Companies bet big on South Texas gas find
By BRETT CLANTON Copyright 2009 Houston Chronicle

Last October, just as the economy was tilting into crisis, a small oil and gas company in Houston quietly announced the discovery of a mammoth natural gas field in South Texas that at any other time might have garnered bigger headlines.

Petrohawk Energy's find, however, did not go unnoticed in the oil and gas industry — and it didn't take long before oil companies large and small began making their moves.

Today, though the economy and natural gas prices remain weak, the Eagle Ford shale remains one of the hottest prospects in North America, and energy companies are moving forward there even as they're pulling back elsewhere.

That's because of what some companies suggest is a virtually recession-proof combination of highly productive wells and low drilling costs they say can yield profits even as natural gas prices hover near seven-year lows.

Also attractive: the flat South Texas ranch land, where obstacles are few and Gulf Coast oil and gas infrastructure is nearby; and landowners have grown comfortable with the industry after decades of oil drilling.

“You can certainly make more money from wells than cows,” said Joe Martin, whose family leased nearly 20,000 acres of land to Petrohawk in LaSalle County for drilling.

But it may still be a while before the full potential of the Eagle Ford shale is known. Though early results are promising, companies have been cautious about overstating what could be in the ground, especially since so few wells have been drilled so far.

“What we're going to find out, as with most shale plays, is there's going to be sweet spots,” said Bob Banks, chief operating officer at Swift Energy, a Houston-based oil company with nearly 90,000 acres leased in the Eagle Ford. “That's what we don't know yet, which areas are really going to work better than the others because it's pretty early days.”

Recently discovered U.S. shale plays, including the Haynesville in Louisiana and Marcellus in Pennsylvania, are expected to provide a major boost to U.S. natural gas supplies in coming years. The dense rock formations, once thought too difficult to explore, have been unlocked with the help of recent advances in drilling technology.

The core areas of the eight largest U.S. shale plays may contain 475 trillion cubic feet of recoverable resources, according to an estimate by Ross Smith Energy Group, an industry research firm in Calgary, Alberta. That's roughly ten times the size of Texas' famed Barnett shale play in the Dallas-Fort Worth area, which supplies nearly 10 percent of U.S. natural gas production, excluding Alaska.

$3.88 break-even point

While the Eagle Ford is among the smallest of the group, with some 19 trillion cubic feet of natural gas remaining, the economics is among the best, the firm said.

Producers in the Eagle Ford can break even when natural gas is priced as low as $3.88 per million British thermal units, the firm said, versus break-even prices of $5.18 in the Barnett, $3.74 in the Marcellus and $4.49 in the Haynesville.

Natural gas closed at $4.99 per million BTUs Monday in trading on the New York Mercantile Exchange, down from nearly $14 in summer of 2008, amid a recession-related drop in demand and bulging stockpiles. Consumption will fall by 2.4 percent this year and remain flat in 2010, according to the Energy Information Administration's most recent short-term forecast.

A potential boom

Yet that has not stopped companies from pushing ahead in the Eagle Ford play, which starts near the Mexican border and extends east below San Antonio across a string of counties including Webb, Dimmit, LaSalle, McMullen and Live Oak.

“It's got the potential of being a boom,” said Martin, whose family leased to Petrohawk, noting that land prices in the region have risen to $1,500 per acre in some places, 10 times what they were two years ago.

Houston's Petrohawk, with 210,000 acres in the Eagle Ford, has been the most active. It operates 17 wells in the Eagle Ford and aims to add another seven or eight by year-end, said Joan Dunlap, the company's head of investor relations. This month, the company said it will sell its properties in West Texas' oil-rich Permian Basin to an unidentified privately held company for $376 million to focus on its assets in the Eagle Ford and Haynesville shale plays.

Asked if the Eagle Ford could be as big as other major U.S. shale gas plays, like the Barnett shale, Dunlap said, “it's a big question mark.”

Other oil and gas companies including Pioneer Natural Resources, Swift Energy and Anadarko Petroleum Corp. also have drilled wells in the Eagle Ford or are planning to in coming months.

Less clear are the intentions of Houston-based ConocoPhillips and Irving-based Exxon Mobil Corp., each of which has large acreage positions in the Eagle Ford.

Houston's ConocoPhillips, with 300,000 acres, considers the region “one of the top resource plays in the lower 48” and will concentrate much of its 2009 exploration spending in the Eagle Ford and other North American unconventional resource plays, spokesman Charlie Rowton said. But he declined to elaborate.

Exxon Mobil confirmed it holds an interest in the Eagle Ford shale in La Salle and McMullen counties, but a spokesman said, “the details of the exploration program are considered confidential.”

Exxon Mobil confirmed it holds an interest in the Eagle Ford shale in La Salle and McMullen counties, but a spokesman said, “the details of the exploration program are considered confidential.”

Bob Fryklund, industry analyst with IHS-Cambridge Energy Research Associates in Houston, said highly diversified oil majors may not have the same urgency to act as independent oil and gas producers do.

