Exxon, Rubber Balls And Frac Treatments

Exxon/Mobil claims to have developed a new technique of continual, sequential hydraulic fracturing of tight sandstone gas reservoirs in long "horizontal" wellbores. The method allows one frac stage to be immediately sealed off by pumping "rubber balls" into the well immediately following the frac fluid and proppant. They then move up the hole and duplicate the process on the next zone. This allows them to frac and complete an entire well in a couple of days compared to what might take as long as a month using conventional technology.

Clearly Exxon/Mobil expects this technology to spread or they would not have publicized it. The cost-saving and production enhancing implications are significant. This development warrants watching. The article is by Elizabeth Souder/Dallas Morning News (source)
Peter

Exxon sees natural gas potential with new drilling technique

By Elizabeth Souder/ The Dallas Morning News (source)

03:23 PM CDT on Sunday, July 26, 2009

By ELIZABETH SOUDER / The Dallas Morning News
esouder@dallasnews.com (source)

RIFLE, Colo. – Dozens of workers mill around a jumble of pipes and whirring equipment surrounding 10 natural gas wells operated by Exxon Mobil Corp.

New technologies make natural gas drilling more efficient (DMN - Photography/Editing: Courtney Perry)

07/15/2009

At this well site in the desert, 80 miles west of the Rocky Mountains tourism hive, the men load cranes, operate pumps and monitor little red lines on computer screens. The work must happen simultaneously, in a carefully orchestrated ballet, to keep the well costs low – and profit high enough – to be worth the effort of the country's largest oil company.

"We're about 15 minutes away from a new frac being born," Randy Tolman, Exxon's project coordinator for the Piceance Basin, shouts over the noise. He invented this faster method of fracturing, or "fracing," the underground layers of rock and sand to unlock natural gas.

Exxon aims to export the new process to the unconventional natural gas reserves it is accumulating around the world. Drilling for more natural gas could make Exxon a lot of money as Americans demand cleaner fuel because natural gas doesn't emit as much pollution or greenhouse gases as oil and coal when burned.

"It's the bridge fuel," said Amy Jaffe, associate director of Rice University's energy program, adding: "It's going to be a 20-year bridge."

Exxon forecasts that natural gas demand will rise 50 percent by 2030 and outstrip demand for coal.

"Clearly, we anticipate that natural gas will grow much faster than oil or coal. So we see a pretty healthy demand out there in the future for natural gas globally, but even here in North America," chief executive Rex Tillerson said during an analyst meeting earlier this year.

At the gas well site in the desert, Exxon has drilled 10 holes, five of which already produce natural gas. The company's rigs in the Piceance (pronounced PEE-awns) Basin don't have to be reassembled between wells. Instead, the drill can move horizontally and laterally to reposition. This speeds the process and cuts the cost of rig crews.

As with many so-called unconventional natural gas fields in the U.S. and around the world, simply drilling a well here won't produce much gas. Operators must fracture the underground rock or sand around the well to allow more gas to flow out.

"This is a very complex reservoir, one of the most complex I've worked on in my 33 years," said Jim Branch, project executive with Exxon Mobil Production Co.

From months to weeks

In the 1980s, frac jobs could take months. Now a complicated frac typically takes a couple of weeks. Exxon's Tolman developed a method to fracture a Piceance Basin well in three days, and he thinks he can compress it to 24 hours.

The key is to conduct every activity simultaneously. Everybody thought that was impossible until Tolman persuaded his colleagues to experiment.

While working on a natural gas well in La Barge, Wyo., in the 1980s, Tolman noticed something strange. Natural gas was flowing out of the well without pushing out or damaging the wire that operators had dropped into the well.

Years later, while descending an elevator at Exxon's corporate building in Houston, Tolman had an idea. Why not use this phenomenon to perform simultaneous functions on a well? That's exactly what he is doing at the site in Colorado.

Plenty of other natural gas producers operate wells in the Piceance Basin, but Exxon controls the sweet spot on land owned by the Bureau of Land Management.

The company has been producing small amounts of natural gas in the basin since the 1950s, with interests on 300,000 acres, holding enough gas to heat 50 million homes for a decade.

Exxon began a significant expansion here in 2007, after scientists developed drilling and fracing methods that could make the operations profitable. Exxon now operates seven rigs in the Piceance Basin and produces 100 million cubic feet a day. Project executive Branch said the company could eventually increase to 1 billion cubic feet a day.

Long-term outlook

The current lull in natural gas prices won't deter him.

"We're taking a long-term view," Branch said, repeating Exxon's mantra. He won't say whether the operations are profitable, with natural gas future prices trading below $4 per thousand cubic feet. Last summer, prices rose above $13.

Chief executive Tillerson said he's not specifically aiming to become more of a natural gas company than an oil company. Right now, Exxon's production is split about evenly between the two, and the company's strategy is to simply pursue the best projects each year.

"We don't have a deliberate strategy to change the oil-gas mix," Tillerson said during a news conference after the company's annual meeting earlier this year.

Analysts say a shift is evident and necessary.

Exxon's total natural gas sales have declined four out of the past five years, dropping 1.5 percent in 2008 to 10,812 million cubic feet per day. Production dropped 3 percent last year, although the company produced more natural gas than it discovered.

"By the time Exxon shifts, it will take three to five years before you see anything that's noticeable," said Oppenheimer & Co. analyst Fadel Gheit. "There is no instant gratification in anything they do."

The company has announced adding a number of unconventional resources to its books during the last few years, including fields in Germany, Eastern Europe, Canada and the Marcellus shale in the Northeast U.S.

"The future of unconventional shale gas, there's a pretty bright future," Tillerson said after the annual meeting. He said he's considering other fields as well, where Exxon can use its strategy of getting in cheaply, holding the resources for a long time and applying fresh technology.

Many of Exxon's new fields are shales, similar to the Barnett Shale in North Texas, where Exxon had a joint venture but sold out. The Piceance Basin isn't shale but sand. The company hasn't tried the new technology on shale reserves, and officials won't say where, exactly, they will try the process next.

"We haven't done it yet" on shales, Tolman said. "But I think there's a great opportunity."

Frac central

At the desert well site, workers wearing fireproof jumpsuits and hard hats in the summer heat have positioned the wire in the well. The frac water is flowing, and the pressure is building.

