In the following video, see the Shell’s Olympus TLP hull arrive in Texas following the long journey from South Korea. The approximately 32,500 metric ton main body of the Olympus TLP, arrived in Texas two weeks ago.
The installation of the topsides will now take place before the TLP departs for its final location on the Mars Field in the Gulf of Mexico.
The Mars Field, owned by Shell (71.5%) and BP (28.5%), and operated by Shell, continues to contribute to the Gulf of Mexico’s position as a critical component of the US energy supply. Discovered in 1989 and brought onto production in 1996, the Mars Field is considered one of the largest resource basins in the Gulf of Mexico. The site for the Olympus TLP, known as the Mars B development, is located about 130-miles south of New Orleans in the Mississippi Canyon and lies in approximately 3000 feet of water.
The Olympus TLP, Shell’s sixth and largest tension leg platform, will also provide process infrastructure for two of Shell’s deep water discoveries, West Boreas and South Deimos.
The U.S. Department of Energy has granted Pangea LNG Holdings, LLC, long-term, multi-contract authorization to export liquefied natural gas (LNG) to free trade agreement (FTA) nations from its South Texas LNG Project currently in development on Corpus Christi Bay.
Pangea LNG will be authorized to export up to 8 million metric tons per annum (mtpa) of LNG produced from domestic gas fields for a 25-year term commencing on the date of its first export. That amount is equal to 1.09 Bcf/day of natural gas.
Pangea LNG has also filed an application with DOE requesting authorization to export LNG to any country with which the U.S. does not have a free trade agreement in effect. That application, which was filed in December, is pending.
“Approval by the US DOE is a positive step forward for this project, which represents a significant investment in the development of the LNG market in the U.S.,” said John Godbold, Pangea LNG project director. “Exporting LNG will help stabilize U.S. natural gas prices, grow and sustain drilling and production jobs, and stimulate additional investment in developing the country’s gas reserves.”
DOE approval of FTA authorization is part of the regulatory process necessary to develop Pangea LNG’s new LNG export terminal on a 550-acre site. The site is located on the 45-foot deep La Quinta Ship Channel which is part of the Port of Corpus Christi, the sixth busiest U.S. seaport in terms of tonnage.
The South Texas LNG Project is subject to federal, state and local regulatory approvals with the Federal Energy Regulatory Commission (FERC) acting as the lead federal agency. Pangea will begin the FERC pre-filing process by the second quarter of 2013 and expects the project to be in operation by at least 2018.
FTA countries covered by the DOE authorization include Republic of Korea, Australia, Bahrain, Canada, Chile, Colombia, Dominican Republic, El Salvador, Guatemala, Honduras, Jordan, Mexico, Morocco, Nicaragua, Oman, Panama, Peru and Singapore.
Pangea LNG B.V. is a holding company with two major LNG export projects under development – the South Texas LNG Export Project on the Texas Gulf Coast and the Tamar Project in the Eastern Mediterranean. Pangea LNG is a developer of liquefaction projects which are designed to accelerate and support the monetization of gas reserves.
by Karen Boman Rigzone Staff
The liquefied natural gas (LNG) division of Calgary-based Ferus LP successfully completed in October what the company believes to be the first-ever hydraulic fracturing operation utilizing liquefied natural gas (LNG) as engine fuel in North America.
Ferus’ LNG Division was engaged by a major oil and gas service company in the United States to conduct the pilot project, which involved six dual-fuel 2,250 horsepower pressure pumper units, powered by LNG, to stimulate well performance in the south Texas Eagle Ford shale.
The dual fuel systems allow for natural gas and diesel to be consumed simultaneously with no decrease in performance, Jed Tallman, manager of market development for Ferus LNG, told Rigzone. Approximately 10,000 gallons of LNG was used in the pilot project, which took place in the southwestern portion of the Eagle Ford play.
While the company cannot discuss the plans of the operator involved in the pilot project, Ferus LNG has been contacted by numerous operators and service companies regarding LNG as a low-cost, environmentally superior alternative fuel, Tallman said.
The increase in interest by operators and service companies in using LNG for hydraulic fracturing has been dramatic.
“Because of the large amounts of diesel consumed in fracturing fleets, the use of LNG as an alternative fuel will result in cost savings for the operator or service company, not to mention a significant reduction in greenhouse gas emissions,” Tallman commented.
