Shale gas enhancing energy supply, security
Whether you call it revolution or evolution, one thing is clear: Shale natural gas is producing jobs and economic benefits across the nation.
This week, shale gas was the focus of a major conference in Houston involving industry representatives, government officials and academics who gathered to discuss the technologies and future of this increasingly important source of energy.
For most of the nation, the contributions of shale gas may seem like a revolution. Shale gas has created thousands of new jobs, meant millions of dollars in new government revenues and enhanced energy security for America.
Of course, those of us who work in and around the energy industry understand that shale gas has been more of an evolution than a revolution.
The technologies used to develop these natural gas supplies aren’t new. Our industry began directional drilling in the 1920s, leading to substantial use of horizontal drilling in recent decades. And we have used the process of hydraulic fracturing since the 1940s. In that time, the industry has safely drilled more than a million wells.
The transformative impact of shale gas is challenging us all to think in new ways.
Not long ago many worried about a natural gas supply shortage in the U.S. But as President Obama recently stated, a “century’s worth … [lies] in the shale beneath our feet.” A decade ago gas from shale accounted for less than 2 percent of U.S. natural gas production. Today it is nearly 30 percent and growing.
As our nation considers this potential, we are reminded of the importance of reliable, affordable energy to our economy – especially during challenging economic times. Affordable supplies of natural gas – driven by the increase in shale production – have helped reinvigorate the domestic petrochemical industry, which relies on gas as a feedstock to make plastics and the other building blocks of modern manufacturing. These supplies are strengthening America’s steel industry, which is building new mills and hiring workers to support shale gas drilling. And areas where production of shale oil or natural gas is occurring are experiencing economic growth, job creation, and increased tax revenue.
For instance, in North Dakota, unconventional oil and gas production in the Bakken Shale has provided enormous economic benefits, with close to $5 billion in direct economic activity in 2009. In Texas, a study of the Barnett Shale formation near Fort Worth estimates it is now responsible for $11 billion in annual economic output and more than 100,000 jobs for the North Texas region. And in Pennsylvania, state labor statistics show 214,000 Marcellus Shale-related jobs at the beginning of 2011. Penn State researchers meanwhile calculate that Marcellus drilling could add nearly $10 billion in value to the Pennsylvania economy this year.
We also must not forget that hydraulic fracturing helps our nation reach our shared goals for responsible environmental stewardship. Natural gas produces about 50 percent fewer greenhouse gas emissions than coal when used to produce electricity for consumers and businesses, and significantly reduces other emissions such as mercury, sulfur and nitrogen oxide. It also uses a small fraction of the water used in coal, nuclear and solar power generation processes to produce a barrel of oil equivalent energy.
To ensure economic and environmental benefits continue, the people of the natural gas industry understand that we must remain firm in our commitment to properly manage the risks involved in drilling operations. That means meeting the highest standards of well design and well integrity. It means training our personnel and contractors to ensure adherence to established operating procedures. It means safely and efficiently handling the water and additives used to fracture wells. And it means working with state regulators to ensure protection of water and air quality.
The United States’ shale gas resources are an extraordinary energy endowment for our country, and our industry knows how to produce these resources safely and responsibly. We must keep these facts in mind as the public and policymakers discuss energy policies – and what increased access and technology mean for the energy industry.
With a commitment to operations integrity, wise development of our shale gas can provide new supplies of affordable, reliable energy in a safe, secure and environmentally responsible manner. And the rise of this resource comes at a time when our country – and the world – clearly needs the economic and environmental benefits that natural gas stands ready to deliver.
Mark W. Albers is a senior vice president at Exxon Mobil Corporation.
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China’s largest offshore oil producer, China National Offshore Oil Corp (CNOOC), said unconventional oil and gas production in its United States partnerships totaled 3 million to 4 million barrels this year.
“We expect annual production to hit 8 million barrels as we put more capital into the wells,” said Zhu Weilin, executive vice-president of CNOOC Ltd.
China is estimated to hold more natural gas trapped in shale than the US, according to the US Energy Information Administration in April. Shale gas is among the largest onshore energy prospects in China.
CNOOC paid $570 million for a 33.3-percent stake in Chesapeake Energy Corp’s Niobrara shale project in Colorado and Wyoming in February this year. Last November, the company made a $1.8-billion purchase for a one-third stake in Chesapeake’s Eagle Ford project in south Texas.
He said his company is looking for opportunities with US companies in deepwater exploration as well as shale gas and oil.