The frac specialists inside a (mercifully) air-conditioned trailer – some of them Halliburton employees working on a contract for Exxon – prepare to shoot electronic pulses from the wire.

The men watch colorful computer screens to monitor pressure created by pumping a mixture of sand, water and chemicals into the well. When the pressure is just right, they shoot the frac gun, then drop rubber balls into the well to plug the frac holes, and immediately repeat the process.

"Nineteen hundred until ball drop," says Ron Campbell, an Exxon workover superintendent manning one of the computers in the trailer. He's talking to the outdoor crews over a radio while staring at screens that monitor well pressure and tension on the wire lines.

Five other workers inside the trailer check computer monitors and scour instruction booklets. Scattered around the desk are bottles of water and Gatorade, a hard hat, a calculator and a half-eaten bag of Uncle Bob's Party Mix.

The red line on one of the screens rises. Over the radio, somebody says: "Shot is fired."

The red line wiggles as the rubber balls reach their holes and pressure inside the well builds.

"The frac is being a little bit fussy," Tolman says.

The men will fire the frac gun seven times today. While one gun is shooting the first well, they will load the second gun for well No. 2, back and forth, so that the men and the equipment are constantly working.

The natural gas will go through a treatment facility for cleaning, then into the U.S. pipeline system, bound for home cooktops, power plants and chemical facilities across the nation.

Most energy experts agree that demand for natural gas will surely rise if a bill to cut greenhouse gas emissions becomes law. The bill passed the House and awaits consideration by the Senate.

Renewable fuel sources can serve only a sliver of U.S. demand. Until more wind farms and solar arrays can be installed, Americans would have to rely on natural gas to comply with the new regulations. Natural gas emits less of the greenhouse gases thought to cause climate change than coal.

And, thanks to new drilling technologies, the U.S. has plenty of natural gas to meet the rules. According to the Energy Information Association, proved U.S. natural gas reserves in 2007, the most recent data, have risen by one-third to 237,726 billion cubic feet since 2002, just as the new techniques were becoming popular.

In fact, most experts agree that new technology, such as the Exxon process, offers the only hope of immediately meeting the greenhouse gas emissions goals outlined in the bill.

Natural Gas Powered Vehicles Make Sense

It makes sense to convert existing vehicles and build new ones to burn compressed natural gas rather than gasoline and diesel fuel derived from petroleum (crude oil). If the government sweetens the deal with large tax credits, as they are proposing, so much the better.

Will this solve our energy "problems" and stop "climate change"? No. Will it create jobs, increase tax revenue, and decrease our dependence on foreign oil? Yes, most definitely. Go for it, Democrats and Republicans. Vote for it.
Peter

Big Tax Breaks for Natural Gas Vehicles in New Senate Bill

WASHINGTON, DC, July 10, 2009 (ENS) - A bill that allows a tax credit of up to $12,500 for the purchase of a natural gas-fueled vehicle was introduced in the U.S. Senate this week.

The bipartisan legislation, S. 1408, would extend and increase tax credits for natural gas vehicles and refueling. It is sponsored by Senator Robert Menendez, a New Jersey Democrat, with Senate Majority Leader Harry Reid of Nevada and Senator Orrin Hatch, a Utah Republican as original co-sponsors.

Said Menendez, "We saw last summer how the wild fluctuations in oil prices helped to wreck our economy and we’ve seen how pollutants from dirty fuels are wrecking our planet. Our economic crisis has shined a spotlight on the urgent need for alternative, cleaner and cheaper sources of energy that we don’t have to import. By making it easier and cheaper to own a vehicle that runs on natural gas, we can help families save money on energy, create new manufacturing jobs and clean our air."

"Because of new extraction techniques," Menendez told reporters, "We now have 35 percent more accessible natural gas than we did two years ago."

The bill, known as the NAT GAS Act, extends for 10 years the alternative fuel credits for natural gas used as a vehicle fuel, the purchase of natural gas-fueled vehicle, and the installation of natural gas vehicle refueling property credit.

"Each day, our nation consumes about 21 million barrels of oil - more than 25 percent of the world’s oil supply," said Senator Reid. "Nearly 70 percent is imported from outside our borders. With only three percent of the world’s oil reserves, we cannot produce our way to a safe and secure energy future. I’m proud to join with Senators Menendez and Hatch in introducing legislation that will help encourage the development of natural gas vehicles to help save consumers and operators thousands of dollars per year, protect our environment, and decrease our dependence on foreign energy."

Burning natural gas produces far less air pollution than burning gasoline. According to the U.S. Environmental Protection Agency, cars running on natural gas cut overall toxic emissions by at least 93 percent compared to gasoline.

"We must get serious about using cleaner burning natural gas and renewable energy, and this legislation is a strong step in the right direction," said Reid.

T. Boone Pickens listens as Senator Orrin Hatch tells reporters why he supports tax credits to spur the use of natural gas. (Photo courtesy Office of the Senator)

Natural gas is an abundant resource, with 98 percent of natural gas used in the United States originating in North America, a key reason for his support of this bill, said Senator Hatch.

"Natural gas is an important alternative fuel to help pave the way to energy independence, which will not only help keep us safer, but will also help reduce the high cost of fuel and, thus, high utility bills across the board," Hatch said.

"In our current economic downturn, it’s crucial to provide appropriate incentives that lead to lower prices for all Americans," he said. This piece of legislation does just that while also helping clean up our environment; I am a proud cosponsor."

Billionaire T. Boone Pickens, who drove his CNG-fueled Honda GX Civic to the news conference introducing the bill on Wednesday, said, "This bipartisan legislation does more to reduce our foreign oil dependency crisis than any other piece of legislation in the past 40 years. As I have said many times before and will continue to say, natural gas is cleaner, cheaper, it’s abundant and it’s American."

"This bill will accelerate the use of natural gas in vehicles and is the only way I know to quickly and effectively reduce our dependence on foreign oil," Pickens said. "For too long, our dependence on foreign oil has been one of the factors influencing our foreign policy and if we can eliminate that issue by using our own domestic natural gas resources I am confident that it will benefit our national security, our economy and the environment."

Pickens stands to benefit from passage of the legislation. The company he founded, Clean Energy Fuels Corp., owns and operates natural gas fueling stations from British Columbia to the Mexican border.

