHP Billiton

While hydraulic fracturing has been used since the 1950s, the controversial process has received heightened attention in recent years as oil and gas companies have expanded their operations into “shale plays,” geologically tight formations containing vast natural gas resources. Recent documentaries like “Gasland” and “Haynesville” have further heightened public interest in fracturing, and earlier this summer Texas lawmakers passed groundbreaking legislation requiring oil and gas operators to publicly disclose the specific chemicals used in hydraulic fracturing.

“Should these chemicals be disclosed? Absolutely,” said Dr. Mukul Sharma, a Cockrell School professor who holds the “Tex” Moncrief Chair in the Department of Petroleum and Geosystems Engineering. “But to claim hydraulic fracturing is a toxic mix of things is incorrect. All of these materials have been used in oil and gas wells for the past 100 years.”

Also known as “fracing,” the process creates fractures in shale formations to extract natural gas that was once thought unrecoverable. Now, combined with horizontal drilling, the process has transformed traditionally unproductive deep shale formations and led to an energy revolution over the past decade that is credited for the production of a significant and increasing proportion of domestic oil and gas. Sharma said natural gas is a much cleaner burning fuel, significantly less expensive than oil and provides a domestic source of energy that creates jobs and significant tax revenue to states and royalty income to landowners.

But opponents of the process have raised safety and environmental concerns about fracturing. Chief among them are that it contaminates groundwater, depletes valuable water reserves and can cause earthquakes.

Sharma’s presentation June 27 to faculty and students in the department’s Summer Research Internship program addressed these concerns — some of which he said are real and some perceived — along with other facts and myths surrounding hydraulic fracturing.

In reference to concerns about the amount of water used for the process, Sharma said municipal water-use in the Barnett Shale — a top natural gas-producing formation in north Texas — is 323 billion gallons. The water used for fracturing in the same area is only about 2.7 million gallons per well.

“To say we’re going to consume all of the water resources in the region is fear mongering,” he said.

Sharma said the process does cause earthquakes but their magnitude is smaller than an earthquake that occurs when a truck drives down a road, rarely producing any damage to buildings on the surface of the Earth.

“On the Richter scale, they would be negative or put another way, one million times smaller than a typical California tremor,” Sharma said.

He also praised recent legislation in Texas that, beginning in 2012, will require oil and gas operators to disclose the chemicals that they inject into the ground during hydraulic fracturing. Oil and gas companies lobbied against the legislation, arguing that it would disclose trade secrets to competitors.

Sharma said people should “know what’s going in the ground,” but he said he hopes the new regulations are not onerous to the point that they cause the process to slow down.

“That’s the balance we have to strike, and only time will tell whether we have achieved this balance,” he said.

He also added that most shale gas extraction uses water and polyacrylamide, a non-toxic polymer that helps reduce friction in the wellbore.

Fear of groundwater contamination from hydraulic fracturing has been heightened, most notably by the 2010 “Gasland” documentary, which interviews a resident in Pennsylvania who is able to light his tap water on fire. The resident said nearby gas drilling was to blame.

Sharma said such claims in the documentary are misleading because natural gas has been known to seep in water wells decades before hydraulic fracturing was ever used. He said an example of such occurrences is western New York’s Eternal Flame Falls, a natural waterfall over shale that emits natural gas from deep inside the Earth and produces flames when lit.

Sharma said more than one million wells have been drilled with hydraulic fracturing and, to date, there are no documented cases of groundwater contamination resulting directly from fracturing.

“If this was a pharmaceutical drug trial this would be a stupendous success,” he said.

“Can you contaminate ground water? Yes,” he said. “But the fact that we’ve had a long history of doing this and we haven’t had any cases where this has happened indicates to me that if the engineering is done properly and we take basic precautions, we can avoid this issue.”

View Dr. Sharma’s slide show presentation on fracing facts and myths  HERE

Reprinted with the kind permission of the University of Texas at Austin

At Shale Gas Eastern Europe 2011 in Warsaw, Poland, Encana’s Mike Graham, Executive VP and President, Canadian division, offered insights from North America’s largest independent natural gas producer, whose head office is in Calgary, Canada.

“We’re a big shale gas producer, a $30 billion enterprise. All of our production is onshore in North America, and we don’t have a lot of liquids,” he reported.

