Premier Reaches Out to Xodus for Catcher FEED Study

Premier Oil has reached out to Xodus Group to conduct a subsea Front End Engineering Design study for the Catcher project in the Central North Sea. Catcher is situated on Block 28/9. The oil field was discovered in June 2010.

Xodus will develop and engineer field and subsea architecture, flow assurance processes, subsea control systems, pipelines and tie-ins, as well as providing technical safety and risk support. The company will also assist in the FEED for the three riser systems for each of the wells, to allow production from the field through the subsea tieback.

Work for the FEED contract will be developed in two phases. Premier stated in a release that a review of previous and current studies, preliminary process flow diagrams and investigative work to identify structural functional requirements, will lay the foundations for the subsequent select phase.

Premier Oil and partners formally agreed on a development concept and have moved into the design phase, which should be completed by the end of September.

"Xodus is proud to be involved in the Catcher project which is a significant development in the North Sea," said Andrew Wylie, senior consultant at Xodus Group in a statement. "Our fully independent, integrated and highly technical service will deliver a wealth of knowledge to this project. Xodus is committed to Aberdeen and the North Sea market and our breadth of capability and multidisciplinary service makes us a preferred partner for FPSO projects. From risers to pipelines, and design to pre-commissioning, we have a proven track record."

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

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Study: Oil, Gas Industry Needs to Step Up Water Management

The oil and gas industry needs to step up efforts to expand its use of recycled water and non-freshwater resources and implement better water management planning if shale energy production is to expand according to projections.

Research conducted by San Francisco-based CERES indicates that nearly 47 percent of wells were developed in water basins with high or extremely high water stress. Most of the hydraulic fracturing activity in the United States is occurring in Texas and Colorado, which are experiencing prolonged drought conditions.

The report is based on well drilling and water use data from FracFocus.org and water stress indicator maps developed by the World Resources Institute. The research was based on FracFocus’ data on 25,450 wells in operation from January 2011 through September 2012.

Ninety-two percent of Colorado wells analyzed in the report are in extremely high water stress regions. In Texas, which accounts for nearly half of the total wells analyzed, 51 percent of the wells were in high or extremely high water stress regions. Water use in hydraulic fracturing in some Texas counties accounted for over 20 percent of the region's total water use. Concerns over water usage for hydraulic fracturing in Texas prompted legislators to mandate water recycling in the oil and gas industry.

Seventy percent of the wells analyzed in Pennsylvania were in medium to high water stress water basins and only 2 percent were in high water stress basins.

"Given projected sharp increases in shale oil and gas production in the coming years, competition over water should be a growing concern to energy companies," CERES concluded in the report, noting that hydraulically fractured oil and gas production is expected to double in the coming years. "Shale energy development cannot grow without water, but in order to do so the industry's water needs and impacts need to be better understood, measured and managed."

The industry has made progress in increasing its use of recycled water and other alternative water sources for fracturing wells, including non-freshwater alternatives such as wastewater, saline water, seawater and acid-mine drainage. But overall water recycling and use of non-freshwater sources must rise considerably to have a significant impact.

Key recommendations by CERES for companies and regulators include:

Comprehensive mandatory disclosure by companies of how much freshwater, non-freshwater and recycled water they are using region by region as well as how much water is returning to the surface and where it is ending upRequirements for companies to set quantifiable water use targets, such as recycling and non-freshwater use targetsEnsure that companies and local regulators are conducting sufficient water management planningEnsure companies have a local stakeholder engagement process in place on water issues

The U.S. oil and gas industry's increased exploration and production of U.S. unconventional resources has increased the amount of water being used by the oil and gas industry in its operations.

Best practices for water management in unconventional exploration and production activity are still evolving as companies address water use management issues such as the cost of transporting water to drilling sites, whether to treat or dispose of water, and concerns by environmental groups, state officials and the U.S. public over the amount of water used and the impact of hydraulic fracturing on water supply in shale regions.

A number of water treatment processes are also becoming available to the oil and gas industry, including EcoLogix and EcoSphere, which Rigzone reported on last year.

Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@rigzone.com.

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Japan to Study Ice Gas Reserves

Japan is planning a three-year study into how much methane hydrate, or "ice gas", it has within its territorial waters in the Japan Sea over the next three years, the country's trade and industry minister said Tuesday.

Japan will also continue to develop technologies to extract natural gas from undersea methane hydrate reserves with the aim of making commercialization of the process viable by as early as 2023, Minister of Economy, Trade and Industry Toshimitsu Motegi said Tuesday.