“CNOOC has 19 offshore blocks in China that we are looking for foreign partners to co-develop,” said Zhu at the recent China-US Relations Conference.
“We see other small Chinese companies coming to the US for partnerships and supply agreements in unconventional oil and gas fields,” said Christine Ehlig-Economides, professor of the Petroleum Engineering Department at Texas A&M University. “This is one area they want to learn from.”
Industry analysts said China is paying a high premium for the partnerships while others have said Chinese is learning new exploration techniques through the projects.
The prices China’s State-owned oil companies have paid for assets are mixed; in some cases, they may have paid above market value but recent economic conditions, good financial performances, and growing experience with international deals have benefited the companies, according to a report by the International Energy Agency.
Two-thirds of the USD 70 billion invested in 144 projects overseas by China’s three oil giants, Sinopec Group, China National Petroleum Corp and CNOOC, have not turned a profit thus far, according to a recent report by the China University of Petroleum and the China Petroleum and Chemical Industry Association.
“Natural resources are one of the few sectors where the US government has stringent scrutiny because they are the strategic industries,” said Huang Yasheng, professor at the Sloan School of Management at the Massachusetts Institute of Technology.
In 2005, CNOOC dropped its USD 18.5-billion bid for Unocal Corp because of opposition from US lawmakers.
It would have been the largest overseas acquisition by a Chinese company.
“Chinese companies should position themselves globally, rather than nationally,” said Xiang Bing, founding dean of the Cheung Kong Graduate School of Business, one of China’s leading business schools.
- Norwegian giant in it for the long haul with Texas shale venture (mb50.wordpress.com)
The research was sponsored by a grant from the center, which is a legislative agency of the Pennsylvania General Assembly.
The Center for Rural Pennsylvania is a bipartisan, bicameral legislative agency that serves as a resource for rural policy within the Pennsylvania General Assembly, its website indicates.
According to the report, this research studied the water quality in private water wells in rural Pennsylvania before and after the drilling of nearby Marcellus Shale gas wells. It also documented “both the enforcement of existing regulations and the use of voluntary measures by homeowners to protect water supplies.”
In its introduction, the authors said they evaluated water sampled from 233 water wells near Marcellus gas wells in rural regions of Pennsylvania in 2010 and 2011.
“Among these were treatment sites (water wells sampled before and after gas well drilling nearby) and control sites (water wells sampled though no well drilling occurred nearby),” the study indicated. “Phase 1 of the research focused on 48 private water wells located within about 2,500 feet of a nearby Marcellus well pad, and Phase 2 focused on an additional 185 private water wells located within about 5,000 feet of a Marcellus well pad.”
During that phase, the researchers collected both pre- and post-drilling water well samples and analyzed them for water quality at various analytical labs. During Phase 2, the researchers or homeowners collected only post-drilling water well samples, which were then analyzed.
The post-drilling analyses were compared with existing records of pre-drilling water quality, which had been previously analyzed at state-accredited labs, from these wells.
“According to the study results, approximately 40 percent of the water wells failed at least one Safe Drinking Water Act water quality standard, most frequently for coliform bacteria, turbidity and manganese, before gas well drilling occurred,” the report indicated. “This existing pollution rate and the general characteristics of the water wells, such as depth and construction, in this study were similar to past studies of private water wells in Pennsylvania.”
The study’s pre-drilling results for dissolved methane showed its occurrence in about 20 percent of water wells—although levels were generally far below any advisory levels.
“Despite an abundance of water testing, many private water well owners had difficulty identifying pre-existing water quality problems in their water supply,” the report indicted. “The lack of awareness of pre-drilling water quality problems suggests that water well owners would benefit from unbiased and consistent educational programs that explain and answer questions related to complex water test reports.”
In this study, statistical analyses of post-drilling versus pre-drilling water “did not suggest major influences from gas well drilling or hydrofracturing (fracking) on nearby water wells, when considering changes in potential pollutants that are most prominent in drilling waste fluids.”
When comparing dissolved methane concentrations in the 48 water wells that were sampled both before and after drilling, the research found no statistically significant increases in methane levels after drilling—and no significant correlation to distance from drilling.
“However, the researchers suggest that more intensive research on the occurrence and sources of methane in water wells is needed,” the report indicated.
The report then cited the Pennsylvania Oil and Gas Act of 1984, which indicates that gas well operators are “presumed responsible” for pollution of water supplies within 1,000 feet of their gas well for six months after drilling is completed if no pre-drilling water samples were collected from the private water supply.