Encana has approximately $23 billion in market capitalization, 11.7 million net acres of land in North America, 25,000 net drilling operations and produced 3,321 MMcfe per day in 2010.

“We were the biggest natural gas producer until we did the split,” said Graham, referring to Cenovus.  “Half our production is in Canada. We produce 6 or 7 times the amount of Poland.”

He said Encana was also big in the Haynesville and Barnett, as well as in a new shale play in Michigan.

“We are moving to liquid rich plays as well,” reported Graham. “We will grow about 6% top line growth and will spend about $4.7 billion this year – it is a capital intensive business.”

He told delegates at the conference that “The Game Had Changed” over 100 years of potential natural gas supply, and that winning in a low price environment required low supply cost assets, a disciplined hedging program, and aggressive cost reduction initiatives, among others.

“You have to be the low cost producer in this game and that’s what we strive to be. In America we thought we were running out of natural gas and now we think we’re going to be able to export. We’ve done some JVs with Asia, sales to Chinese and Korean companies of acreage.

Encana, he said, was well placed to capitalize upon its competitive advantages, like maximizing its opportunities, focusing on low cost and concentrating on innovation.

“We think we have a lot of competitive advantage,” Graham continued. “We got into our plays early, and were in Chad, Brazil, etc. but sold all of our international assets and bought into North America. We’ve got a big land base and a tremendous amount of reserves, 84 TCF of potential on Encana lands. We are looking to do a lot of farm ins.”

He said that Canada, the “Great White North was not just the 51^st state.

“We are far away the biggest producer in Canada,” explained Graham. “We do go after the big resources. We’re big in CBM, and have a tremendous acreage position.”

He showed a map of the Horn River, Montney and Bighorn plays in British Columbia.

Showing picture of a well site, powdered with snow, Graham said: “We no longer call it a gas factory, we now call it our resource play hub. You do need to do these things repetitively: 60 wells off of one single pad. Our supply costs have been moving down and you definitely reduce your environmental footprint with pad drilling.”

He said wells per pad in the Horn River were eight to 16, with 240 – 480 fracks. In contrast to a comparable vertical well scenario, Graham said Encana’s well pads had a less than 5% disturbance area, reducing surface disturbance and only using six horizontal wells fracked eight times each to get a similar result.

“We might put in fracks every 100 meters. We typically do 2-3 per day,” he explained.

He said that Encana could contract rigs for up to five years, and keep them drilling 365 days per year.

“You might spend 300 million dollars on a single pad, so it’s not a game for those without deep pockets.”

Costs on a per frack basis, he said, had gone down to $650,000 per frack, down from about $4 million in 2007.

In terms of Encana’s Montney Completions, Graham said they would make the play “as big or bigger than the Barnett.” He reported that the company was using the External Casing packer completion technique a lot in the lower Montney.

He made mention of supply management initiatives. “We do a lot of ‘lean’ throughout the organization. We’ve got a goal to bring down our average supply costs.”

In terms of Joint ventures, Graham said that in the last three years Encana had done something like $4 billion, with players like Korean Gas and PetroChina.

“The Chinese are huge consumers of natural gas,” he explained. “They consume something like 8 billion cubic feet a day, although Japan is the biggest. We think that’s where the market’s going to shift, so there’s a tremendous market for natural gas. Demand is growing by 3% per year worldwide.”

This created great excitement at Encana, according to Graham.

“The North American market is saturated,” he explained. “We announced a couple of weeks ago plans for an LNG project: the Kitimat LNG Terminal, off the west coast of Canada. We hope to have a final investment decision by the end of the year. Others are also interested in doing this, which should help float the price of gas in North America.”

Graham was adamant that Encana’s drilling operations were environmentally safe.

“We think we’ve never ever damaged a water well,” he said, “and are focused on the protection of shallow groundwater. In the Horn River basin, our water source is from non potable water – all of our frack fluid is saline water coming out of the subsurface.”

Graham said that Encana was a big promoter of natural gas, commenting: “It’s great to see US President Barack Obama speaking about natural gas. It will allow the US to convert 18 wheelers to natural gas, and they could reduce their foreign oil imports by half if that were possible. We see it as displacing coal in North America.”

The development of unconventionals in Poland, he said, also held great promise.

“We think it’s a fantastic country. Poland’s on the verge of something big and it could be a very prosperous future for Poland in nature.

He noted that the Haynesville and Marcellus were also very significant.