“This is just one portion of their portfolio, while for a lot of the independents it's their whole portfolio,” he said.

But increasing moves by major international oil companies into U.S. shale plays, he said, suggest they may see more potential there than they once did.

 

Natural Gas, The New Oil
As the age of fossil fuels enters a time of efficiency, Houston has the opportunity to keep its leading role oil
By Tom Fowler - Copyright 2009 Houston Chonicle

Almost from its beginnings 150 years ago this month, the oil industry has been a high-risk international business driven by speculators and technological innovation.

Edwin Drake and the New Haven, Conn., investors who funded the United States' first commercial oil drilling operation in rural Pennsylvania aren't so different from today's venture capitalists betting big on a new, unproven technology, author and energy industry analyst Daniel Yergin says.

Drake was labeled "mad" and came within days of tapping out his funds as he adapted equipment that previously had been used only for water wells in search of a lamp fuel cheaper than whale oil.

Within just a few years, the forest of wells that followed was feeding an international market, says Susan Beates, the curator at the Drake Well Museum in Titusville, Pa.

Despite the similarities with 1859, though, the oil industry in 2009 faces challenges that make past barriers seem like mere bumps in comparison - surging energy demand from the developing world, volatile price swings that spawn both boon and bust, and demands to limit the environmental damage of fossil fuels.

"But the age of oil is not over," Yergin says. "Over the next two to three decades, on a global basis we'll see oil demand increase, but there will be a tremendous drive for us to use it much more efficiently."

That drive, and particularly the role that natural gas may play in it, could help keep another generation of workers in Houston's office towers and refineries employed.

"In some ways Houston isn't the oil capital as much as it is the natural gas capital of the world, at least for the last half century," says Joseph Pratt, a historyprofessor at the University of Houston who specializes in the energy industry.

Amory Lovins, president and chief scientist of the Rocky Mountain Institute, predicts the U.S. could just about eliminate its need for oil by 2040 by expanding on a number of energy efficiency efforts that have sprung up since an Arab oil embargo sparked the energy crisis of the early 1970s.

These include reducing oil's use as a transportation fuel through lighter, fuel-efficient vehicles, shifting to a combination of natural gas and nonagricultural biofuels, improving building efficiency standards and other measures.

"It's not going to happen because of concern for the climate but because it's profitable. Any company that saves energy knows it saves money," Lovins says. "The whaling industry of the 1800s didn't die out because it ran out of whales. It ran out of customers. Whales were actually saved by profit maximizers of the oil industry."

The energy industry certainly doesn't widely embrace Lovins' timeline for oil's decline, but Pratt says the business knows a thing or two about saving energy. Refineries and drilling platforms use huge amounts, so company engineers are constantly find ways to do more with less.

"I'm a believer in that collective engineering impulse to find better ways to get oil and natural gas and maybe better ways to use it," Pratt says. "When it comes to better and cleaner ways to use it, we've just touched the surface on our abilities."

The likelihood of government mandates to reduce greenhouse gas emissions will increase the importance of natural gas, which was more nuisance than resource for much of the industry's history because of difficulties in transporting it. Its combustion emits far less carbon dioxide, and it can be adapted to run all manner of equipment.

Less than a decade ago there were concerns about the adequacy of domestic natural gas sources, Yergin says, leading to anxiety among power companies and large industrial users. But advances in drilling technology that are letting companies get gas from plentiful shale formations have changed that outlook.

By some estimates shale gas formations can meet U.S. demands for many decades to come. A report released earlier this year says that including shale, gas reserves estimates are up 35 percent from the year before.

"There's a lot more confidence about using gas," Yergin says.

Pratt says Houston is particularly well suited for a future that relies more heavily on natural gas because it's such a big part of the city's past.

The abundance of natural gas near the city helped fuel the growth of industries along the Houston Ship Channel after World War II. An extensive national pipeline network emanated from the area, bringing the fuel to both coasts.

The companies that build the pipelines historically have been in Houston, as have the researchers who improve on the technologies to extract, process and move the fuel. The intellectual and financial resources that reside in the energy companies that stretch from downtown westward to Katy are unrivaled by any other city, Pratt says.

"To say oil will be around for another 150 years is an exaggeration," Pratt says. "But I'd say that for the second half of the petroleum age, natural gas will be the predominant fuel."

Going Deep in the Rockies
At one time, even nuclear bombs couldn’t loosen ‘tight gas’ trapped in sandstone.
Now Exxon Mobil says it has a way.
By Kristen Hays - Copyright 2009 Houston Chonicle

Oil and gas producers have known for decades that a massive bounty of natural gas lies beneath western Colorado's mountains. Getting at it, however, can be costly and complicated.

With a potential gain of 1 billion cubic feet per day of output from its leased land in the deepest part of the gas-rich Piceance Basin — which would be about 2 percent of all U.S. gas production — Exxon Mobil Corp. spent the last decade perfecting a way to drill less for more gas.