“LNG offers significant environmental and cost-saving advantages and is quickly becoming the alternative fuel of choice for heavy-duty high horsepower on-road and off-road applications in North America,” said Ferus President and CEO Dick Brown in a Nov. 28 statement. “We were very pleased to play such a critical role in this ground-breaking project, and we intend to be at the forefront of this growing industry as more and more diesel consumers make the switch to North America’s abundant supply of natural gas.”
It is difficult to estimate the specific size of the market for LNG in hydraulic fracturing and in other areas such as railroad transportation and trucking moving forward, Tallman commented.
“But given the economic benefits, improved emissions profile, and increased gas production, we feel that LNG will make up a considerably larger percentage of our domestic energy consumption in the future.”
While the use of LNG for hydraulic fracturing is not being specifically done to alleviate criticism of hydraulic fracturing, the improved emissions profile of natural gas certainly is a benefit, Tallman said.
To complete this project, which marks a significant milestone in the adoption of natural gas as an alternative engine fuel, Ferus managed the entire supply chain on behalf of its client including LNG supply, transportation, and on-site storage and vaporization using specialized equipment and highly-trained personnel.
In addition to being a cleaner-burning and less expensive fuel alternative, LNG is non-toxic, non-combustible, non-flammable as a liquid, and dissipates into the atmosphere in the event of a leak or a spill, making it safer than diesel and gasoline, the company said in a statement.
The use of LNG requires specialized fuel handling equipment and additional training for individuals involved in the LNG supply chain.
“As a leading provider of cryogenic liquids for the energy sector, Ferus is uniquely qualified for the undertaking,” Tallman said.
The increased use of natural gas to fuel not only hydraulic fracturing but transportation has grown thanks to the abundance of shale gas in the United States.
The use of natural gas over diesel is becoming more widespread, likely due to the cost benefits associated with fuel switching, according to a Nov. 28 analyst report from GHS Research. GHS referenced Baker Hughes‘ Nov. 26 announcement that it would convert a fleet of its Rhino hydraulic fracturing units to bifuel pumps as a way to improve operational efficiency, lower costs and reduce health, safety and environment impacts. Bifuel is a mix of gas and diesel.
The new pumps use a mixture of gas and diesel, reducing diesel use by up to 65 percent with no loss of hydraulic horsepower. The converted fleet, which meets all U.S. Environmental Protection Agency emissions standards, can also reduce a number of emissions including nitrogen oxides, carbon dioxide and particulate matter.
Baker Hughes first converted a small fleet of its units in Canada; the success Baker Hughes saw with this endeavor prompted to company to convert an entire fleet in the United States. The company is converting several more fleets of Rhino trucks to Rhino Bifuel equipment. Baker Hughes also has a test program in Oklahoma, where a number of light-duty vehicles have been converted to natural gas.
Westport Innovations, which manufactures natural gas-powered truck engines, recently reported it is building a railroad locomotive engine that can run on LNG. During 2012, the company saw “broad consensus” for the first time that natural gas will take material market share in every global transportation market within the next five years, said David Demers, chief executive officer for Westport, during the company’s third quarter 2012 earnings update Nov. 8.
Demers noted that consensus suggests that the company will see 7 percent to 15 percent of the North American trucking industry run on natural gas in 2017.
Westport Innovations will also introduce new natural gas-powered versions of the Ford F-450 and F-550 Super Duty trucks in mid-2013, the company said in a Dec. 3 statement.
“Although current demand for natural gas used in vehicles is minor relative to the demand associated with power generation, industry and residential heating, it is catching on and may soon reach a tipping a point where growth rapidly accelerates, with or without government intervention,” GHS reported.
- Baker Hughes using natural gas in fracturing jobs (fuelfix.com)
- Baker Hughes Converts Fleet of Hydraulic Fracturing Units to Bifuel (maritime-executive.com)
- USA: Waller Marine to Develop LNG Terminal (mb50.wordpress.com)
- Natural gas exports are in near future, Exxon says (star-telegram.com)
Pangea LNG Holdings announced that it has begun the process of seeking approvals necessary to build a liquefied natural gas export facility on Corpus Christi Bay in South Texas.
Pangea has filed an application with the U.S. Department of Energy seeking authority to export up to eight million metric tons per year of liquefied natural gas to all current and future countries with which the U.S. has a Free Trade Agreement and intends to quickly file a similar application for LNG exports to any country with which the U.S. does not have a Free Trade Agreement in effect.