The largest provider of natural gas for transportation in North America, on June 30, Clean Energy opened the world’s largest natural gas truck fueling station on a site adjacent to the Ports of Long Beach and Los Angeles. Natural gas has the ability to displace 100 percent of the petroleum currently used in heavy-duty vehicles, according to the EPA.

If the bill becomes law, it would increase the refueling property tax credit from $50,000 to $100,000 per station, a provision from which Pickens' company would benefit.

The state of Utah also stands to benefit from this legislation. Americans use more than 22 trillion cubic feet of natural gas per year. There are an estimated 350 trillion cubic feet of natural gas in Utah and surrounding states. Currently, natural gas for vehicles sells for 88 cents per gallon in Utah, and at least 5,000 Utah drivers fuel their cars and trucks with natural gas.

In February, Utah Governor Jon Huntsman announced plans to increase the state’s natural gas vehicle fueling infrastructure and in his State of the State address designated Interstate 15 (I-15) from Idaho to Arizona as a natural gas vehicle corridor.

Demand for natural gas as a vehicle fuel has quadrupled during 2008, Huntsman's office says. Today, the state of Utah and the utility Questar Gas own and operate 25 natural gas fueling stations that are open to the public.

The legislation S. 1408:

• Allows the natural gas vehicle and natural gas fueling infrastructure credits to be transferred by the taxpayer back to the seller or to the lessor
  
• Allows state and local governmental entities to issue tax exempt bonds to finance natural gas vehicle projects.
  
• Allows 100 percent of the cost of a natural gas vehicle manufacturing facility that is placed in service before January 1, 2015 to be expensed and to be treated as a deduction in the taxable year in which the facility was placed in service. This decreases to 50 percent after December 31, 2014 and is phased out by January 1, 2020.
  
• Requires that when complying with mandatory federal fleet alternative fuel vehicle purchase requirements, federal agencies shall purchase dedicated alternative fuel vehicles unless the agency can show that alternative fuel is unavailable or that purchasing such vehicles would be impractical.
  
• Provides for grants for light-duty and heavy-duty natural gas engine development.

Copyright Environment News Service, ENS, 2009. All rights reserved.

Good News For Gas Producers

This is very good news for producers of natural gas in America and Canada. Natural gas can be compressed (CNG) and used in conventional internal combustion engines with very little modification. It appears the United States and Canada have abundant supplies of natural gas, especially considering the relatively recent discovery of how to produce gas from common organic rich shale, or so-called Shale Gas.

There is no doubt that finding and developing more of this gas will create American jobs, increase tax revenue, decrease our dependence upon foreign sources of oil and be a good thing for our economy in general. The technology and infrastructure to accomplish all of this is in place, ready to go.

Many examples of these Shale Gas Plays are exhibited on this blog. Some of these shales include the Barnett, Haynesville, Fayetteville, Marcellus, and the Woodford. These articles can be found on this blog through the search function.
Peter

Natural-Gas Vehicles Gain Senate Backing; Gas-Price Jump Seen By Siobhan Hughes, Of DOW JONES NEWSWIRES WASHINGTON -(Dow Jones)- A plan to encourage more natural-gas vehicles in the U.S. got a new push on Wednesday, as the top Democrat in the Senate backed legislation to provide tax breaks and other incentives for the vehicles. But underscoring the trade-offs involved in turning the U.S. away from oil as a transportation fuel, one of the plan's biggest backers said that it would cause gas prices to double from current levels. That could be a problem for households that use gas to heat their homes or gas-fired power plants, though fueling vehicles would remain relatively inexpensive. "Will it bring the price up?" billionaire energy investor T. Boone Pickens said in a response to a question at a press conference on Capitol Hill. "It will probably." He estimated that prices would rise to about $7 per thousand cubic feet, compared with prices that would translate into about $3.46 per thousand cubic feet in recent trading. Pickens joined two senators at a press conference to promote the legislation, which is also backed by Senate Majority Leader Harry Reid, D-Nev. The plan would extend tax breaks for buying natural-gas vehicles, provide grants to develop light- and heavy-duty gas engines, and provide incentives to build refueling stations. Besides turning away from foreign oil, the goal is to turn to a fuel that produces fewer greenhouse-gas emissions. "Natural gas is not the ultimate solution at ending our dependence on foreign oil," said Sen. Bob Menendez, D-N.J., one of the sponsors. "But natural-gas vehicles must be part of the solution as well, because With new extraction techniques we now have 35% more accessible natural gas than we did two years ago." The plan has been promoted for at least a year by Pickens and a fellow gas man, Chesapeake Energy Corp. (CHK) Chief Executive Aubrey McClendon. The two got a boost last year, when Rahm Emanuel, who at the time was a lawmaker in the U.S. House of Representatives and now serves as chief of staff to U.S. President Barack Obama, introduced a natural-gas vehicle bill. Though the full measure never became law, it helped elevate the topic within the highest levels of the U.S. Congress. Behind the push is the discovery of vast new amounts of gas locked up in rock formations -- known as shale -- around the U.S. The gas fields in Texas, Louisiana and Pennsylvania led the nonprofit Potential Gas Committee to announce that the U.S. has 2,074 trillion cubic feet of natural gas still in the ground, or nearly a century's worth of production at current rates. That is up 35% from the previous estimate in 2007. For drilling in those regions to be truly economic, prices would need to rise. At $7, Pickens estimated that the cost of refueling a natural-gas vehicle would still be cheaper than using conventional gasoline, as a thousand cubic feet of gas contains the same amount of energy as eight gallons of gas, which would cost between $20 and $24 at current prices. Gas would also be cleaner: Cars that run on compressed natural gas generate 25% fewer carbon-dioxide emissions than cars that run on conventional gasoline, according to an earlier U.S. Environmental Protection Agency estimate. Separately, Pickens denied a report that he was scaling back a plan to build the world's biggest wind farm to five or six smaller farms. Speaking to reporters after the press conference, he said "I didn't cancel it." He said " it's going to be delayed about a year or two." -By Siobhan Hughes, Dow Jones Newswires; 202-862-6654; Siobhan.Hughes@ dowjones.com

Natural Gas-Powered Vehicles....A Good Thing

Bill in US Congress to Boost Natural Gas Vehicles

2 April 2009

US Congressman Dan Boren (D-OK-02), Democratic Caucus Chairman John Larson (D-CT-01), Congressman John Sullivan (R-OK-01) have introduced a bill to expand the use of natural gas as an alternative to conventional transportation fuel.