Now, the Irving-based behemoth is ramping up its Piceance project with more drilling and with new, largely automated gas gathering, treatment and monitoring facilities.

Armed with the financial heft to shrug off low natural gas prices that have prompted other Piceance producers to move out or slow down, Exxon Mobil is running seven rigs, five more than two years ago.

“Now that we have this level of rigs, we can drive down costs,” said Jim Branch, Exxon Mobil's Piceance Project executive.

The Piceance is a bowl-shaped underground basin that covers 6,000 square miles in five counties on both sides of the Colorado River.

Its allure isn't new. Southern Union Gas drilled the first well there in the mid-1950s.

The federal government exploded nuclear bombs underground there in the late 1960s and early 1970s, hoping to unleash natural gas and to demonstrate the bombs had peacetime uses. The explosions yielded no gas other than some of the radioactive kind, and public opposition squelched the blasts. So, Piceance activity was light until recent years, when technological advances caught up with the challenges of getting at so-called “tight gas” trapped in pockets of concrete-like sandstone in remote mountain areas.

Despite natural gas prices that have fallen below $3.50 per million British thermal units from last year's highs of $13, Exxon Mobil is banking on the Piceance for years to come. The company has leased about 300,000 acres of mostly federal land that Exxon Mobil says could contain 45 trillion cubic feet of gas. That's about twice the amount of gas consumed in the U.S. each year, according to the U.S. Energy Information Administration.

“That potential is huge,” said Fadel Gheit, an analyst with Oppenheimer & Co. “They are doing it in the methodical Exxon way. Exxon is very bullish on natural gas globally, not only in the U.S., and they are putting their money where their mouth is.”

‘Elegant ballet'
Exxon Mobil spent a decade tinkering with technology used to extract gas elsewhere to adapt it to the Piceance. The company came up with a way to drill deep, then blast holes in the pipe next to pockets of gas. A mixture of chemicals and water shoot into the well at high pressure to crack open the rock, while sand that's mixed in holds the fissure open so gas can flow.

The process involves repeated fractures in up to 50 zones that contain gas pockets on the way back up the well, like opening an elevator door on various floors, to maximize gas flowing from each well.

“We use the term ‘elegant ballet' because we can actually do multiple wells now,” Branch said. “The key to improving the cost is to keep this equipment working constantly.”

That process, combined with directional drilling that deviates from a straight vertical line, means Exxon Mobil can drill up to 20 wells per site. That translates to fewer rigs sharing space with the basin's mountains, pinyon pines, sagebrush and grazing cattle.

The company says the method dramatically cuts operational costs. Exxon Mobil won't disclose the Piceance project costs, except to say that it's part of the company's plan to spend $125 billion on projects over five years, including $29 billion this year.

Exxon Mobil is among many producers in the Piceance. Others include EnCana, Williams, XTO Energy and Chevron.

Williams tried Exxon Mobil's technology in 2006 but found no cost benefits above what the company was already doing, spokesman Jeff Pounds said.

Exxon Mobil began increasing its Piceance presence two years ago. At the peak of construction, 600 workers were on the payroll. Now, about 60 employees run the operations, mostly from a control center, while contractors do the heavy lifting with drilling and seismic imaging.

Falling gas prices
Work in the area has slowed since natural gas prices dropped.

“We had 105 rigs in the basin last year; now, there are 25,” said Shawn Brennan, manager of Houston-based Enterprise Products Partners' new gas treating plant in the basin.

Besides moving gas, Brennan said, the company's Piceance operations extract up to 70,000 barrels a day of natural gas liquids, such as propane, butane and ethane, which can be sold outright or used in processing at refineries and chemical plants.

“That's a lot of diversity to weather the markets as they are now,” he said.

Exxon Mobil faced some lingering ill will when establishing its gas operations. In the early 1980s, the company had a major oil shale operation in the Piceance. That decade's oil bust prompted an abrupt pullout, throwing the Rifle-area economy into a tailspin for years.

To make itself more welcome, the company donated $500,000 to help pay for a new helicopter ambulance pad at a hospital in Grand Junction.

Co-existing
Other community service outreach efforts include an academy for math and science teachers in area public schools and an annual sheepdog championship competition.

“We were certainly mindful of that history,” Branch said. “I know there is some legacy there, but it has not complicated our work here.”

For the ranchers in the Piceance, it's sometimes a challenge to co-exist.

Exxon Mobil and some other producers try to limit traffic by busing workers in to work and having them live on site for 14 days, like offshore crews. The companies replant grass and trees after clearing right of way for pipelines, and cattle guards prevent free-roaming livestock from wandering too close to plants.

Larry Robinson, 63, a third-generation rancher, said he sees evidence of environmental sensitivity, but there's no way to pretend the producers aren't there.

“The solitude's gone, and we're getting more and more wells and more and more pipelines, more and more compressors,” Robinson said. “It isn't like it used to be for us, and I don't think it will ever be the same.”