Methane hydrate is a compound in which a large amount of methane is trapped within a crystal structure made up of water, so forming a solid that is similar to ice.

Japan Oil, Gas and Metals National Corporation (JOGMEC) reported March 12 that it successfully extracted natural gas from methane hydrate deposits from under the seabed offshore Japan.

Dow Jones Newswires contributed to this article.

A former engineer, Jon is an award-winning editor who has covered the technology, engineering and energy sectors since the mid-1990s. Email Jon at jmainwaring@rigzone.com.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Japan to Study Ice Gas Reserves

Japan is planning a three-year study into how much methane hydrate, or "ice gas", it has within its territorial waters in the Japan Sea over the next three years, the country's trade and industry minister said Tuesday.

Japan will also continue to develop technologies to extract natural gas from undersea methane hydrate reserves with the aim of making commercialization of the process viable by as early as 2023, Minister of Economy, Trade and Industry Toshimitsu Motegi said Tuesday.

Methane hydrate is a compound in which a large amount of methane is trapped within a crystal structure made up of water, so forming a solid that is similar to ice.

Japan Oil, Gas and Metals National Corporation (JOGMEC) reported March 12 that it successfully extracted natural gas from methane hydrate deposits from under the seabed offshore Japan.

Dow Jones Newswires contributed to this article.

A former engineer, Jon is an award-winning editor who has covered the technology, engineering and energy sectors since the mid-1990s. Email Jon at jmainwaring@rigzone.com.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Study: Fracking May Boost California's Economy, Adding 2.8M Jobs

Development of California's Monterey shale formation can play the major role in the state's future economic well-being, noted a recent study, "Powering California: The Monterey Shale and California's Economic Future", released by the University of Southern California (USC) and Los Angeles-based think tank Communications Institute.

California's Monterey shale is estimated to hold 15 billion barrels of oil and development of the 1,750-square mile formation in central California could generate half a million new jobs by 2015 and 2.5 million jobs by 2020.

"This report provides an indication that there is one potential bright spot in California's economic future: the increased production of energy," the report stated. "California has long served as the incubator for emerging energy sources and technologies, as the state has taken advantage of both technology and its natural resources to become a leader in the generation of renewable energy. Now, these same technological and resource advantages can allow the state to return to leadership in the production of oil."

The Monterey/Santos play, a prolific source rock for many of California's large oil fields, is considered by far the largest shale oil formation in the United States, roughly two-thirds of total oil shale potential. By those numbers, the Monterey reserves trump the Bakken and Eagle Ford fields.

This new onshore oil play can easily pump up the nation's oil output by 25 percent in just a few years and help the state's local energy picture. California has more recoverable reserves in shale than nearby big oil-producing countries, according to a July 2012 report issued by the U.S. Energy Information Administration (EIA).

To tap this prolific shale play, horizontal drilling and hydraulic fracturing would most likely be used, which has riled environmentalists to oppose this widely-used drilling technique. And much pressure has been placed on California's Governor Jerry Brown, a Democrat, but the opposite has occurred.

"We want to get the greenhouse gas emissions down, but we also want to keep our economy going," he said at a March 13 press conference, Reuters reported. "That's the balance that's required. The fossil fuel deposits in California are incredible, the potential is extraordinary. But between now and development lies a lot of questions that need to be answered."

The study forecasts that the state could greatly benefit, about $4.5 billion in oil-related tax revenue in 2015 and $24.6 billion by 2020. California boasts perhaps the largest deep-shale reserves in the world – reserves that, unlike elsewhere, hold the promise for an unprecedented volume of advanced crude oil production, the study noted. California's well-known offshore reserves contain more than 10 billion barrels of oil and nearly 12 trillion cubic feet of natural gas but the onshore play is projected to hold even more oil – more than 15 billion barrels, according to the EIA.

"Gov. Brown is trying to do what he feels is best for California and he realizes that much of the negative publicity was not based on an understanding of the facts," stated Don Clarke, a Los Angeles consulting geologist, in an interview with Rigzone. "We must protect the environment and any Monterey development can only be done with proper consideration to the environment and especially the groundwater."

Development of the oil-shale deposits may boost the state's economic activity by as much as 14.3 percent, the study said. And with that, increasing the state's per-capita gross domestic product (GDP).

"California, whose Monterey Formation alone is estimated to be four times larger than North Dakota's Bakken reserve, has chosen… to sharply limit its fossil-fuel industry. As a result, it has generated barely one-tenth the new fossil-fuel jobs in archrival Texas. Not surprisingly, California … lagged behind in GDP and income growth, while the energy states have for the most part enjoyed the strongest gains," author Joel Kotkin said Dec. 7 in the Daily Beast.