Provisions of the New Alternative Transportation to Give Americans Solutions Act, or NAT GAS Act (H.R. 1835) include:

• An 18-year extension of three critical tax incentives that focus on natural gas as a transportation fuel, the purchase of natural gas-fueled vehicles (NGVs), and the installation of commercial and residential natural gas refueling pumps.

  Currently, the alternative fuel credit expires at the end of 2009, and the vehicle and refueling pump credits expire at the end of 2010. The legislation would also modify the current tax credits to provide even greater incentive for state and municipal fleet managers to buy natural gas vehicles and engines.

• A new tax credit for auto manufacturers that produce natural gas and bi-fuel vehicles.

• A requirement that by the end of 2014 at least 50% of the new vehicles purchased and placed into service by the federal government to be capable of operating on compressed or liquid natural gas.

• Grants for light and heavy-duty natural gas vehicle and engine development.

Haynesville Shale Gas Play Continues With Positive Results

Operators in the Haynesville Shale Gas Play have reduced their drilling activity "until drilling and completion costs are reduced to acceptable levels". What is acceptable? I seems to me these costs are fairly inflexible. These wells are expensive and cutting costs can be dangerous and counter-productive. What really is needed is higher natural gas prices. My guess is the price will increase when demand increases.
Peter

Haynesville well results encourage operators

By OGJ editors (source)
HOUSTON, July 15 -- Forest Oil Corp., Denver, and Goodrich Petroleum Corp., Houston, reported results from recent Jurassic Haynesville horizontal well completions in Louisiana and East Texas.

Forest, meanwhile, said it operated only four rigs in this year’s second quarter and continues to defer significant investments until drilling and completion costs are reduced to acceptable levels to support a larger drilling program at current natural gas prices.

In Red River Parish, La., the Driver 13-1H well produced into a sales line at 20.3 MMcfd of gas equivalent with 6,500 psi flowing casing pressure in early July. It had 10 frac stages in a 3,500-ft horizontal leg and cost $9 million.

Forest has identified 110 potential horizontal locations on the 11,050 Haynesville prospective net acres it holds in Louisiana. It will maintain a one-rig program in the parish for the rest of 2009 and one rig in other prospective areas of the play in Texas and Louisiana.

Goodrich Petroleum said the Taylor Sealey-3H in Panola County, Tex., produced at 9.3 MMcfd with 5,200 psi on a 24/64-in. choke. It is in Minden field 6 miles south of the Lutheran Church-5H well that had an initial rate of 9 MMcfd. The company has 100% working interest.

The company reached total depth at two other Haynesville shale horizontal wells, T. Swiley-4H in Minden field and Beard Taylor-1H in Beckville field.

Goodrich Petroleum also held interests in three wells completed by Chesapeake Energy Corp. in Bethany-Longstreet field, Caddo and DeSoto Parishes, La.

Initial rates were 12.5 MMcfd with 7,800 psi on an 18/64-in. choke at Johnson 32H-1, Goodrich 31%; 15.4 MMcfd with 6,100 psi on a 22/64-in. choke at Wallace 36H-1, Goodrich 22%; and 14 MMcfd with 4,000 psi on a 22/64-in. choke at the Bryan 25H-1, Goodrich 13%.

More On The Three Forks Play In The Willistion Basin

We must be slightly skeptical about everything reported by companies testing the new Three Forks Play in the Williston Basin. This includes flow, or production rates, drilling costs and numbers of frac jobs. Most companies tend to exaggerate the positive and downplay the negative. The trick is to be able to "read between the lines" about what is being said. In any case, the Three Forks Play looks interesting. Brigham Exploration drilling 20,000 foot laterals (horizontal wells) is impressive. We'll be hearing more about this play for sure.
Peter

Three Forks rates rise as drilling costs fall

By OGJ editors (source)
HOUSTON, July 15 -- Operators are climbing the learning curve in the Williston basin by drilling long lateral wells in the Bakken and Three Forks formations with as many as 24 frac stages.

One operator, Brigham Exploration Co., Austin, Tex., said it is continuing to see drilling and completion costs fall.

Initial rate at the Strobeck 27-34, in the Ross area of Mountrail County, ND, is 1,788 b/d of oil and 1.4 MMcfd of gas from a long lateral in Three Forks. Brigham Exploration completed the well with 20 frac stimulation stages, 18 of which were effective.

Strobeck 27-34, which appears to have had the basin’s second highest initial rate for a Three Forks completion, cost $3.9 million, 33% lower than company late 2008 authority for expenditures at similar wells.

“The Strobeck 27-34 results also confirm the core taken from our Anderson 28-33, which indicated that both the upper Three Forks and middle Bakken formations were heavily saturated with oil,” the company said.

Anderson is 1 mile west of Strobeck and about a mile southwest of Brigham Exploration’s Carkuff-22 1H, which went on production at 1,110 b/d of oil after 12 frac stages in a short lateral.

The company recently drilled the lateral of its Anderson 28-33 on a 1,280-acre unit in the Ross area to 19,900 ft in the Bakken and ran 24 swell packers to bottom. A 24-stage frac operation, believed to be a record number for the basin, is planned in early August.

Brigham Exploration has spud the Brad Olson-1H 9-16 well in the Rough Rider area of Williams County, ND, and plans 24 frac stages in an intended 20,000-ft Bakken lateral at an estimated cost of $6.25 million, 34% less than 2008 AFEs.

Brigham Exploration controls 35,200 net acres in the Ross area and 100,345 net acres in the Rough Rider area. It is participating in 20 Mountrail County Bakken wells operated by others in various stages, including 12 already on production.

Three Forks: A New Play In The Williston Basin?

North Dakota could have a huge new oil field

Wells in North Dakota's Bakken shale show promise for huge new oil deposit

• By James Macpherson, Associated Press Writer
• On Tuesday July 14, 2009, 1:46 pm EDT

BISMARCK, N.D. (AP) -- Dozens of fruitful wells beneath the rich Bakken shale in North Dakota continue to fuel a hunch among oilmen and geologists that another vast crude-bearing formation may be buried in the state's vast oil patch.

Lynn Helms, director of the state Department of Mineral Resources, said recent production results from 103 newly tapped wells in the Three Forks-Sanish formation show many that are "as good or better" than some in the Bakken, which lies two miles under the surface in western North Dakota and holds billions of barrels of oil.