 

Cap and Trade Emission Regulation Plus Wind and Solar Work Best With Natural Gas
MEA Energy Delivery News & Solutions Newsletter (EDNS) - June 2009

Cap and Trade Emission Regulation Plus Wind and Solar Work Best With Natural Gas Some believe that the Waxman-Markey Cap and Trade legislation which is pending in the US Congress plus the pressure to reduce C02 emissions further with wind, solar and other renewable energy sources will help bring back natural gas prices. One of the reasons often cited is natural gas power plants are load-following power plants, which can shut down when the solar or wind resources are available. This is not true for nuclear or coal power plants, which are designed to run all the time. Thus, an electric grid comprised more heavily of natural gas load-following power plants is capable of adding a higher proportion of electricity generated by the wind and the sun.

 

Natural gas glut could hit U.S.
By Tom Fowler; Houston Chronicle, Jan. 31, 2009

As many as seven massive natural gas export terminals are expected to start up overseas this year, expanding worldwide capacity by 20 percent and flooding markets with new supplies of the key power plant and heating fuel. Dozens of new tankers capable of carrying natural gas in a liquefied form are slated to hit the seas.

Just as these new supplies come on line, worldwide demand is expected to drop as the global recession deepens.

Operators of these new facilities are unlikely to cut back production, however, so shipments of liquefied natural gas will most likely head to the deepest markets with the greatest amount of natural gas storage capacity — the United States.

‘Counterintuitive’

“It’s completely counterintuitive,” said Murray Douglas, a global LNG analyst with Wood Mackenzie in Houston, who is predicting U.S. LNG imports will grow 30 percent to 456 billion cubic feet this year and to more than 1.1 trillion cubic feet by 2013.

“We don’t believe Asia and Europe will be in a position to absorb this new production, and the U.S. is the only market that can take it, that has a large amount of storage.”

The wave of imports might even be strong enough to challenge growing domestic natural gas production from various shale formations, including the Barnett Shale near Fort Worth and Fayetteville Shale in Arkansas.

“This can put pressure on U.S. gas prices and could delay the full development of some of the new shale pro-jects,” Douglas said.

Other analysts, including Houston-based Waterborne Energy and Raleigh, N.C.-based Pan Eurasia Enterprises, agree that an American gas import surge may be coming.

Even the Department of Energy updated its LNG import predictions for 2009 recently to include the possibility of such a surge.

Big Energy Chunk

Natural gas accounts for 23 percent of total energy consumed in the U.S., according to the Department of Energy, much of it used to fuel power plants.

Twelve percent of the gas comes from foreign suppliers, most of it through pipelines from Canada, and about 3 percent comes from overseas aboard LNG tankers.

Changing To Liquid

Natural gas turns into liquid at minus 260 degrees Fahrenheit. In that condensed form, it can be transported in specially designed oceangoing tankers. When the tankers reach a gasification terminal, the liquid is heated back into gas for transport by pipeline.

2007 was a record year for LNG imports into the U.S., with some 770 billion cubic feet arriving through five terminals.

Three terminals came on line in 2008, including Houston-based Cheniere Energy’s terminal on the Louisiana side of the Sabine Pass south of Port Arthur and Freeport LNG’s terminal on Quintana Island south of Houston. The third, owned by The Woodlands-based Excelerate Energy, is near Boston.

Timing Not Ideal

The timing was bad. U.S. imports slowed as tankers were drawn both to Europe — where prices spiked recently because of ongoing supply disputes with Russia — and Asia, where economic growth and the shutdown of a large nuclear power plant in Japan because of earthquake damage led to greater demand for natural gas to run other power plants.

More of the same was expected for this year. Some equity research firms even stopped tracking LNG terminal operators.

Asia-Pacific Region

But the coming wave of new export terminals, where the gas is liquefied and loaded on tankers, is centered largely in the Asia-Pacific region, said Steve Johnson, president of Waterborne Energy. That means those markets will be well-served, leaving more tankers available for Atlantic markets — with the U.S. being the deepest and most liquid.

One might expect the new LNG exporters to delay opening, or at least cut back their output given the lower demand.

But the gas liquefaction projects have been planned over many years and cost their host governments many billions of dollars, Johnson said.

“Shutting it down is the last thing they will do,” Johnson said.

Competitive Price

LNG can be competitive priced as low as $3 per million British thermal units, said Zach Allen, head of Pan EurAsian Enterprises, a management advisory firm that follows LNG markets. That’s a price the U.S. hasn’t seen since 2002.

While LNG generally is sold in contracts between importers and exporters, its price is influenced by the price of natural gas traded on the New York Mercantile exchange, which closed Friday at $4.42 per million Btu.

“Some cash is better than none, especially for producers who rely heavily on that cash for social and other programs that would be politically explosive to cut off or cut back,” Allen said.

Some of Qatar’s natural gas fields produce other valuable liquids that are stripped out and sold at prices that essentially cover all production costs before the gas even makes it to market, Douglas said.