With more than 10 years of journalism experience, Robin Dupre specializes in the offshore sector of the oil and gas industry. Email Robin at rdupre@rigzone.com.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Study: Fracking May Boost California's Economy, Adding 2.8M Jobs

Development of California's Monterey shale formation can play the major role in the state's future economic well-being, noted a recent study, "Powering California: The Monterey Shale and California's Economic Future", released by the University of Southern California (USC) and Los Angeles-based think tank Communications Institute.

California's Monterey shale is estimated to hold 15 billion barrels of oil and development of the 1,750-square mile formation in central California could generate half a million new jobs by 2015 and 2.5 million jobs by 2020.

"This report provides an indication that there is one potential bright spot in California's economic future: the increased production of energy," the report stated. "California has long served as the incubator for emerging energy sources and technologies, as the state has taken advantage of both technology and its natural resources to become a leader in the generation of renewable energy. Now, these same technological and resource advantages can allow the state to return to leadership in the production of oil."

The Monterey/Santos play, a prolific source rock for many of California's large oil fields, is considered by far the largest shale oil formation in the United States, roughly two-thirds of total oil shale potential. By those numbers, the Monterey reserves trump the Bakken and Eagle Ford fields.

This new onshore oil play can easily pump up the nation's oil output by 25 percent in just a few years and help the state's local energy picture. California has more recoverable reserves in shale than nearby big oil-producing countries, according to a July 2012 report issued by the U.S. Energy Information Administration (EIA).

To tap this prolific shale play, horizontal drilling and hydraulic fracturing would most likely be used, which has riled environmentalists to oppose this widely-used drilling technique. And much pressure has been placed on California's Governor Jerry Brown, a Democrat, but the opposite has occurred.

"We want to get the greenhouse gas emissions down, but we also want to keep our economy going," he said at a March 13 press conference, Reuters reported. "That's the balance that's required. The fossil fuel deposits in California are incredible, the potential is extraordinary. But between now and development lies a lot of questions that need to be answered."

The study forecasts that the state could greatly benefit, about $4.5 billion in oil-related tax revenue in 2015 and $24.6 billion by 2020. California boasts perhaps the largest deep-shale reserves in the world – reserves that, unlike elsewhere, hold the promise for an unprecedented volume of advanced crude oil production, the study noted. California's well-known offshore reserves contain more than 10 billion barrels of oil and nearly 12 trillion cubic feet of natural gas but the onshore play is projected to hold even more oil – more than 15 billion barrels, according to the EIA.

"Gov. Brown is trying to do what he feels is best for California and he realizes that much of the negative publicity was not based on an understanding of the facts," stated Don Clarke, a Los Angeles consulting geologist, in an interview with Rigzone. "We must protect the environment and any Monterey development can only be done with proper consideration to the environment and especially the groundwater."

Development of the oil-shale deposits may boost the state's economic activity by as much as 14.3 percent, the study said. And with that, increasing the state's per-capita gross domestic product (GDP).

"California, whose Monterey Formation alone is estimated to be four times larger than North Dakota's Bakken reserve, has chosen… to sharply limit its fossil-fuel industry. As a result, it has generated barely one-tenth the new fossil-fuel jobs in archrival Texas. Not surprisingly, California … lagged behind in GDP and income growth, while the energy states have for the most part enjoyed the strongest gains," author Joel Kotkin said Dec. 7 in the Daily Beast.

With more than 10 years of journalism experience, Robin Dupre specializes in the offshore sector of the oil and gas industry. Email Robin at rdupre@rigzone.com.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Japan to Study Ice Gas Reserves

Japan is planning a three-year study into how much methane hydrate, or "ice gas", it has within its territorial waters in the Japan Sea over the next three years, the country's trade and industry minister said Tuesday.

Japan will also continue to develop technologies to extract natural gas from undersea methane hydrate reserves with the aim of making commercialization of the process viable by as early as 2023, Minister of Economy, Trade and Industry Toshimitsu Motegi said Tuesday.

Methane hydrate is a compound in which a large amount of methane is trapped within a crystal structure made up of water, so forming a solid that is similar to ice.

Japan Oil, Gas and Metals National Corporation (JOGMEC) reported March 12 that it successfully extracted natural gas from methane hydrate deposits from under the seabed offshore Japan.

Dow Jones Newswires contributed to this article.