"I think it's a big deal and we're pretty fired up about it," Helms said.

Companies have reported some Three Forks wells recovering more than 800 barrels daily, considered decent by Bakken standards.

Denver-based Whiting Petroleum Corp. has drilled two wells in the Three Forks formation, with one that recorded more than 1,000 barrels of oil a day, said John Kelso, a company spokesman.

"We are excited about Three Forks but it's early on in the play," Kelso said. "I do know a lot of companies are redirecting focus from the Bakken to Three Forks."

Whiting has one Bakken well that recorded more than 4,000 barrels a day last year, thought to be a record for the formation and about double the highest Three Forks well drilled to date.

Kelso said Whiting's primary focus at present is on the Bakken. The company has more than 300,000 acres under lease in North Dakota.

"With the turbulence in crude oil prices, we've kind of backed off Three Forks for the Bakken," Kelso said. "We will very likely get after Three Forks in 2010, depending on oil prices.

The Bakken formation encompasses some 25,000 square miles within the Williston Basin in North Dakota and Montana. The U.S. Geological Survey has called it the largest continuous oil accumulation it has ever assessed.

The Three Forks-Sanish formation is made up of sand and porous rock directly below the Bakken shale. But geologists don't know whether the Three Forks-Sanish is a separate oil-producing formation or if it catches oil that flows from the Bakken shale above.

Fort Worth, Texas-based XTO Energy Inc. has reported to the state that one of its Three Forks wells pulled more than 2,100 barrels a day. An ETO Energy spokeswoman said the company does not comment on its operations publicly.

State and industry officials are conducting a study to determine whether the Three Forks is a unique reservoir. The plan is to compare results from closely spaced wells, one aiming for the Three Forks, and the other at the Bakken. Researchers will look at pressure changes in the formations to determine if they are connected.

Results from the study could be ready later this year, officials say. It already is spurring some speculation that the state has billions of barrels more in oil reserves.

"Eventually it could equal the Bakken, which is remarkable, and that's an understatement," Helms said.

"Is it the same or is it a separate formation? I think everybody is hoping for the latter," Harms said. "That could literally double the potential we have -- a Bakken 2, if you will."

Kelso, of Whiting Petroleum, said his company's drilling activity shows that Three Forks likely is a separate formation. He said core samples taken from the Bakken and Three Forks show more hydrocarbons in the latter.

"From the core samples, Three Forks looks better for us than the Bakken," he said.

Promising production results from the Three Forks could mean that companies that come up empty in the Bakken could use existing leases to drill in the same area for Three Forks oil.

Geologists say the Three Forks-Sanish is typically about 250 feet thick. Julie LeFever, a geologist with the state Geological Survey in Grand Forks, has studied the Bakken for two decades. She believes oil found in the Three Forks-Sanish has come from the Bakken over millions of years.

"It's probably all the same source system. The reservoir may or may not be unique," she said. "We're still trying to figure out what makes the whole formation tick."

"It's another target," LeFever said. "If the Bakken doesn't pay, maybe the Three Forks will."

Most companies working in the state's oil patch continue to focus solely on the Bakken, said Ron Ness, president of the North Dakota Petroleum Council, a Bismarck-based group that represents about 160 companies.

"I think it's a huge deal," Ness said of the emerging Three Forks play. "But it is still vastly unknown and overshadowed by the urgency to develop the Bakken."

Donald Kessel, vice president of Houston-based Murex Petroleum Corp., said his company was among the first to get a producing well in the Bakken in North Dakota about four years ago. The company now has 26 producing wells in the Tioga and Stanley areas of northwestern North Dakota.

Kessel believes that not all of the Three Forks is laden with oil.

"Right now, we're doing Bakken, and in those areas it doesn't look like the Three Forks is going to work," he said.

"With Three Forks, you have got to find a sweet spot where it develops," Kessel said. "It is not sandwiched like the Bakken between two shales producing oil."

Oilmen and others had known for years that the Bakken held oil. High oil prices and demand in the past few years spurred technology enough to begin tapping it.

Kessel said techniques learned from the Bakken are now being used at other oil shales in the U.S. and internationally. But he said advances in technology have slowed with lower oil prices that have idled drill rigs.

"Technology is not moving at the same pace because there are fewer well bores to do it at," Kessel said.

State geologist Ed Murphy said researchers will know more about the characteristics and potential of the Three Forks formation once more wells are tapped into it.

"One-hundred wells is not that many wells when you're trying to look at overall trends," Murphy said. "Everyone will feel a lot safer with 100 or 200 more wells down the road."

Drilling and well completion technology developed for the Bakken formation likely also could be used in the half-dozen formations above the Bakken and the dozen or so that reach 4,000 feet below it, he said.

Multi-Client 3-D Seismic In Haynesville Shale Play

source

CGGVeritas Records First Data on Shale Gas Tri-Parish 3D Multi-Client Survey in Haynesville

Houston, 7 July 2009 CGGVeritas announced today that it has begun acquiring the Tri-Parish Line 3D multi-client survey in northern Louisiana. The 677-square mile wide-azimuth survey is the largest contiguous Haynesville shale survey to date. It is designed to supply the numerous industry players with a state-of-the-art 3D survey to help them locate the hundreds of horizontal wells that are expected to be drilled in the play. The CGGVeritas Tri-Parish Line 3D multi-client survey in northern Louisiana, USA. View/download larger map. CGGVeritas will operate two separate 7,000-channel crews to acquire the survey over the next 12 months. The configuration of the wide-azimuth survey was specifically designed to enable enhanced fracture detection and understanding, critical parameters for exploration and production. Original participants will systematically receive 3D processed seismic volumes as each phase of the year-long survey is completed. Colin Murdoch, Executive Vice President, North America region, CGGVeritas, said: "The U.S. Gulf Coast has been a primary focus area for CGGVeritas for over ten years. We believe this advanced Tri-Parish Line survey in the heart of the Haynesville shale play will be a key part of our data library assets for years to come." The Haynesville shale is a gas resource play located in northeast Texas and north Louisiana. It is one of the most active horizontal drilling areas in the US. About CGGVeritas CGGVeritas (www.cggveritas.com) is a leading international pure-play geophysical company delivering a wide range of technologies, services and equipment through Sercel, to its broad base of customers mainly throughout the global oil and gas industry. Contacts US Land Data Library Scott Tinley, Tel: +1 832 351 8544 Email: scott.tinley@cggveritas.com Media Relations Sara Pink-Zerling Tel: + 33 (1) 64 47 38 83 Email: sara.pink-zerling@cggveritas.com