The project is located in the city of Ingleside on the La Quinta Ship Channel which is part of the Port of Corpus Christi. The project will be known as South Texas LNG Export.
South Texas LNG Export will be located on a portion of a 550-acre site which includes half a mile of frontage on the federally-maintained deepwater ship channel. Pangea has had the site under option since June. A separate pipeline project would connect the LNG plant to the extensive interstate and intrastate natural gas transmission pipeline network in South Texas.
Pangea LNG is an energy project and investment company involved in the development of LNG liquefaction and storage projects around the globe including an offshore floating LNG liquefaction project in the Eastern Mediterranean Sea.
John Godbold, project director for Pangea LNG, said an intensive project feasibility and preliminary design process is now underway on the South Texas project. The assessment is being conducted by CB&I, a leading international engineering, procurement and construction company.
The South Texas LNG Export project will require federal, state and local regulatory approval. The U.S. Federal Energy Regulatory Commission (FERC) is the lead agency in the permitting process. If this process moves forward on schedule the South Texas LNG terminal could be in operation by 2018.
Kathleen Eisbrenner, Pangea LNG’s chief executive officer, said, “We expect there to be several successful LNG export projects on the Texas Coast in the coming years because of the large new natural gas reserves in North America. Exporting LNG will help stabilize U.S. natural gas prices, sustain drilling and production jobs in South Texas, and stimulate investment in developing additional gas reserves.”
The South Texas project is the second LNG liquefaction project being developed by Pangea LNG companies. Levant LNG Marketing, a Pangea subsidiary, completed an extensive pre-FEED (preliminary front end engineering design), is finalizing commercial agreements and will start FEED engineering shortly on the Tamar Project which will export LNG from the Tamar and Dalit fields in the Eastern Mediterranean, 60 miles offshore from Israel.
That facility will be a permanently moored offshore floating natural gas liquefaction vessel with onboard LNG storage. The self-contained operation will be the first floating LNG export project in the Mediterranean basin. A final investment decision on the Tamar Project is expected by the second half of 2013.
September 26, 2012 – 3:44 pm
The agency said local authorities closed Bridge II linking the city to Piedras Negras, Mexico, to traffic in the morning citing safety concerns, which local news media said were prompted by the discovery of a “suspicious device.”
Eagle Pass is not one of the principal hubs for trade or visitors over the 2,000-mile (3,200-km) U.S. Mexico border.
It’s not widely known outside the Rio Grande Valley, but a “suspicious device” was discovered in Starr County, Texas back in August ( above photo ). It was an improvised explosive device. It was discovered on a ranch through which illegal aliens often slip into the United States.
If illegal aliens and coyotes can slip through there, so can the type of people who tend to play around with IEDs.
There’s no word yet on the nature of today’s suspicious device in Eagle Pass.
- Texas-Mexico border bridge shut over “safety concerns” (news.terra.com)
- Zetas gang threatens Mexico’s shale gas near border (appliedagrotech.net)
Posted on September 3, 2012 at 12:38 am by FuelFix.com
MEXICO CITY — Mexico’s national oil monopoly has been issuing critical alerts seemingly every week, warning of natural gas shortages lasting hours or even days and crimping supplies to homes, power plants and factories.
And yet, the country has some of the world’s largest natural gas reserves and easy access to a cheap and plentiful U.S. supply.
“There hasn’t been enough energy planning in this country,” said Raul Monteforte, a former senior official with Mexico’s Energy Regulatory Commission who’s now development director for Fermaca, a private Mexican transportation pipeline company. “Huge errors of omission have brought us a gas crisis.”
The gas squeeze will only worsen as many of Mexico’s new and existing electricity plants abandon coal and other fuels in favor of natural gas, gobbling up much of the available supply.
Petroleos Mexicanos, or Pemex, as the monopoly is called, will prove unable to get much more of the gas produced in its own fields to market.
Amid renewed political pressure to further open Mexico’s energy industries to private interests, energy planners have launched a frenzied expansion of the country’s woeful pipeline system. As much as 3 billion additional cubic feet per day of U.S. natural gas, most of it from Texas, will feed the new grid.
Central Mexican cities have been the worst affected by the critical shortage, but even companies in Monterrey, the industrial powerhouse that abuts the sprawling Burgos Basin gas fields, have been slammed.