“In 2013, shale gas will make up 34% of gas production,” he said.

The biggest deal activity, according to Rathan, was in the Fayetteville in 2008. He said the Marcellus had peaked from a deal perspective in 2009: “That’s when we entered the marketplace providing strategic advice. This year we feel there will be a lot of activity in the Niobrara.”

He added, “We prioritize them according to the peak level of interest for our clients.’

Rathan said that in developing production of shales, there were two parts: 1) the nature part, which concerned the quality of the shale, and 2) the nurture part, which was all about applying technology to make them produce, “In applying lessons, understanding the geology, interpreting the logs and understanding the surface aspects of developing the shale play.”

His slide told that it was about “Maximizing the right characteristics,” namely, depth, thickness, porosity, TOCs, the pressure regime, etc. “These describe the natural aspects of the play,” he explained “and ultimately you move to certain areas of that play.”

Mr. Rathan spoke about joint venture activity in the Marcellus, including players like Total SA, BG Group and Statoil ASA. “The Canadians came a little later,” he recalled, “and more recently there has been Japanese and Chinese interest. Following them are the BRIC countries.”

He said that in the last six months Tudor Pickering Holt & Co had been very involved in a transactions in the Niobrara and Eagle Ford shale plays involving top Chinese offshore oil producer CNOOC Ltd and Chesapeake Energy Corp.

“They asked us to help them with the technical analysis and the ultimate deal structuring,” he explained. “Working with the Chinese one has an expectation that working with Asian countries can be a lengthy process, but these moved extremely quickly and that’s a critical requirement. In the Niobrara we conducted it on the basis of only two wells in the Powder River basin.”

According to Rathan, the attraction into the US shale plays was also from the perspective of the economics, not just from a learning perspective.

“We believe that the long term gas price will be $6 – the short term price ($4) is not realistic, for shale plays to provide attractive rates of return.”

He said activity was moving to more economic plays. “The sustainable gas price is about the midpoint of his chart,” Rathan showed. “That ultimately is where we expect the gas price to come back to. The shale plays is a good place for the operators to be.”

He noted the move into liquid rich plays. “In oily areas the rates of return are 50-100%. They are cropping up all over the country, signalling a big shift in activity.”

“The emerging plays, particularly the oily ones, have been rising with the rig count and companies are aggressively shifting their capital there. So the activity is shifting to the west, in places like the Niobrara and the Bakken. It’s just applying the same technologies,” he said.

Rathan discussed the value evolution of land acreage at places like Niobrara and emerging oil plays.

“You can’t sell these assets until you have plenty of science, plenty of logs of fracture stimulation,” he explained, “knowing how far out the fractures go. Seismic is extremely important information to build a position, and there’s constant evolution and learnings in this area.”

He explained that the Barnett shale provided a laboratory of sorts for learning. “We realized it wasn’t all equal,” he said of the shale. “A partner purchased the wrong acreage in the Barnett. We try to understand immediately where the sweet spots area.”

From an operational perspective, Rathan spoke of drilling in an urban environment. He showed a photograph of drilling being done right in a university at Fort Worth, saying it was doable via long laterals closely spaced, maximizing an area. He also spoke of stacked pad drilling.

He emphasized the importance of seismic for certain shale plays, like in the Barnett for avoiding the viola limestone in the Barnett, or skirting natural faults.

“Coupled with that is the application of microseismic to understand where we’re stimulating and where we’re not,” said Rathan. “It helps with the drainage area, therefore with spacing and completion optimization.”

He said that minimization of the surface footprint was receiving a lot of attention.

“Enormous quantities of proppant and water volume are required, he explained.

“You can gain a lot of resource out of one location, drilling 3000 foot laterals and achieving enormous quantities of resource from one location. The aim is stimulating as much rock volume as possible via the spacing of frack events.”

He continued: “Engineers are modifying the number of frack stages, and more proppant can lead to higher recovery. As we get longer laterals we get more stages and should get higher EURs. We think we can get a million barrels on a per well basis.”

Rathan posed the question whether too much money was being spent on completions. “It’s not a blind process doing more things,” he answered. “It’s doing things smarter.”

“The type of fluid you use can impact the kind of stimulation you have. We’re finding that a hybrid fluid treatment can give us the best of both worlds.”

Rathan offered up a “Top Ten List” of the factors that had made US shales a success.