The Haynesville Shale and Hydraulic Fracturing

Drilling a horizontal well is just half the story. The next vital step is completing the well. In the case of a shale gas play like the Haynesville, this means successful, multi-stage hydraulic fracturing of the formation. There are many variables to consider. Here is an example:
Peter

HAYNESVILLE SHALE - HYDRAULIC FRACTURE STIMULATION APPROACH

Mark Parker, Halliburton

Abstract (source)

The Haynesville Shale is an ultra low permeability unconventional gas reservoir located in East Texas and Northwest Louisiana. High gas prices and the success of other shale gas plays have led operators to invest highly in this resource play. It has great potential for development by applying all the new technology that is available in the Oil and Gas Industry today. Hydraulic fracturing is required to realize the potential of this reservoir. The nature of the formation requires that it be addressed on its own merits and not be considered an analog to other shale reservoirs. Therefore, cookbook recipes for fracture stimulation treatments will not lead to the optimum production results.

A critical evaluation of the target zones and the boundary layers is necessary for an accurate treatment design using available fracture simulators. An understanding of the formation characteristics and how they impact the development of fracture geometry and proppant placement can lead to improved success.

This paper will review the design process and the technologies that are required to achieve the best production results. Examples of pumping schedules and fracture design output are presented to illustrate the following: * Design approach * Isolation mechanism (pump down technology, CT technology, e-coil) for horizontal completions * Fracture design tools (process logs to identify correct fracture initiation points, fracture design programs, DFIT, Microseismic fracture mapping) * Fluid systems and additives * Proppant recommendations

US and Canadian Shale Gas Plays Examined

Study analyzes nine US, Canada shale gas plays

A recent study has estimated that nine US and Canada shale-gas plays may produce as much as 24 bcfd by 2018. (source)

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The Oct. 6, 2008, Tristone Capital Inc. study evaluated the gas resources in the Bamett (Fort Worth basin), Deep Bossier, Haynesville, Fayetteville, Woodford, and Marcellus shales in the US and the Montney, Hom River (Muskwa), and Utica shales in Canada (Fig. 1).

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The study expects companies ultimately to recover from these resources 261 tcf of gas, based on various risk factors applied and a long-term average gas price of $8.50/MMbtu. Without the risk factors, Tristone Capital says these shales have a 743-tcf recovery potential (Fig. 2).

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Fig. 3 shows the study’s estimated production from these plays, and Fig. 4 shows its US well completion forecast.

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Several emerging shale plays with limited well control also may contribute additional gas to future production, according to the study. These include the Pearsall shales in the Maverick basin of South Texas, the Niobrara shales of Western Colorado, and the Barnett shale in the Delaware basin of West Texas.

Shale play comparison

The study says that shale-gas plays owe their success to a balance of various parameters along with constantly evolving drilling and completion techniques and infrastructure. “It is commonly said that no two shale gas plays are exactly alike,” the study says.

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Table 1 summarizes shale-gas play attributes, and Fig. 5 compares the arithmetic average of the attributes. The study notes that the most productive core portions of plays may deviate from the averages.

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Multistage hydraulic fracturing along a horizontal lateral and improvements in stimulation are main factors influencing shale-gas development economics. The study says these factors have improved economics by more than three times from that of vertical well developments by improving both ultimate recovery and initial production rates.

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Table 2 compares typical lateral lengths and frac treatments for the nine plays.

The three types of frac fluid noted are slick water, CO₂-polymer, and gelled cross-linked oil-based fluid.

Slick-water fracs use a nongelled fracturing fluid with low proppant concentrations and a friction-reducing chemical additive that allows pumping the water into the reservoir faster. The fluid often is a brine or potassium chloride (KCl) water to inhibit swelling of clays. The study notes that this fluid is less expensive than hydrocarbon-based fluid and works best in low-permeability reservoirs

Companies pioneered slick-water fracs first in the Fort Worth basin’s Barnett shale.

The CO₂-polymer frac fluid contains emulsified CO₂ in a methanol-water mixture of 5% water and 20% methanol. The study says the mixture appears to minimize reservoir damage and maximize fluid recovery from multiple diversions in the well. Including CO₂ also reduces by 25% the fluid required and provides extra energy, as the gas expands, during frac fluid flow-back greatly to shorten cleanup time, the study says.

The Montney formation in British Columbia is where companies use this fluid. The study notes that stimulating a horizontal well in the Montney typically involves perforating, isolating, and fracturing 6-11 zones at a cost of about $100,000- 120,000/frac interval. It is common to spend more than $1 million for fracturing these wells, the study says. The study describes these jobs as needing 8-10 pump trucks or about 18,000-22,500 hp and taking more than 1 week to complete.

The study notes that companies initially used gelled cross-linked oil-based fluids as the “fluid of choice” for hydraulic fracturing because of its compatibility with most formations and its cold weather attributes. In several basins, slickwater fracs have replaced oil-based fracs because the slick water uses less water and costs less, the study says.

To prevent swelling and permeability loss in the shales, companies typically continue to use oil-based frac fluids in formations that contain extensive water-sensitive clays. The study notes that these fluids are used in the Fayetteville, Haynesville, and Woodford shales.

Fort Worth basin Barnett

Development activity continues to evolve with part of the current activity in urban sites such as Fort Worth and the Dallas-Fort Worth airports.

The study notes that as of Aug. 18, 2008, the Barnett had 8,416 gas wells drilled in 19 counties. Production had increased to 3.8 bcfd in first-quarter 2008 from 219 MMcfd in 2000. The study expects the shale to produce 6-7 bcfd in the next 5 years.

Some of the newer techniques in the play noted in the study are:

• Longer horizontal laterals, up to 3,500 ft, often drilled from pads with multiple wells, especially in the urban areas.
• Testing of tighter well density with laterals, spaced 250-ft apart (25-30) compared with 500 ft between laterals (50-acre spacing).
• Simultaneous fracing of wells to increase recovery.

Deep Bossier

Wells in Deep Bossier of East Texas reach a 15,000-20,000 ft depth, have pressures of about 15,000 psi, and have tested at 65 MMcfd. The study notes that these wells are expensive, costing $10-20/million for a vertical well.