“Such obstacles can’t be permitted, even less so ones provoked by a state monopoly,” Caintra, a leading Monterrey business association, declared in a full-page newspaper ad. “We demand an immediate solution.”
Texas, Arizona lines
Using an offshore Pemex subsidiary supposedly free of Mexican congressional oversight and constitutional restrictions, planners are rushing to build two new U.S. pipelines – to the Arizona border south of Tucson and from near Corpus Christi to the Rio Grande – to push that U.S. gas deep into the Mexican heartland.
Officials say the new pipelines will be completed by the late summer 2014.
But Monteforte and other critics contend that plans for the lion’s share of the expansion – shipping South Texas gas into the Mexican heartland – will assure Pemex’s grip on gas consumers for decades to come.
“If it flies I think Mexico’s gas market will remain in the hands of Pemex,” said Monteforte in criticizing the Texas pipeline proposal.
His company is building and will own a 225-mile pipeline from the border at El Paso to near Chihuahua City, he said.
“This will kill the opening of the gas market we’ve fought for since the 1990s,” he said.
The new U.S. pipelines, being contracted by Pemex’s MGI gas trading firm, will connect to a privately owned system being built across northwestern Mexico and to the much larger Los Ramones duct that will run from near the border at McAllen deep into central Mexico.
After sharp increases in the late 1980s and early ’90s, Mexico now imports some 15 percent of its natural gas supply from the United States, said Michelle Foss, program manager of the University of Texas’ Bureau of Economic Geology in Houston. By 2010, Mexico had increased its U.S. gas imports by 200 times what it did in the early 1980s.
Now, Mexico’s imports seem poised to spike again, perhaps bolstering prices for dry natural gas.
“Mexico will take all they can get and, as in the 1990s, could help to rebalance our market,” Foss said.
Project proposals for the South Texas pipeline – called the Agua Dulce to Frontera – were expected Monday. Pemex says the winning bid will be announced Sept. 18.
“For us it’s urgent to bring that gas,” said Guillermo Ortiz, a Mexico City executive who heads the energy committee at Canacintra, a leading Mexican industrial chamber. “They took a long time to contract for the pipelines. These types of situations are really hurting the consumers.”
- Mexico pipeline expansion may bring more money to Texas (fuelfix.com)
- Natural gas from Mexico beckons Texas companies (mysanantonio.com)
- Mexican Crime Syndicates Are Getting Into Stolen Petroleum (businessinsider.com)
- Will Texas oil companies get a shot at Mexico investments? (mysanantonio.com)
- Pemex’s El Perdido oil deposits may hold 10 billion barrels (fuelfix.com)
- Pena Nieto Push to Open Mexico Oil Fields Sparks Exxon Interest – Bloomberg (bloomberg.com)
- Mexico May Finally Get a Modern Oil Industry (businessweek.com)
By Vicki Vaughan
The report, from information and analytics firm IHS, looked at well performance for oil and oil-rich liquids in the Eagle Ford as well as in the Bakken Shale of North Dakota and Montana, currently the nation’s top play. The Bakken has more wells than the Eagle Ford, but so far, on a per-well basis, the Eagle Ford seems to be producing more than the Bakken.
The Bakken is more established, and the Eagle Ford is still developing.South Texas
This IHS report is part of a broader study that’s under way of 27 of the nation’s shale plays.
The IHS analysis shows that “Eagle Ford drilling results appear to be superior to those of the Bakken,” said Andrew Byrne, director of equity research at IHS and the study’s author.
The Bakken shale is the play against which others are measured, Byrne said, because “it was the key play that really opened up development of unconventional resources” using high-tech drilling methods and hydraulic fracturing.
The Bakken first began to show great promise about 12 years ago, Byrne said.
“The results from the Bakken were so strong that it set the standard by which all others will be measured. It was the one play that incited the industry into pursuing these opportunities,” he said.
Now, though, comes the Eagle Ford.
Wells in the Eagle Ford Shale have a stronger flow – 300 to 600 barrels a day or oil and oil-rich liquids, based on average production in a peak month – than in the Bakken, where flow ranges from 150 to 300 barrels a day.
“One of the reasons we really like the Eagle Ford is its potential as a large total resource. It could be one of the best, if not the best, in North America,” Byrne said.
“The Eagle Ford covers such a vast area. That also makes this such a strong play.”
The Eagle Ford sweeps 400 miles from East Texas to counties south of San Antonio and on to the border.