“It began with identifying organic rich foreland sedimentary basins –understanding them was one of the first requirements,” he said. “It took decades of legacy vertical well drilling. Vertical well activity in the Barnett led to cracking the code.

Among others, he said that accessible and accommodating land owners were key, as well as a pragmatic and transparent regulatory environment, scientific advances in formation analysis, an investment climate attracted to energy, a declining domestic gas supply and high gas prices, advances in horizontal drilling, and isolated mult-stage fracking.

He said that so much had been learned in North America about this process.

In terms of land he offered advice: “Move early and gather both a contiguous and diverse position, to ensure you don’t miss a sweet spot.”

In terms of regulatory issues, he said: “Focus on areas with oil friendly regulatory regimes. Poland is going to be like the Oklahoma or Texas of the US. Once you’re there you should communicate, be transparent, having town halls and making the economic case.

“US O&Gs need to make their case much more forcefully,” added Rathan.

“Don’t skimp on science,” he said of technical issues. “Get cores, shale petrophysics, etc.”

“From a capital perspective, have a good balance sheet,” he encouraged. “Understand how to fund your company in an appropriate way through the debt markets, equity, non core asset sales, and through joint ventures to develop the plays and stay strong.”

In terms of operations, Rathan emphasized being flexible. “Rig mobility is important in the US, from the less competitive gas plays to the more, and now to the liquid rich plays. The ability of companies to move their operations around is important and we hope that in Europe there won’t be certification boundaries.”

Their number could soon double.

Another 930 wells are permitted and either awaiting drilling, being drilled or awaiting the complex hydraulic fracturing process that releases gas from the shale. Already, the number of producing wells is more than triple what it was a year ago.

And just last week, the federal government announced that Haynesville had become the nation’s most productive gas field, surpassing the Barnett Shale in Texas.

The boom has fundamentally changed America’s energy outlook. The development of Haynesville and other deep gas plays is a major factor in the precipitous drop in natural gas prices, and temporarily, at least, the exploitation of such sources has eliminated the need for the United States to import vast quantities of liquid natural gas.

It has also had a profound effect on Louisiana’s economy, causing a boom in the mostly rural and poor sections of the state’s northwestern quadrant and helping to ease the effects of a national recession on state coffers. The boom’s effect on the state’s budget has been limited, however, by a generous exemption granted to energy producers that dramatically limits the taxes they must pay in the first two years of a well’s production — usually its prime period.

Louisiana expects to reap the benefits of the Haynesville formation for a long time, with 10,000 wells expected to be producing by the end of 30 years, said James Welsh, of the Department of Natural Resources’ Office of Conservation, which oversees oil and gas exploration and production.

“There’s never been a dry hole drilled in the Haynesville shale,” Welsh said.

Read the Full Article from TheTimes-Picyune HERE

Tight gas is natural gas held in rock pores up to 20,000 times narrower than a human hair. Often the gas will not flow freely into a well, or it flows at a much slower rate than in normal gas reservoirs.

The amount of gas that would be recovered from each well would be low but the overall volume of available gas in the reservoir can be much higher than conventional gas reservoirs.

Shell has decades of production experience with tight gas – in the North Sea, mainland Europe and North America. At its operations at Pinedale, Wyoming, for example, the company is now able to drill wells over twice as fast and at 30% less cost than when it started.

Engineers must drill many more wells than in a conventional field to access volumes large enough to make a project worthwhile.

Shell uses seismic sensors and advanced software to map out underground fields and pinpoint the best locations to drill. Steerable drills are employed to extend many wells horizontally into the rock, often up to 2.5km away, from one location on the surface. This also helps to increase efficiency and lower the environmental impact of our operations.

Engineers crack open the rock at selected intervals within the well by pumping fluids (mainly water) into the well bore, a technique known as hydraulic fracturing. This releases the gas and helps it to flow.

Shell started producing tight gas in the early 1950s in south Texas, but it is only in recent years that technologies and improved efficiency have allowed us to produce high volumes of gas economically from some tight gas fields.

One of its current major tight gas projects is at Pinedale, which produces around 350 million cubic feet of gas a day – enough to power 1.6 million US homes. Elsewhere thew group is working in a partnership to explore the Haynesville field in Louisiana.