“This has resulted in extensive industry-sponsored pre-drilling testing of most water supplies within 1,000 feet of Marcellus drilling operations,” the report states. “However, the research found a rapid drop-off in testing beyond this distance, which is driven by both the lack of presumed responsibility of the industry and also the cost of testing for homeowners.”
The authors of the study said their research suggests that a standardized list of minimum required testing parameters should be required across all pre-drilling surveys to eliminate confusion among between water supply owners and water professionals.
The study indicates that this standardized list should include bromide. The research found that bromide levels in some water wells increased after drilling and/or fracking. These increases may suggest more subtle impacts to groundwater and the need for more research.
“Bromide increases appeared to be mostly related to the drilling process,” the study indicated.
Additionally, “a small number of water wells also appeared to be affected by disturbances due to drilling as evidenced by sediment and/or metals increases that were noticeable to the water supply owner and confirmed by water testing results.”
Increased bromide and sediment concentrations in water wells were observed within 3,000 feet of Marcellus gas well sites in this study, suggesting “that a 3,000 foot distance between the location of gas wells and nearby private water wells is a more reasonable distance for both presumed responsibility and certified mail notification related to Marcellus gas well drilling than the 1,000 feet that is currently required.”
On the regulatory side, “the research found that regulations requiring certified mail notification of water supply owners, chain-of-custody water sampling protocols, and the Pennsylvania Department of Environmental Protection’s investigation of water supply complaints were generally followed, with a few exceptions.”
The study also concluded that “since voluntary stipulations were not frequently implemented by private water well owners” that more educational and financial resources should be made available to facilitate testing.
The authors were clear: “This research was limited to the study of relatively short-term changes that might occur in water wells near Marcellus gas well sites. Additional monitoring at these sites or other longer-term studies will be needed to provide a more thorough examination of potential water quality problems related to Marcellus gas well drilling.”
- Environmental officials study instances of methane in wells near Marcellus Shale drilling operation (pennlive.com)
- Flowback from “fracking” Marcellus gas wells in PA has killed vegetation similar to West Virginia Study (pennlive.com)
- ‘Citizens Shale Commission’ weighs in on Marcellus policy (pennlive.com)
“We’ve got a very sizable resource in place,” Dennis Carlton, executive director of Cuadrilla Resources, said in a phone interview from Blackpool, England. “Without drilling individual units within the thick shale we don’t know what the recovery factor will be.”
Two exploration wells near the seaside resort of Blackpool found shale formations almost 10 times as thick as typical U.S. deposits, Carlton said. Hydraulic fracturing, a process that uses water, sand and chemicals to smash apart rocks and release trapped fuel, reversed declines in U.S. natural-gas output and made it the world’s largest producer.
As many as seven exploration wells may need to be drilled, fractured and tested before more information can be given about recoverable reserves, he said. Investors in Cuadrilla include Riverstone Holdings LLC, led by former BP Plc Chief Executive Officer John Browne, and AJ Lucas Group Ltd. (AJL)
“In the Marcellus, if you have a 300- to 400-foot interval, that’s on the high side,” he said, referring to one of the largest U.S. shale-gas basins. “We’ve got 3,000 foot of shale.”
The U.K.’s largest shale resource found to date is equivalent to 5.6 trillion cubic meters, or about three times Norway’s existing, proved reserves. Norway is the second-largest gas exporter to Europe and the biggest foreign supplier to Britain.
Cuadrilla is likely to be able to recover only a fraction of the gas trapped in the rocks. The U.K.’s technically recoverable shale resources are 20 trillion cubic feet, the U.S. department of Energy said in an April report.
The company has 1,200 square kilometers (300,000 acres) under license in northwest England, covering 80 to 90 percent of the shale in the area, he said.
“We’ve got the best of the best, at least in the Bowland basin,” he said.
North Sea gas production is declining and the U.K. is increasingly reliant on imports to meet Europe’s highest demand for natural gas.
Cuadrilla voluntarily halted fracking at its operations in June after “small tremors” were reported in the area, according to its website. The company will submit a report to the Department of Energy and Climate Change in October, Carlton said.
Carlton estimated a “mid-case” scenario of drilling 400 production wells from 40 well pads in the future. To date they have drilled two exploration wells and have historical data from three 10- to 15-year-old wells drilled by British Gas.