A former engineer, Jon is an award-winning editor who has covered the technology, engineering and energy sectors since the mid-1990s. Email Jon at jmainwaring@rigzone.com.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Study: Fracking May Boost California's Economy, Adding 2.8M Jobs

Development of California's Monterey shale formation can play the major role in the state's future economic well-being, noted a recent study, "Powering California: The Monterey Shale and California's Economic Future", released by the University of Southern California (USC) and Los Angeles-based think tank Communications Institute.

California's Monterey shale is estimated to hold 15 billion barrels of oil and development of the 1,750-square mile formation in central California could generate half a million new jobs by 2015 and 2.5 million jobs by 2020.

"This report provides an indication that there is one potential bright spot in California's economic future: the increased production of energy," the report stated. "California has long served as the incubator for emerging energy sources and technologies, as the state has taken advantage of both technology and its natural resources to become a leader in the generation of renewable energy. Now, these same technological and resource advantages can allow the state to return to leadership in the production of oil."

The Monterey/Santos play, a prolific source rock for many of California's large oil fields, is considered by far the largest shale oil formation in the United States, roughly two-thirds of total oil shale potential. By those numbers, the Monterey reserves trump the Bakken and Eagle Ford fields.

This new onshore oil play can easily pump up the nation's oil output by 25 percent in just a few years and help the state's local energy picture. California has more recoverable reserves in shale than nearby big oil-producing countries, according to a July 2012 report issued by the U.S. Energy Information Administration (EIA).

To tap this prolific shale play, horizontal drilling and hydraulic fracturing would most likely be used, which has riled environmentalists to oppose this widely-used drilling technique. And much pressure has been placed on California's Governor Jerry Brown, a Democrat, but the opposite has occurred.

"We want to get the greenhouse gas emissions down, but we also want to keep our economy going," he said at a March 13 press conference, Reuters reported. "That's the balance that's required. The fossil fuel deposits in California are incredible, the potential is extraordinary. But between now and development lies a lot of questions that need to be answered."

The study forecasts that the state could greatly benefit, about $4.5 billion in oil-related tax revenue in 2015 and $24.6 billion by 2020. California boasts perhaps the largest deep-shale reserves in the world – reserves that, unlike elsewhere, hold the promise for an unprecedented volume of advanced crude oil production, the study noted. California's well-known offshore reserves contain more than 10 billion barrels of oil and nearly 12 trillion cubic feet of natural gas but the onshore play is projected to hold even more oil – more than 15 billion barrels, according to the EIA.

"Gov. Brown is trying to do what he feels is best for California and he realizes that much of the negative publicity was not based on an understanding of the facts," stated Don Clarke, a Los Angeles consulting geologist, in an interview with Rigzone. "We must protect the environment and any Monterey development can only be done with proper consideration to the environment and especially the groundwater."

Development of the oil-shale deposits may boost the state's economic activity by as much as 14.3 percent, the study said. And with that, increasing the state's per-capita gross domestic product (GDP).

"California, whose Monterey Formation alone is estimated to be four times larger than North Dakota's Bakken reserve, has chosen… to sharply limit its fossil-fuel industry. As a result, it has generated barely one-tenth the new fossil-fuel jobs in archrival Texas. Not surprisingly, California … lagged behind in GDP and income growth, while the energy states have for the most part enjoyed the strongest gains," author Joel Kotkin said Dec. 7 in the Daily Beast.

With more than 10 years of journalism experience, Robin Dupre specializes in the offshore sector of the oil and gas industry. Email Robin at rdupre@rigzone.com.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Senecio Tight Gas Feasibility Study Underway

AWE disclosed Thursday that it has started on a development feasibility study for the commercialization of the onshore Senecio tight gas accumulation. The Senecio discovery is located in the north Perth Basin, Western Australia.

Analysis of pressure tests conducted in November 2012 and other data captured since the fracture stimulation has confirmed permeability of between 0.03 millidarcy (mD) to 0.06 mD, which is within the pre-fracture estimated range.

"This analysis, together with the successful flow test in September 2012 that reported a stabilized gas rate of 1.35 million standard cubic feet of gas per day, with a 16-foot (five-meter) perforation interval, demonstrates potentially commercial reservoir flow capacity," AWE said in a statement. AWE's project partner is Origin Energy. Both of the companies have an equal stake in the partnership.