“They are essentially producing the gas for free,” Douglas said.

The cost of getting the LNG from its foreign origin to other markets can be relatively low, Johnson said.

The 43-day round trip from the huge export terminal in Qatar to the Lake Charles, La., LNG terminal costs $2.09 per million British thermal units.

From Egypt to Lake Charles takes 30 days and $1.29 per million Btu.

 

George Mitchell Still Pushes Energy Conservation
Houston Chronicle, August 1, 2008; by Kristen Hays

George Mitchell was an ecoconscious oilman before it was cool.

The 89-year-old Houston wildcatter, real estate developer and philanthropist assembled business and academic leaders to address solutions to energy, food, environment and population growth problems more than 30 years ago.

Now Americans are grappling with record-high oil, gasoline and food prices, climate change concerns are at the forefront and emerging economies in Asia and the Middle East are thirsting for energy.

For Mitchell, it's a big dose of déjà vu.

"A lot of these things could have been predicted," Mitchell said during a recent interview in his downtown Houston office. "We have cars that get an average 22 miles per gallon. We could have had cars that get 40 by now."

Mitchell has been a strong booster of sustainability — meeting needs in a way that preserves resources for future generations — since the early 1970s. That's when an Arab oil embargo touched off oil shocks that cut U.S. fuel consumption, prompted switching from heating oil to natural gas and coal, and set off four decades of presidential rhetoric about achieving energy independence.

Bob Malone, president of London-based BP's U.S. arm, BP America in Houston, listed those pledges for independence dating back to the Nixon administration in a recent speech at a National Governors Association gathering in Philadelphia.

During the same stretch, U.S. energy consumption jumped 30 percent, Malone said. While efficiency has increased, "we might have done better if high-mileage, pollution-free vehicles we've been working so hard to develop had arrived in significant numbers." He added that current high energy prices stem from "a decades-long failure of U.S. energy policy."

Mitchell agrees.

"We used to try to work with Washington to no avail," he said.

But he kept pushing. While running Mitchell Energy & Development, a natural gas company he sold to Oklahoma City-based Devon Energy in 2002, Mitchell sought to encourage collaborative efforts to address food and energy needs as well as environmental issues as the globe's population grew.

In 1975, he established the Woodlands Conference Series to encourage business leaders, government representatives and universities to study sustainability issues. The Woodlands, a planned community north of Houston that Mitchell envisioned in the mid-1960s, had opened the previous year.

The conference series led to the founding in 1982 of the Woodlands-based Houston Area Research Center to study technical and policy issues with funds from contracts, grants, and gifts.

The most recent conference in the series was several years ago, but the research center evolved into what is now called the Houston Advanced Research Center, focusing on sustainability research, and its Center for Global Studies, which emphasizes environmental issues and sustainable development.

HARC is a consortium of universities, including the University of Houston, Rice University, the University of Texas at Austin and Mitchell's alma mater, Texas
A&M.

HARC's first research program in 1983 involved a laser study related to the federal government's Strategic Defense Initiative, a missile- and satellite-based shield against nuclear attack proposed that year by President Reagan.

Other research programs over the years include analyses of six possible superconducting super collider sites in Texas; HARC's Geotechnology Research Institute that seeks to improve oil and gas exploration technology; DNA technology research; development and testing of superconducting magnetic energy storage systems; establishment of a center for fuel cell research; and a team effort with Mexico's Monterrey Institute of Technology and Higher Education on water and development issues in the lower Rio Grande basin.

The center's work continues.

But conservation-heavy reactions to the 1970s oil shocks softened after oil prices plummeted in the 1980s. Fuel was cheap and plentiful, though the nation's dependence on foreign oil increased. For many Americans, interest in sustainability waned.

At the same time, European countries imposed high fuel taxes to keep consumers on the continent focused on conservation, efficiency and investment in public transportation.

"Europe was way ahead of us on that," Mitchell said.

The Paris-based International Energy Agency emphasized the same issues last month, supporting the Group of Eight industrialized nations' push for energy security and sustainability.

"With energy demand continuing to grow, prices breaking records and concern about climate change intensifying, we need policies that bring sustainable solutions," IEA executive director Nobuo Tanaka said when the recent G8 summit in Japan concluded, according to a statement. "The energy challenges we face — in terms of energy security and climate change — are global and call for a global response."

The need for global collaboration to achieve sustainability by addressing multiple issues — energy, food, the environment and population growth — is more important now, Mitchell said.

"Sustainability will be one of our most serious problems. Energy is part of it. The global climate is part of it. We need to do solar and wind, but they're not enough. Now we've got 6.5 billion people. In 2050, we'll have another 3 billion. If you can't make it work now, you've got more wars, more poverty, and everything you can think of," he said.