- And now the UK reports a huge shale gas find – but WWF wants to ban it (ktwop.wordpress.com)
- Gas field to turn Blackpool into Dallas-on-sea (guardian.co.uk)
- Deep under Lancashire, a huge gas find that could lead to 800 ‘fracking’ wells (independent.co.uk)
- Leading article: Fracking – not a risk that it is worth Britain taking (independent.co.uk)
- Camp Frack mobilises against UK’s first shale gas well (guardian.co.uk)
- The UK’s lack of fracking regulation is insane | George Monbiot (guardian.co.uk)
Posted 05/09/2011 06:55 PM ET IBD Editorials
Regulation: The Energy Department wants to find ways to make hydraulic fracturing, a fast-growing method of extracting natural gas, safer and cleaner. Say, isn’t that how the administration justified its offshore drilling ban?
We’re from the government, and we’re here to help you drill safely. That was the canard thrown out by President Obama and Interior Secretary Ken Salazar when they announced the ban on offshore drilling following the Deepwater Horizon oil rig explosion and spill.
Since then the drilling industry in the Gulf of Mexico has collapsed and output has dropped. Although the ban was ostensibly lifted, it has been replaced by a new permit system that is so slow that rigs have left the Gulf for foreign shores. At least one drilling company has filed for bankruptcy.
The safety mantra was raised once again last Thursday when Energy Secretary Steven Chu announced the appointment of a seven-member panel to study hydraulic fracturing, commonly referred to as “fracking,” and come up with new safety standards that address concerns raised by environmentalists.
The process involves the injection under high pressure of fluids, mainly water with a few chemicals added, to fracture the porous shale rock found in huge formations in the northeast and Rocky Mountain West and get at the oil and gas trapped inside the porous rock.
Environmentalists contend these chemical additives contaminate ground water supplies.
“America’s vast natural gas resources can generate many new jobs and provide significant environmental benefits,” Chu said. “But we need to ensure we harness these resources safely.” It was a similar “but” that led the Obama administration to impose a seven-year ban on offshore drilling in the Outer Continental Shelf in the eastern Gulf of Mexico, off both coasts and in the energy-rich Chukchi and Beaufort seas off Alaska.
The new panel includes such friends of domestic energy as Kathleen McGinty, former secretary of the Pennsylvania Department of Environmental Protection and an aide to Al Gore when he was a senator, and Fred Krupp, president of the Environmental Defense Fund.
It was a similar panel created by Interior Secretary Ken Salazar after the Deepwater Horizon blowout that led to the current moratoria on off shore drilling.
But so committed is this administration in its opposition to fossil fuel extraction, except in Brazil, that it had to doctor that panel’s evaluations to make it seem they endorsed the drilling ban when they did not.
The administration was even found in contempt of court for trying to reinstate its moratorium after a judge issued an injunction on the grounds that the moratorium was too broad in its scope and totally unjustified based on the available evidence.
U.S. District Judge Martin Feldman argued Salazar’s original Gulf drilling moratorium was based on flawed reasoning.
“If some drilling equipment parts are flawed, is it rational to say all are?” Feldman asked. “That sort of thinking seems heavy-handed, and rather overbearing.”
We think so too.
We believe the safety issue is a cover for the Obama administration’s ideologically driven animus toward fossil fuels and its deliberate campaign to raise energy prices — and thereby to make its favored “green” alternatives look more competitive and attractive.
By TED GRIGGS Advocate business writer Published: May 6, 2011
A third independent, Amelia Resources LLC of The Woodlands, Texas, has signed a deal with an unnamed partner to help develop the more than 110,000 acres Amelia has under lease.
Devon Energy officials said Wednesday the Oklahoma City-based company has leased around 250,000 acres in the shale. Devon plans to drill two wells in the formation this year, the first of them this quarter.
On Thursday, Dallas-based Denbury Resources announced a joint venture with an unnamed partner that will complete one well and drill another at no cost to Denbury. In late 2009, Denbury acquired Encore Acquisition Co., which had drilled some wells in the shale.
In a news release, Denbury Chief Executive Officer Phil Rykhoek said the company will retain a small interest in future activities in the shale.
“We continue on our oil-focused program and expect many good things in the near future,” he said.
LSU researchers have estimated the Tuscaloosa Marine Shale holds 7 billion barrels of oil.
During Wednesday’s conference call with stock analysts and investors, Devon Executive Vice President of Exploration and Production David Hager said the formation lies 11,000 to 14,000 feet underground and is 200 feet to 400 feet thick.