In western Canada, Shell acquired the Duvernay natural gas company in 2008. It also produces enough tight gas in the Groundbirch area of British Columbia, Canada, to meet the needs of over 400,000 Canadian homes.

Most recently, Shell bought land containing shale gas in the Marcellus field in north-east US and in the Eagle Ford field in south Texas. These acquisitions brought Shell’s total tight gas land holdings in North America to over 14,500 square kilometres.

Outside North America, Shell is producing 117 billion cubic feet of tight gas a year at the Changbei field in China, and is exploring for more resources in other parts of the country.

In Australia, the group acquired Arrow Energy in 2010 in a A$3.5 billion joint deal with PetroChina, to produce another form of tight gas called coalbed methane – natural gas found in coal seams.

In Germany, Shell is in a joint venture to explore for tight gas in the Lower Saxony Basin. And we are in the early stages of assessing potentially major resources of shale gas in Sweden and South Africa.

“China and Europe are not yet experiencing the same transformation in energy security as North America,” noted Shell. “But tight gas is expected to play an important role in providing these regions with a cleaner, more secure energy supply and we are working to develop its potential.”

Environmental issues

All Shell’s tight gas operations use hydraulic fracturing to break open rock and release the gas. This, it says, is ’a safe and proven technique’, citing the opinion of the US Environmental Protection Agency, which is now carrying out a new study into hydraulic fracturing and its potential impact.

“Fracturing has been used by oil and gas companies for over 60 years. Government legislation is designed to protect drinking water aquifers including from potential contamination by fracturing fluids and this is a high priority for Shell,” said a Shell statement.

“Fracturing typically takes place a kilometre or more (thousands of feet) below drinking water supplies. We insert concrete and steel barriers into the wells as standard practice to prevent any drilling or fracturing fluids from entering into local water supplies,” it added.

According to Shell, specific social and environmental challenges vary from region to region, citing, for example how Pinedale is situated in the rural Rocky Mountain region and teems with wildlife: antelope, mule deer and sage grouse are common here.

“We have implemented a number of environmental measures with the aim of protecting local biodiversity, keeping air and water clean, and reconstructing the land once drilling ends,” said Shell.

Source: The Engineer

Barnett, Marcellus or Haynesville are the names that often are associated with shale gas development in the United States.

We’re not talking about any of the huge, gas-rich shales that slip off the tongue said Darcy Spady, Vice President and Managing Director of St. Brendan’s Exploration Ltd. in Calgary.

Spady recently shared his experience about completion production methods with the delegates Shale Gas World 2010 in Warsaw, Poland.

He said there was even a lot to learn from little shales – what he termed “hillbilly shales.”

The major rush into new shale basins was good but by looking at past experiences, much wisdom could be gleaned.

“Look at the state of where we are.  The Barnett was a massive game changer. We never would have dreamt of the kind of fracking being done there. By 2009, 70% of the new shale gas was from there. We’ve made a major shift in thinking – suddenly when your rock is as tight as a sidewalk, we’ve changed our perspective from a fracking point of view.”

Spady stated, “There have been massive changes in the industry but we can’t forget that for years, we dropped nitro-glycerine in the well and we did all sorts of crazy things and there are some that produce 80 or 90 years later.”

He opined that straight some methods like nitrogen fracking might make sense in areas under development such as shales in Europe.

“Maybe there are shales on the European side that don’t need all of this fluid pumped into them. Historically foam fracturing (nitrogen and gel) had little effect on the formation, and some service companies are using an air system.”

Spady also mentioned a straight gas frack and liquid and CO2 fracturing.

“There are methods to reduce footprint,” he said. “We’re concerned, and trying to lower carbon emissions to have less diesel and carbons spewing. Do we have to put all this water into it?”

Mr. Spady described  a small shale gas job taken on by St. Brendan’s in 2004, a “hillbilly shale” where mineral rights were owned under a high school’s football field.

“I was picked to do this project,” he recalled. “It would make a great paper on public drilling.”

“There’s lots and lots of these little Appalachian wells out there,” explained Spady. “They have a small footprint, and there’s no water use. It doesn’t get much more urban than that – and they didn’t even realize we’d finished the well when we finished it.”

He said that while such an operation was not sexy for a stock market, it sure ended up making for nice reserves. “The school uses the gas to this day and they got their football field back,” remarked Spady.

Future constraints were also touched upon. “We have the same key issues as today as long as we use large water fracks. Management of the water is critical and it will be costly.”