 

No-Blow Device for Removing and Stopping Steel Service Tees

Need to stop gas flowing so that ¾”, 1”,1 and ¼” , so even up to 2” Mueller tees can be replaced? Mazco Safety-T-Stopper is one answer. It has been upgraded to allow more flexibility. More and more adapters are being developed so that the tool can be used on steel and cast iron systems. The Safety-T-Stopper is a no-blow device designed for removing and stopping straight-gut, steel service tees. Several Canadian gas distribution companies are currently using it and at least one US gas distribution company is running it through its standards group.

The system is priced at $5,400 (Canadian) which includes a minimum of one set of attachments. A full set of attachments will add another $2,000 to the price.

Specifics of the Safety-T-Stopper can be viewed on Mazco’s website: http://www.mazcoproducts.com

Growing Pains en Route
Houston Chroncle (March 25, 2008) ; Tom Fowler

A rush of new projects moving natural gas from areas like Texas' Barnett Shale through a pair of Louisiana pipeline hubs could increase volatility for the fuel in the short term and drive down prices in the long term, according to a new study.

Some 40 pipeline, storage and liquefied natural gas terminal projects will come on line over the next 18 to 24 months, providing billions of cubic feet of new gas supplies for the key pipeline hubs of Perryville and Henry Hub in Louisiana.

Those new sources of fuel are likely to outpace capacity to move the fuel farther east to markets including Florida, Ohio and New York, according to data compiled by Bentek Energy, a Golden, Colo.-based research and consulting firm.

That could first mean greater price swings as markets figure out how to accommodate the new supplies and, ultimately, put downward pressure on prices because of oversupply.

Lower prices at the Henry Hub would affect prices throughout the country, because it's a widely used benchmark price.

"It's too much gas in the wrong place," said Rusty Braziel, managing director of Bentek. "It's going to be a roller coaster ride for a while."

Following the hurricane-induced price spikes of 2005, natural gas prices were relatively stable in 2006 and 2007, mostly trading in a range of $6 to $8 per million British thermal units.

In 2008, however, gas has been more volatile. Prices climbed as much as 35 percent earlier this month to more than $10 per million Btu, driven by winter demand and the expectation that natural gas imports would lag far behind last year's.

Prices have backed down somewhat but were up 26.4 cents on Monday, closing at $9.33 per million Btu on the New York Mercantile Exchange.

Higher prices have led to increased production in areas including the Rocky Mountains, Texas and Arkansas, and a boom in pipeline construction. A handful of large projects out of the Rockies will run through Illinois and Ohio, but a greater number of projects from Texas will go through an area Bentek refers to as the Southeast/Gulf region.

On average 29 percent of the pipeline capacity in the Southeast/Gulf is unused, but it tightens significantly during seasonal peaks. In the winter, when the Northeast draws heavily on natural gas for heating, that unused capacity shrinks to 10 percent.

In the summer peak, when gas-fired power plants come on line to handle the increase in air conditioning, that figure is closer to 7 percent.

But as pipeline projects from companies like CenterPoint Energy, Spectra Energy, Energy Transfer, Enterprise, Kinder Morgan and others are completed in the next two years, it will bring up to 14 billion cubic feet per day of new supplies into the Southeast/Gulf area.

Four liquefied natural gas terminals are also expected to open in the region in the next year — ranging from Freeport to Sabine Pass, La. — add- ing the potential for an additional 7.1 billion cubic feet of supply.

But only about 4.2 billion cubic feet of new projects are under way to move gas out of the Southeast/Gulf region to northern and eastern markets, Braziel said. Ultimately, the region could have 2 1/2 times more supply coming in than it can ship out.

A situation could develop similar to what occurred in the Rocky Mountains last summer when a surge of new production outpaced the new pipeline capacity being built out of the region. Prices in some parts of the Rockies fell as low as 5 cents per million Btu.

"I'm not saying that's going to happen with Henry Hub, but there's a similar dynamic at work," Braziel said.

 

For Exxon Mobil - Bragging Rights
Houston Chroncle (February 7, 2008) ; Kristen Hays

Offshore oil wells aren't out of reach for onshore drilling rigs.

And Exxon Mobil Corp.'s reach now stretches farther than anyone else's, more than seven miles from the frigid shores of Sakhalin Island off Russia's east coast, where the Chayvo oil field holds potentially a billion barrels of oil.

The world's largest oil company recently broke its own industry record for the longest "extended-reach" oil well. Such wells begin vertically on land and then curve to bore through layers of rock under the seabed to offshore reservoirs.

The well is 8,350 feet beneath the Sea of Okhotsk and 38,322 feet from shore to reservoir — about the length of 125 football fields. It blows past Exxon's previous record of 37,016 feet.

"It's almost an underground pipeline," said Joel Kiker, vice president of drilling for Exxon Mobil's development arm.

The 230-foot-tall Yastreb rig on the Chayvo project, operated by Houston-based Parker Drilling, also holds a title — the world's most powerful land drilling rig.

Such wells push technological limits to steer the drill bit and withstand massive pressures and temperatures. They also negate the need for pipelines and offshore platforms, particularly in harsh arctic areas like Sakhalin where conditions don't favor such installations and onshore facilities reduce environmental impact.