Hager said Devon believes it can use fracturing technology — pumping in water, sand and chemicals to crack the shale — to increase production in the formation.
The state plans to hold a hearing, possibly by next month, on whether to approve Devon’s request to use hydraulic fracturing for a well near Ethel in East Feliciana Parish. “Fracking” has drawn criticism from environmentalists who say the process contaminates the water supply and places a heavy burden on the resource. The oil and gas industry says those claims are inaccurate.
Hager said vertical wells drilled in the formation had initial production rates of 300 barrels per day.
The three or four horizontal wells drilled in the shale three years ago, which were shorter than Devon plans to drill, tested at rates of up to 500 barrels per day, Hager said.
Those are all reasons for encouragement, Hager said. But Devon needs to get more information on the oil play, including whether the formation can be fractured, and there are risks associated with Devon’s investment.
Still, the company has spent less than $50 million on its leases, and if Devon is successful the company “can create an awful lot of value,” he said.
Kirk Barrel, president of Amelia Resources, said drilling a longer horizontal segment, or lateral, exposes the wellbore to as much rock as possible, and that means the well can produce more oil.
Barrel, author of a blog on the Tuscaloosa Marine Shale, said one of Encore’s wells was drilled horizontally out to 4,100 feet; a typical horizontal section is 4,000 to 5,000 feet long.
However, in the two wells it fractured, Encore only did three stages, Barrel said. Devon’s plans show the company plans to do 13- to 15-stage fracks, which in theory should substantially increase production.
In the south Texas Eagle Ford Shale, “a distant cousin” geologically of the Tuscaloosa Marine Shale, some drilling companies have done 20-stage fracks, Barrel said. In North Dakota’s Baaken Shale, some wells have had 40-stage fracks.
Matt Ross, a spokesman for the Louisiana Oil and Gas Association, said in multistage fracturing, the initial fracturing is done around the point where a well levels out horizontally.
The subsequent fracks are spaced throughout the rest of the horizontal section, Ross said. The spacing depends on the drilling company’s preference.
Meanwhile, Barrel said his firm has placed a significant amount of acreage with an unnamed partner.
Barrel said he could not disclose how much acreage Amelia now has under lease; in February that was more than 110,000 acres.
Amelia is still in the process of adding to its acreage, Barrel said, and he did not know when the partnership might begin drilling.
- Emerging Shale Oil Plays (mb50.wordpress.com)
- Louisiana official reports activity on third possible shale play (mb50.wordpress.com)
- New Frontiers: the attention turns to some up-and-coming plays (mb50.wordpress.com)
- Halliburton: Moving Quickly on the Global Shale Boom (mb50.wordpress.com)
- Natural gas shale play development now going global (mb50.wordpress.com)
- US Shales: Whether its a Revolution of Evolution, Shale Gas Delivers (mb50.wordpress.com)
The impacts that the international liquefied natural gas market will see from shale gas production growth in North America and across the globe will vary widely according to local market conditions, members of a panel at the Offshore Technology Conference in Houston said Wednesday.
In the US, where the “shale gas revolution” first started and already is well under way, domestic gas supplies have severely cut into the demand for imported LNG, Emma Cochrane, manager of gas power and marketing for ExxonMobil, said.
With ample gas supplies to meet US gas demands most of the time, LNG imports will largely serve to meet seasonal balancing needs, she said.
“Imports will mostly come in the summer, where there is nowhere else for the gas to go,” Cochrane said. As a result of the inflow of gas supplies from shale plays across the nation, “the US becomes almost self-sufficient” in meeting its gas demand in the future.
In other regions of the world, however, the growth of shale gas production will be less of a factor in supply-and-demand dynamics than more localized factors, Rafael McDonald, associate director of global gas research, IHS CERA, said.
“We see an acceleration of the tightening of the global gas market,” he said. However, the resurgence of gas demand in the wake of the global recession will result in “a multi-speed recovery,” with some regions outpacing others.
“In terms of GDP and gas demand, some places never dipped, like Brazil and China. Some dipped but came roaring back, like South Korea, and some continue to languish,” he said.
Australia, which has ambitious plans to dramatically increase its liquefaction and LNG export capacity, could someday surpass Qatar as the world’s largest LNG exporter, McDonald said. “There are some questions still. There 28 million tons of capacity already, with over an additional 100 million tons of capacity planned,” he said.