Another key component, according to Spady was pricing. He asked, “Is large operation footprint sustainable at $4 gas?”

He spoke about the role of technology and said that more and more service companies were providing innovations in terms of air drilling.

“There’s a mix of both the technology and technique – like going back to air for brittle shales. Sometimes the shareholders out there demand too much, when everything is based on flow rates.”

Spady added, “I think in general current methods of these massive water fracks are unsustainable for all shales. Is the publicity cost too high for these large water fracks? Putting together the data and looking back at older techniques must be examined

 New technology has made extracting natural gas from the shale commercially viable in recent years and created wealth opportunities in some of the state’s more impoverished parishes. And while not everyone can become a “shale-onaire”—the nickname given to landowners who become rich by leasing to natural gas drillers—new sources like the Haynesville play are a boon to the Capital Region and its petrochemical industry, which relies heavily on natural gas as a raw material for its products and as an energy source. The economics of natural gas differ from oil in part because the markets for gas are more regional. About one-fourth of the energy used in the U.S. comes from natural gas, according to the American Gas Association, and almost all of that comes from North American sources.

 There isn’t an international organization like OPEC that can dictate prices to the rest of the world. Instead, natural gas prices can swing wildly based on supply and demand, weather and other factors. Prices averaged $4.10 per million British thermal units from 1990-2010, according to New York-based Trading Economics. On any given day, however, gas was as cheap as $1.05 and as expensive as $15.38; today, prices are between $3 and $4.

One Btu represents the amount needed to heat one pound of water one degree Fahrenheit. Louisiana Economic Development Secretary Stephen Moret says the U.S. has moved from an expensive and volatile natural gas market to one with prices that are much lower and that are expected to stay reasonably low and stable for years—perhaps even decades. “That is a gift from heaven,” Moret says. “The competitiveness and the outlook for our chemical industry are dramatically better than they were two years ago.” And unconventional shale plays are a big reason why.

Louisiana chemical industry was in real danger of losing facilities, Moret says, as companies were tempted by low-cost feedstocks in the Middle East and Asia. Many facilities have become profitable again, and companies see Louisiana and Texas as logical places to expand. An international company like BASF not only competes against other corporations, there’s also internal competition over which facility might receive a specific investment.

Tom Yura, general manager of BASF’s Geismar plant, says low natural gas prices give the U.S. a significant advantage over Asia and Europe, where heavier, oil-based feedstocks typically are used. “The stability for us here in Louisiana is good because then you can plan,” he says, adding that the proximity to shale sources nearby also is comforting since transport costs are low. BASF had a strong third quarter in North America in part because of natural gas prices, which is an especially big deal coming out of a global recession. “Could you imagine if natural gas was still $13 or $10 per million Btu?” Yura says. “People would say, ‘Geez, your stuff is really expensive. I don’t think we want to buy much of that right now. We’ll just sit and wait.’”

Source: Baton Rouge Business Report

“If you decided, I’m going to pass on the Barnett, pass on the Haynesville, pass on the Marcellus, and you were going to wait for the next four or five–there won’t be any,” McClendon said Wednesday during the company’s annual meeting with analysts, referring to tight, hydrocarbons-rich rock formations in Texas, Louisiana and the U.S. Northeast, respectively. “By the end of 2011 it will be over. There won’t be any basins that have escaped investigation.”

The comments come three days after Chesapeake agreed to sell a third of its interest in south Texas’ Eagle Ford shale formation to Chinese state-run Cnooc Ltd. (CEO) for $2.16 billion in cash and drilling funding.

Shale formations were believed to be impractical sources of fossil fuels until recent years. Technological advances in hydraulic fracturing–shattering the rocks to allow oil and gas to seep from the cracks–and horizontal drilling have unlocked vast reserves and prompted international companies to scramble for entry into the field pioneered by independent firms like Oklahoma City-based Chesapeake.

McClendon said Chesapeake will continue to court joint venture partners for its interests, including those in the Niobrara shale in northeast Colorado and the Permian Basin in west Texas. And Chesapeake may sell its expertise to other companies considering shale plays overseas.

But Chesapeake isn’t planning any foreign investments, McClendon said.

We aren’t going to Poland, we aren’t going to Canada,” he said. “In terms of spending Chesapeake capital overseas, I don’t see it.”