The play “gets uniformly strong results, and that’s making the play look that much bigger and better,” Byrne said.
“All plays essentially have sweet spots. What makes the Eagle Ford so good is that the noncore stuff is delivering strong results also. In some other plays, it’s only the sweet spot that’s economic.”
The Center for Community and Business Research at the University of Texas at San Antonio has also prepared studies of the Eagle Ford Shale. Center Director Thomas Tunstall predicts that the Eagle Ford Shale will produce 65 million barrels of oil for 2012. Oil production in the Eagle Ford reached 36.6 million barrels in 2011, according to Texas Railroad Commission data.
It’s somewhat difficult to predict production from the shale because the rate of production is accelerating, Tunstall said.
IHS doesn’t yet have an estimate of all the oil that is in the Eagle Ford.
“We’re working on that,” Byrne said.
Last week, Steve Trammel, senior manager of industry affairs for HIS, said in an interview that rig counts are declining in shale plays with much more natural gas than oil because of low natural gas prices.
But drilling is on the rise in shale with oil and “liquids-rich” areas, where wells can tap a mix of oil and condensate, a light oil, and “wet,” or liquid, natural gas, Trammel said.
In fact, the highest average monthly production in the Eagle Ford is coming from the formation’s liquids-rich window, Byrne said.
Asked which might be the next hot play, Byrne said: “We haven’t officially put out that opinion yet. That will have to be reserved until we finish our study.”
The energy industry is “very creative,” he noted. “It seems like every quarter another play shows up.”
- Texas: Experts deliver another round of Eagle Ford bullishness (mb50.wordpress.com)
- Black gold comes to Texas’ rescue again (fuelfix.com)
- Eagle Ford oil production in May tripled from 2011, Texas says (fuelfix.com)
- Eagle Ford banks challenged as deposits skyrocket (mb50.wordpress.com)
- Eagle Ford tied to global economy (mysanantonio.com)
- Black gold comes to Texas’ rescue again (mysanantonio.com)
San Antonio Express-News
Deposits at most of those banks have surged. The Karnes County National Bank’s deposits rocketed 110 percent to almost $168 million from the end of 2009 through the first quarter of this year.
Eleven other institutions registered jumps in deposits that ranged from 46.8 percent to 82.7 percent. By comparison, domestic deposits at U.S. banks increased 14.7 percent during the same period.
But the influx of deposits has left the Eagle Ford-area banks with something of a challenge: how to deploy that money at a time when loan demand isn’t nearly as strong.
“It’s a problem, but it’s a good problem,” said H.B. “Trip” Ruckman III, president and chairman of The Karnes County National Bank in Karnes City. Its deposits rose by $88 million from the end of 2009 to March 31, while its loans rose by $19 million.
“We have had depositors come in with more than a million dollars at a whack,” he added. “So it is a challenge to keep the money invested.”
The San Antonio Express-News tracked deposits and loans from the end of 2009, when activity started picking up in the Eagle Ford Shale, through the first quarter of this year at 20 banks based in the 14 counties directly affected by the oil and gas activity. Most of the banks tracked are small community banks with assets of less than $220 million.
Eighteen of the 20 banks had deposit growth above the national average of 14.7 percent over the 27 months ending March 31.
Deposits at Security State Bank in Pearsall, for example, climbed by $150 million from 2009 through March 31, mostly as a result of the oil and gas activity, said Mike Wilson, president and CEO.
“Where we used to hunt for money, we don’t have to hunt anymore,” he said.
Curtis Carpenter, who follows banks as managing director of Sheshunoff & Co. Investment Banking in Austin, likened the situation to having “more than you can say grace over.”
Still, the deposit windfall has yet to translate to the same growth in loans.
“You can only loan money where it makes sense,” Carpenter said. “And the fact that all of these deposits are coming in doesn’t necessarily translate into lending opportunities.”
Those lending opportunities will pick up as the Eagle Ford area prospers from all the oil and gas activity, Carpenter said. Bankers agreed, saying they are eager to loan on both multifamily and single-family residential projects. There is some reticence to loan on RV parks and motels because of concerns that they’ve saturated the area.
Bankers offered other reasons why loan growth hasn’t corresponded with deposit growth. Banks have to comply with lending standards — set by banking regulators — that are designed to prevent bank failures. Many existing bank customers are paying off loans with their newfound wealth rather than borrowing money. In addition, many of the oil services companies operating in the Eagle Ford Shale have pre-existing relationships with banks outside the area, so they are not turning to South Texas banks for loans.