Jerome Schubert, an assistant professor of petroleum engineering at Texas A&M University whose research includes extended-reach drilling, said the practice isn't new. But pushing wells as far from shore as Exxon Mobil has illustrates how technological advances increase access to undersea oil.

"It kind of gives them bragging rights," Schubert said. "It's, 'We've gotten a little farther,' and it gives a target for someone else.

"But they're not going to try to beat the record just to beat the record. Every time they drill another extended-reach well, they get better at it."

To meet ever-growing global demand, companies are pushing to reach oil and gas in remote areas once deemed too difficult to tap. The Chayvo field was discovered nearly 30 years ago, but sat untouched until new technologies made it accessible.

Similar challenges also once hindered drilling in other areas, including the deep-water Gulf of Mexico. There, Chevron holds the record for the deepest vertical well — 34,189 feet in the company's Knotty Head development about 170 miles southeast of New Orleans.

A tricky salt layer

Deep water Gulf drilling requires the ability to plow through a thick, undulating salt layer as well as rock and sediment amid high pressures. The salt makes it more difficult to scope out reservoirs, even using 3-D seismic imaging that Exxon Mobil pioneered.

Kiker said the Sakhalin drilling doesn't contend with salt, but has a host of other challenges, including the need to control friction between pipe used in drilling and rock as the well-path curves to head offshore. And when the horizontal path traverses layers of softer rock it must be protected from caving in.

The Sakhalin team evaluates each step with real-time digital data, he said.

1996 agreement

Exxon Mobil began studying Sakhalin exploration in the late 1980s. In 1996, as the operator of a consortium that owns the multiphase project, the company forged an agreement with the Russian government to get started.

Exxon Mobil has a 30 percent interest in the project. The other partners are affiliates of Russia's Rosneft RN-Astra and Sakhalinmorneftetgas-Shelf; Japan's Sakhalin Oil and Gas Development; and India's ONGC Videsh.

The entire Sakhalin-1 project involves development of the Chayvo, Odoptu and Arkutun-Dagi fields, which combined have potentially recoverable reserves of 2.3 billion barrels of oil.

The first Chayvo well was drilled in 2003 and production began two years later. The project reached peak production of 250,000 barrels a day a year ago.

Since that first well was drilled, Exxon Mobil has slashed its drill time by half to about two months, Kiker said.

"We've been employing fast-drill for over a year. We're continuing to push the limits of what we've done before," he said.

BP in the game

Other companies in the extended-reach game include London-based BP, which is seeking permits and developing technology for its Liberty project, a 100 million-barrel field off the shores of Alaska's North Slope.

If approved, the project would involve drilling wells anticipated to be seven miles long or longer from an existing manmade island connected to shore by a four-mile causeway, BP spokesman Steve Reinhardt said.

 

Ultrasound Tool Can Combine Metal Loss And Crack Inspection Of Gas Pipelines
Pipeline & Gas Journal (08/07) P. 30 ; Vogel, Roger ; Pollard, Lee ; Yates, Ray
A new ultrasound inspection tool can pinpoint metal loss and cracks in gas pipelines in one shot. Modeled after a special configuration of the modular LineExplorer, the tool offers greater efficiency in pipeline preparation, operations and cleaning during inspections. The inspection tool also delivers improved data quality. As a proven and reliable technology for crack detection in pipelines, ultrasound is credited with ushering in a new generation of tools that integrate advances in electronic and mechanical design. New ultrasound tools feature a new and optimized sensor carrier design, which allows crack inspection and metal loss to be done at the same time. Combining metal loss and crack inspection capabilities enhances data quality, delivering more information to pipeline operators. This information, combined with reliable corrosion growth studies, remaining lifetime and fitness-for-purpose calculations offer a more accurate assessment of the true condition of the gas pipeline or pipeline system.

Energy Markets in 2040 Will Be Very Different
Pipeline & Gas Journal (05/07) Vol. 234 , No. 5 , P. 120 ; Learsy, Raymond J.

Energy analyst Raymond J. Learsy discusses what the condition of energy markets will be in 2040. Learsy says by that time, he believes there will be government-required restrictions on the use of fossil fuels, most particularly gas and petroleum-based fuels. In addition, he says, there will be a vast changeover from gas-powered vehicles to flex fuel, hybrid, and electric automobiles on the United States' roads. Learsy also thinks there will be a renaissance concerning train travel and a revamping of its infrastructure offering services that is similar to the European model, and of mass transportation overall. Next, he says, millions of acres will be handed over to raising crops for the manufacturing of agri-based ethanol which will be utilized to manufacture fuels to power the new offerings of bio-powered automobiles. Learsy feels the 54-cent per gallon tax on imported sugar cane ethanol from Brazil and other locations will be no more, and the oil-manufacturing facilities still around will be shielded against productivity pricing by offshore rivals by a nationwide floor price for hydrocarbons. He states there will be more oversight by the government of commodity trading pits and electronic trading of oil and all energy-associated products, and there will be substantial development of America's massive reserves of Western oil shale. "OPEC will have been reduced to an aged and toothless tiger," Learsy writes, and the United States will have set up a nationwide oil trust which will oversee and promote the energy resources located on federal lands.