Currently the play has six main fields in four counties: Robertson, Leon, Freestone, and Limestone.

Fayetteville

The Fayetteville shale in Arkansas is the shallower and thinner equivalent of the Barnett shale. The core of the play is in five counties in central Arkansas: Cleburne, Van Buren, Conway, Faulkner, and White.

The study says as of May 31, 2008, the play had 877 producing wells, with production in July of 740 MMcfd compared to only 90 MMcfd in December 2006. The study expects the play to produce 3.15 bcfd by 2018.

Haynesville

The Haynesville shale is in northwestern Louisiana and East Texas. Wells in the play initially have produced 5-20 MMcfd, the study said. The study expects wells to have ultimate gas recovers of 4-8 bcf.

Currently, companies have drilled about 20-25 horizontal wells in the play, and the study expects about 60-80 rigs could be active in the play by yearend 2008, with most of the drilling in Caddo and DeSoto Parishes in Louisiana.

Woodford

The Devonian-aged Woodford shale lies at 6,000-14,000 ft depths in the Arkoma basin of southeast Oklahoma. The study notes that the $6 million well cost in the Woodford is more than the $2-3/million/well cost in the Fayetteville and Barnett shales.

The study estimates that an 80-acre well in the Woodford will recover about 4 bcf of gas.

Marcellus

The Marcellus shale in the Appalachia basin extends over several states, although most wells drilled to date have been in Pennsylvania, the study notes.

It says Marcellus production has been minimal to date because of the need to expand the existing infrastructure to accommodate the high-pressure gas that the gas transportation system in Appalachia cannot at this time handle.

Most companies have so far drilled mostly vertical wells to delineate the play, but the study expects horizontal wells to be the primary means for developing the formation.

Montney

The Montney shale lies in the east-central part of British Columbia. The study notes that continued drilling should increase production to 1 bcfd by yearend 2009 from the current 600 MMscfd in early 2008.

Operators typical include five to eight fracs/well, and the study expects estimated ultimate gas recovery to increase to 7 bcf/well from the current 5 bcf/well as technology innovation continues.

Horn River basin

The Horn River basin in Northeastern British Columbia extends into the Northwest Territories. The Devonian Muskwa shale is the main play although the basin also has other shales with large original gas in place such as the Fort Simpson, the study says.

Initial well production rates have ranged from 2 to 8.8 MMcfd with wells with more fracs stages producing better, the study notes. The study says estimated ultimate gas recovery ranges from 4 to 6 bcf/section.

Utica

The Utica and the overlying Lorraine shales are relatively new plays in Quebec with only a few wells testing the formations to date. The study estimates that recoverable gas could be as much as 40 tcf (150 bcf/section).

An initial vertical well tested at 1 MMcfd; rates should be higher for horizontal wells with multiple fracs, according to the study.

Emerging plays

Three emerging shale plays listed by the study are Pearsall shales in the Maverick basin of South Texas, the Niobrara shales of Western Colorado, and the Barnett shale in the Delaware basin of West Texas.

The study says the Pearsall is as deep as 3,500 m in places, has a 200-300 m thickness, and contains about 30-175 bcf/section of original gas in place. It notes reports that say initial horizontal wells flowed at 0.8-3.8 MMcfd.

The Niobrara shales outcrop in Kansas and Nebraska, but are at more than 2,500 m depths in western Colorado. The study notes that in the eastern shallower portion of the play, the shales are underpressured and wells have low initial rates, while in the deeper overpressure portion, wells may produced at 1 MMcfd and recover 100-150 bcf of gas/section.

The Barnett in the Delaware basin is twice a deep as the Barnett in the Fort Worth basin and therefore holds much more gas per section. One estimate is that the Delaware Barnett has 500 bcf/section compared with 150 bcf/section in the Fort Worth basin. The study notes that developing Delaware Barnett gas will be more complicated and costly.

Great Economic News From Shreveport, Louisiana (Courtesy of the Haynesville Shale Gas Play)

More good news is the Haynesville Shale Gas Play is having very strong positive economic effects in the Shreveport area of northwestern Louisiana. This is not pie-in-the-sky, wishful thinking for creating jobs and energy supplies, such as windmills and solar farms. This activity is not a government "make-work" project. This is the real deal.

Shale gas is an available resource being exploited using existing technology. We need this kind of good economic good news in America, badly. Someone should invite President Obama down to Shreveport and give him a tour.
Peter

July 1, 2009 Shreveport-Bossier among best for a fresh start, Web site says By Curtis Heyen cheyen@gannett.com (source) Shreveport-Bossier City has been ranked 15th among the top 20 places in the U.S. to begin a new career or a new life, according to the Web site BusinessWeek.com. The Web site cites Shreveport-Bossier City for having a low cost of living and seeing new jobs coming from the natural gas industry and the movie business. The listing reinforces what local leaders have believed for a long time, said Kurt Foreman, president of the Northwest Louisiana Economic Development Foundation. "We certainly feel like this is a great place to start over, build a business or grow a career. "I'm pleased that these national magazines are seeing what we have seen for a long time." The recession has not negatively impacted Shreveport-Bossier City as much as other parts of the nation, Bossier City Mayor Lo Walker said. "We do have job opportunities. ... We've had a net increase in population and jobs. "This news can only encourage people to be more receptive to coming to this region." The BusinessWeek.com article notes that a number of movies, among them "W.", include scenes filmed in Shreveport and the surrounding area. In fact, Oliver Stone shot most of his movie in Shreveport. Another example not noted by the Web site is "Year One," which was filmed near Sibley and on a Shreveport soundstage. That moving, starring Jack Black, opens in theaters today. But the local film industry has slowed significantly this year. The next major project is "Straw Dogs," a Sony Screen Gems picture slated to begin filming here this summer. On the other hand, interest in the Haynesville Shale in northwest Louisiana continues to fuel employment in the region. The natural gas formation, trumpeted as perhaps the largest in the nation, has pumped millions of dollars into some property owners' pockets -- including local governments -- since the discovery was announced in April 2008. A recently completed economic impact study estimates Haynesville Shale activity created about 32,742 jobs, about $2.4 billion in business sales statewide and nearly $3.9 billion in household earnings, including almost $3.2 billion in lease and royalty payments to private landowners, in 2008. Topping BusinessWeek.com's list is the Anchorage, Alaska, metropolitan area. Also among its top five are Provo-Orem, Utah; Kennewick-Richland-Pasco and Yakima, both in Washington; and Omaha, Neb.-Council Bluffs, Iowa. The Web site ranked metropolitan areas based on the percentage of companies planning to hire in the third quarter, according to a survey by Milwaukee staffing firm Manpower of 28,348 U.S. employers that was conducted April 6-29. Businessweek.com says it eliminated Barnstable, Mass. (Cape Cod), which would have topped the list, because the surge in expected hiring in the next quarter is likely due to seasonal hires. In cases where areas have equal percentages of companies planning to hire, the Web site says, the unemployment rate was used to break the tie. The best job prospects for each area also were pulled from the same survey. Home prices used for the BusinessWeek.com's list were provided by Zillow.com, 2008 population is based on U.S. Census Bureau data, and the March unemployment rate comes from the U.S. Bureau of Labor Statistics.