He added that “all of that can’t come on line,” as Australia does not have the resources to increase its LNG capacity to the extent that LNG developers envision.
Davis Thames, president of Cheniere Marketing, described how the changing dynamics of the international gas market has led his company to announce plans to convert its Sabine Pass LNG receiving terminal in Cameron Parish, Louisiana into bi-directional terminal capable of exporting as well as importing LNG.
“In the US, we have a natural gas market that doesn’t exist anywhere else in the world,” he said. Technological innovations in gas production techniques have resulted in “a tremendous amount of gas,” coming onto US markets, driving down the domestic costs of gas and destroying the economic rationale behind building LNG import-only terminals.
As a result, Cheniere is reinventing its business model from the traditional LNG import terminal, Thames said.
“We’re providing a midstream service,” he said. Cheniere’s proposed bi-directional LNG facility “looks more like a pipeline,” than a traditional LNG import terminal, he said.
Houston-based Cheniere, which owns the 4 Bcf/d Sabine Pass LNG import terminal, in August 2010 applied to US authorities for permission to export gas produced in the Lower-48 states.
–Jim Magill, email@example.com
By Selam Gebrekidan Tue May 3, 2011 12:13am EDT
(Reuters) – A century after a gusher at the Spindletop field in Beaumont, Texas, ushered in the first U.S. oil boom, a quieter oil craze is underway 300 miles west in a chain of counties more famous for cattle than crude.
Over the past two years, some 30 companies have moved in to a shale prospect in South Texas called the Eagle Ford that could add 420,000 barrels per day (bpd) to U.S. crude oil production, nearly matching the output of OPEC member Ecuador.
The first phase of this latest boom has accelerated over the past year. Companies have hastened development of the estimated 3 billion barrels of shale oil across Eagle Ford by bringing in the horizontal drilling and hydraulic fracturing techniques that opened up North Dakota.
Where wildcatters and entrepreneurs pounced on the Spindletop boom at the start of the 20th century, engineers and business analysts are leading the charge to develop reserves under 20,000 square miles of cattle land in Eagle Ford.
Shale natural gas initially drew companies to the area, but as gas prices languished and crude surged, interest in the region’s crude potential grew.
To relieve a bottleneck producers say has begun to choke growth, pipeline companies in recent weeks committed more than $1 billion to add 940,000 barrels per day (bpd) of pipeline capacity by the end of 2012, according to Reuters estimates.
Texas, once the center of the oil world, fell on hard times as production declined and big energy companies looked overseas to expand and replenish reserves. After decades of decline, U.S. oil output is slowly rising again, largely due to shale reserves like the Bakken field in North Dakota and now Texas.
In April alone, top pipeline companies such as Enterprise Products, Nustar Energy and Koch pipelines announced five projects to build new crude and condensate lines or expand older ones, bringing the rising supply of high quality light, sweet oil to giant Gulf Coast refiners.
For now, truck drivers are working overtime to ferry oil from the region, which stretches across 22 counties in South Texas. Transport companies are retrofitting rigs, but often can’t find lodging for drivers as hotels and motels are booked a year in advance.
“The demand is really straining the trucking industry,” said John Esparza, president of the Texas Motor Transportation Association. “A lot of the capacity that existed a few years ago was cut during the recession. Now there is a spike in demand for a very specific type of truck.”
Explosive production growth will make the transportation infrastructure problem more glaring. Eagle Ford output has risen from nil two years ago to 71,000 barrels of oil per day, and will leap fivefold by 2015, according to energy consultancy Bentek.
“The growth …. clearly outpaces the capabilities of existing pipeline infrastructure,” says Joan Dunlap, spokesperson for Petrohawk Energy, one of the top four producers in Eagle Ford.
ConocoPhillips , which aims to triple its current output of 20,000 barrels of oil equivalent per day in the next few years, expects pipeline problems to be solved by 2013, the company said last week in its first-quarter earnings report.
FROM TWO DOZEN TO 2,000
The pace of development has picked up quickly since the first successful horizontal well was drilled in Eagle Ford in late 2008, when the Texas Railroad Commission had only 26 permits on record for the area.
The number shot up to more than a thousand in 2010, and the commission issued 562 permits in the first quarter of 2011 alone.
“The Eagle Ford is going from a non-event to being extremely active. We’re expecting a four to five times increase in permits and production in four years,” said Commissioner David Porter of the Railroad Commission of Texas, which regulates exploration companies operating in the state.