Oil companies go deep into Gulf's potential
They are taking the bet they can extract oil lying 30,000 feet below the sea floor
Houston Chronicle Online - June 13, 2007 - Brett Clanton

 View Graphic: Oil and gas discovered deep in Gulf of Mexico

Last fall, a team led by Chevron Corp. became the toast of the oil industry when it demonstrated that an alluring deepwater region of the Gulf of Mexico could deliver on its promise.

Now, oil companies are taking concrete steps to unlock the area's potential, with an eye toward extracting oil from there in as little as two years.

Devon Energy Corp., an Oklahoma City-based firm with about 2,000 employees in Houston, is planning to drill what could be the first commercially producing oil field in the region by late 2009. Chevron has assembled a 60-person team to explore how it will develop the offshore frontier. Shell Oil has ordered a floating platform and plucked 200 employees to work on a project planned to come online by the turn of the decade. Others are also studying ways to turn prospects and discoveries into producing oil fields.

The activity has been spurred by predictions that up to 15 billion barrels of oil — enough to increase the nation's reserves by 50 percent — could be trapped in an ancient rockbed known as the lower tertiary.

The area of greatest interest, known in industry lexicon as the lower tertiary trend, has been hailed as the biggest discovery since
Alaska's North Slope in the late 1960s. It runs about 200 miles from the central Gulf of Mexico to the South Texas Coast, spanning an area about the size of West Virginia.

But the challenges of pulling oil from the region still loom large. Not only are the reservoirs more than 30,000 feet under the sea floor in places, they are hidden under nearly 10,000 feet of water. Getting to the rock means sending drills into densely compacted formations that will be stubborn in yielding resources and that may require new tools that can withstand higher temperatures and higher pressures. All of that means huge costs.

Last week, Devon talked of those challenges during a tour of the Ocean Endeavor, a newly renovated drilling rig it has under contract for the next four years as part of a huge company bet on the lower tertiary.

Stephen Hadden, Devon's senior vice president of exploration and production, compared the task to trying to thread a needle from 10 feet away in the dark. Yet if successful, the company could double its proven oil and gas reserves and see a huge return on investments, he said.

"The reward is worth the risk," he said.

Incentives growing

The excitement over the ultra-deepwater Gulf region comes as high commodity prices and growing global energy demands are providing incentive for companies to invest in higher-risk projects.

Chevron's successful test in September of its Jack No. 2 well told the industry that enough oil could be drawn from the lower tertiary trend to justify the massive investments.

"It proved that this trend could be produced economically and that it even holds a good potential to impact domestic and global oil production," said Matt Pickard, an analyst with Quest Offshore Resources in Sugar Land, which does market research and analysis for the global offshore energy industry.

The Jack well was completed and tested in 7,000 feet of water, and more than 20,000 feet under the sea floor, including a wide salt layer. Such layers, called salt canopies, have been obstacles for oil companies in the region because the formations hampered traditional seismic survey work needed to map underground deposits. But in recent years, more sophisticated 3-D seismic equipment has allowed oil companies to "see" through the salt.

12 finds and counting

So far, 12 discoveries have been announced in the lower tertiary trend since 2001, according to the Interior Department's Minerals Management Service. Yet that number could grow as international oil companies and state-owned firms including Brazil's Petrobras show more interest in the area.

Devon has leased more than 230 blocks — second only to Chevron — from the federal government. Each block is about 5,000 acres.

In coming weeks, Devon will use the Ocean Endeavor to drill a prospect well at its Chuck field, which it owns with Exxon Mobil and ConocoPhillips. Then, it will drill another well at Chevron's Jack field, in which it owns a partial stake. After that, it will move the massive rig to Cascade, a field in which it holds a majority interest and expects to begin producing oil from in 2009.

Each well will cost at least $100 million and take three to four months to drill, Devon said.

That's why operators are cautious about diving into the region too quickly.

James Cearley, Chevron's general manager of deepwater exploration, said Chevron's team is in the "earliest stage" of a feasibility study to determine how it should invest resources to develop oil fields in the lower tertiary trend.

The company won't begin producing oil in the region until at least 2010, he said.

Other firms, including Houston's BHP Billiton, have sold some stakes in discoveries to focus on lower-risk projects. Such moves are a reminder that not everyone is sold on the outer waters of the Gulf.

Gregory Simmons, Devon's manager of Gulf of Mexico deepwater exploration, said after many years in the industry and seeing many booms and busts, it is hard to blame them.

"Regardless of how good these look," he said, "there's never a sure thing."

Differential Impedance Obstacle Detection (DIOD) System