Canadian Companies Prefer Drilling In U.S.

Here is another oddity. The Canadian Government is in effect subsidizing companies to produce gas in Canada, while one Canadian comany, EnCana, plans to spend $290 million in the Haynesville Shale Gas Play in northwestern Louisiana while cutting its drilling activity elsewhere.

Someone should tell the Obama Administration there is a shale gas "boom" going on in the U.S. Developing this resource can create jobs, increase revenue to State, Local, and the Federal Governments. The pipelines are there, the drilling rigs are there, the technology exists, the trained workers are there, ready to go. Mr. Obama, what are you waiting for?

This natural gas can be used to power buses, trucks and cars. It will reduce America's dependence on foreign oil, and last but not least, it will pacify some environmentalists because it is a "clean" source of energy.
Peter

Alberta Extends Natural-Gas Incentives to Compete With Shale

By Gene Laverty (source)

June 25 (Bloomberg) -- The province of Alberta, the biggest foreign supplier of natural gas to the U.S., said it will extend by one year incentives to boost drilling for the fuel to make it more competitive with U.S. shale gas deposits.

The province will charge producers a flat rate of 5 percent during the first year of output from new wells, a government statement said. Drillers will also receive a royalty credit of C$200 ($172.64) for each meter (3.28 feet) of new well depth drilled.

The programs had been set to expire in March 2010, Energy Minister Mel Knight said in the statement. They will be extended to March 2011.

Companies including EnCana Corp., the nation’s biggest gas producer, are shutting wells amid a 70 percent decline in New York gas futures in the last year. Companies are using new methods to tap gas large gas deposits trapped in shale in Texas and Louisiana that are closer to U.S. consuming regions. Calgary-based EnCana plans spend $290 million on its Haynesville Shale properties this year while slashing drilling in other regions.

To contact the reporter on this story: Gene Laverty in Calgary at glaverty@bloomberg.net.

The U.K's BG Buys A Stake (From EXCO) In The Haynesville Shale Gas Play

This is good news for those of us in the service sector who depend on drilling activity. It is also good to have foriegn money coming into the U.S and creating jobs. The price this U.K. natural gas company is paying to enter the Haynesville Shale Gas Play may seem steep, but they are surely counting on the price of gas and leases to increase.

Also, and not insignificantly, they're paying for the science and technology that has been developed to extract this "unconventional" source of gas. By this I mean primarilly horizontal drilling and hydraulic fraturing. This would also, I hope, include the "steering" of these horizontal wells into the optimum stratigraphic layers of rock.
Peter


BG Buys Exco Stake for $1.06 Billion to Tap Shale Gas (Update3)

By Eduard Gismatullin

June 30 (Bloomberg) -- BG Group Plc, the U.K.’s third- largest natural-gas company, bought assets from Exco Resources Inc. for $1.06 billion to develop its first U.S. shale gas project. Exco shares rose 16 percent.

BG Group acquired a 50 percent stake in 120,000 net acres in East Texas and northern Louisiana, the company said today in a statement. The purchase includes part of the Haynesville Shale gas formation and adds 2.6 trillion standard cubic feet to BG’s resources, with current net output of 78 million standard cubic feet a day.

“We expect BG will use this shale gas to meet U.S. contract commitments, thereby releasing Atlantic basin LNG cargoes for higher-priced global” markets, said Oswald Clint, a London-based analyst at Sanford C. Bernstein & Co.

BG will compete with larger rivals including Royal Dutch Shell Plc, BP Plc and StatoilHydro ASA in the development of U.S. shale deposits. It has also expanded oil and gas resources in Australia and Brazil and forecasts production will rise between 6 percent and 8 percent a year and reach 1.6 million barrels of oil equivalent a day in 2020.

“This alliance brings material new resources and supply to our existing U.S. business at a competitive price and in a prime location at the heart of the world’s largest gas market,” Chief Executive Officer Frank Chapman said in the statement. “The transaction increases BG Group’s exposure to long-term unconventional gas resources and skills.”

Marketing LNG

Dallas-based Exco rose $1.80 to $12.92 in New York Stock Exchange composite trading. BG Group fell 19 pence, or 1.8 percent, to 1,018 pence in London.

Shale gas is natural gas stored in organic rich rocks such as dark-colored shale, interbedded with layers of shaley siltstone and sandstone, according to BG.

BG has been marketing liquefied natural gas in the U.S. and supplied 55 percent of all LNG cargos imported into the country in 2007, according to its Web site. The company also generates power in the U.S. to customers in New England.

A total of $655 million will be paid on completion, plus $400 million as a carry of 75 percent of Exco’s future costs to develop the Haynesville Shale gas, the Reading, U.K.-based company said. The partners agreed to co-operate on further development and BG expects its production in the area will rise to 250 million cubic feet a day in 2012.

‘Expensive’ Deal?

The British company will pay $19,000 per acre for the Haynesville Shale gas assets. It may also buy a 50 percent interest in gas-gathering and transportation assets from Exco for $249 million to supply the fuel to U.S.’s Midwest and Eastern regions.

“Recent deals in the shale gas play have been around $15,000 per acre,” said Bernstein’s Clint. “Hence this deal at $19,000 per acre could be viewed as expensive on that basis.”

The acquisition of the gas assets is conditional on the purchase of the transport infrastructure, BG said.

To contact the reporter responsible for this story: Eduard Gismatullin in London at egismatullin@bloomberg.net