Lagging loan growth
All but six of the 20 banks studied reported loan growth over the period. That growth ranged from as little as 6.5 percent at Texas Community Bank in Laredo to 62.2 percent at The Karnes County National Bank.
The increase for those 14 banks was well above the 1.8 percent increase for all U.S. banks combined. Nevertheless, the pace of growth significantly lagged the rise in deposit growth that Eagle Ford-area banks experienced.
“Nobody’s been able to keep up with that,” said Fred Hilscher, executive vice president of the First National Bank of Shiner. Its deposits are up $78 million, or 78.5 percent, versus $7.7 million for loans. The bank borders two counties directly affected by the Eagle Ford Shale. He attributed most of the increase in deposits to the shale.
“We would hope that we could have a larger loan growth, more investments, but … we’re very conservative in what we do,” he added.
Security State Bank’s lending is up about $46 million, or 29 percent since the end of 2009, though its deposits were up $150 million. Wilson, the bank’s president and CEO, has been assessing loans for new oil field buildings and yards in the area to ensure that the bank doesn’t concentrate too heavily on these types of investments.
“If this oil play was to quit or really slow down, there’s going to be an oversupply of that type of thing,” he said. “Just like RV parks and motels. The whole Eagle Ford Shale, every major community in it, is inundated with motels.”
Every week, the bank turns down at least one loan application for motel construction, Wilson said. He’d prefer to provide construction financing for apartments or duplexes because there is such a shortage of permanent housing in the area, but developers aren’t interested.
“Everybody wants the immediate huge payback,” he said.
At Dilley State Bank, with nearly $100 million in assets, deposits increased by $33 million, or 70 percent, to $80.4 million. Loans, meanwhile, increased $3.4 million, or 36.2 percent, to almost $12.8 million.
“Our loans are higher now,” said Jeff W. Avant, the bank’s president and CEO. “But they are still relatively low (versus assets) for most banks our size. It’s not that we’re not (looking to lend) — we’re looking. We look at all the loans and possible loans that come in.”
Like most other banks, Dilley State Bank isn’t willing to ease its lending standards to make a loan. And while oil services companies have come into the area, the bank hasn’t had a bump in lending to them.
“A lot of oil companies, they are banking wherever they come from,” Avant said.
Straining capital ratios
The flood of deposits has led to one serious issue for some of these small banks: having enough capital.
Banking regulators require that banks maintain a minimal level of capital. Deposits are listed on a bank’s balance sheet as liabilities, so as deposits swell, the institutions’ owners might have to put up more of their own money — capital — as a hedge against potential losses to satisfy regulators’ requirements.
It’s an issue banks will have to grapple with as long as landowners continue to deposit big checks from royalties and leases. The solution is either to turn away customers or to raise more capital, Sheshunoff’s Carpenter said. Selling stock or retaining earnings are ways to boost capital.
Security State Bank has chosen the latter. The bank has been retaining about half its profits — rather than paying them out to shareholders — to increase its capital so its capital ratios remain stable.
Meanwhile, The Karnes County National Bank is seeking authority from federal banking regulators to sell $5 million in stock to boost its capital, Ruckman said.
“You’ve got to be proactive in these situations, and that’s what we’re trying to do,” he said.
Picky about customers
Dilley State Bank hasn’t gone to the extreme of turning away new customers to limit new deposits, but it’s particular about who it wants banking there.
“We’re not trying to grow deposits. We’re not short on cash,” president and CEO Avant said.
One of Avant’s lieutenants refused to share the bank’s CD rates with a reporter out of fear that it they were published it would generate a slew of phone calls from prospective customers wanting to park their money there for just a short time.
“We are looking for long-term-relation-type customers,” Avant said.
All the activity in the Eagle Ford Shale has created exciting times, Security State Bank’s Wilson said. Yet he can’t quit worrying that it won’t last as long as many predict.
“Everything tells us that this is going to be a long-term play, but we’ve all been through some of these before and nobody saw the end coming until the day after it happened,” he said.
- Eagle Ford tied to global economy (mysanantonio.com)
- New drilling, production in Eagle Ford surges (mb50.wordpress.com)
- Eagle Ford Shale’s has had profound impact on Texas (fuelfix.com)
- Eagle Ford: Enterprise opens crude-gathering system (fuelfix.com)