AWE has previously booked a 2C contingent resource for its 50 percent equity share of Senecio of 4.4 million barrels of oil equivalent (mmboe). Previously interpreted 2D seismic data indicated a potential estimated recoverable volume of at least double the quantity currently booked. An outcome of the feasibility study will be an updated definitive resource estimate which will be based on latest interpretation of the well data, the new 3D seismic data, and planned reservoir modeling studies.

AWE's Managing Director Bruce Clement, said that the Senecio tight gas commercialization program is gaining momentum and that positive subsurface data has given the company considerable confidence that commercial gas production can be achieved from the Senecio discovery.

"The results of the pressure test, the flow test, and the Irwin 3D seismic program indicate that a horizontal, multi-stage, hydraulically fracture stimulated well at Senecio could be economically viable," Clement noted in a statement.

"The Perth Basin is potentially a very important source of energy for the Western Australian market and we believe that the timely completion of a development feasibility study will help define a valuable gas resource," Clement added.

AWE plans to consider the use of nearby existing plant processing infrastructure to minimize the project's environmental footprint and development costs. Evaluation of the Dongara and Xyris gas plants and associated infrastructure will form part of the study.
Detailed work on project planning, budget and product marketing may start as soon as 2Q 2013.

Clement said: "The unconventional gas program in the Perth Basin has been very successful to date, significantly increasing our understanding of the geological and commercial potential of the tight gas and shale gas opportunities in the Basin.

Our exploration team is looking at 30 years of accumulated data for the Perth Basin, compiled through conventional oil and gas exploration activities, to identify additional tight gas intersections with development potential."

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Senecio Tight Gas Feasibility Study Underway

AWE disclosed Thursday that it has started on a development feasibility study for the commercialization of the onshore Senecio tight gas accumulation. The Senecio discovery is located in the north Perth Basin, Western Australia.

Analysis of pressure tests conducted in November 2012 and other data captured since the fracture stimulation has confirmed permeability of between 0.03 millidarcy (mD) to 0.06 mD, which is within the pre-fracture estimated range.

"This analysis, together with the successful flow test in September 2012 that reported a stabilized gas rate of 1.35 million standard cubic feet of gas per day, with a 16-foot (five-meter) perforation interval, demonstrates potentially commercial reservoir flow capacity," AWE said in a statement. AWE's project partner is Origin Energy. Both of the companies have an equal stake in the partnership.

AWE has previously booked a 2C contingent resource for its 50 percent equity share of Senecio of 4.4 million barrels of oil equivalent (mmboe). Previously interpreted 2D seismic data indicated a potential estimated recoverable volume of at least double the quantity currently booked. An outcome of the feasibility study will be an updated definitive resource estimate which will be based on latest interpretation of the well data, the new 3D seismic data, and planned reservoir modeling studies.

AWE's Managing Director Bruce Clement, said that the Senecio tight gas commercialization program is gaining momentum and that positive subsurface data has given the company considerable confidence that commercial gas production can be achieved from the Senecio discovery.

"The results of the pressure test, the flow test, and the Irwin 3D seismic program indicate that a horizontal, multi-stage, hydraulically fracture stimulated well at Senecio could be economically viable," Clement noted in a statement.

"The Perth Basin is potentially a very important source of energy for the Western Australian market and we believe that the timely completion of a development feasibility study will help define a valuable gas resource," Clement added.

AWE plans to consider the use of nearby existing plant processing infrastructure to minimize the project's environmental footprint and development costs. Evaluation of the Dongara and Xyris gas plants and associated infrastructure will form part of the study.
Detailed work on project planning, budget and product marketing may start as soon as 2Q 2013.

Clement said: "The unconventional gas program in the Perth Basin has been very successful to date, significantly increasing our understanding of the geological and commercial potential of the tight gas and shale gas opportunities in the Basin.

Our exploration team is looking at 30 years of accumulated data for the Perth Basin, compiled through conventional oil and gas exploration activities, to identify additional tight gas intersections with development potential."

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Chesapeake Energy to Host EPA in Study of Fracking Risk to Water

WASHINGTON--Natural gas producer Chesapeake Energy Corp. (CHK) has agreed to let the Environmental Protection Agency conduct extensive tests at one of its drilling sites as part of an investigation into the safety of hydraulic fracturing, an administration official said.

The testing, which will involve water sampling before and after drilling takes place, will serve as a cornerstone of a yearslong EPA study to determine whether the process known as fracking poses a risk to water supplies.

Another natural gas company, Range Resources Corp. (RRC), also may allow the EPA to work at one of its drilling sites, although an agreement has been held up by researcher liability concerns at a drilling site, a Range Resources spokesman said.

The moves suggest companies believe they can pass close inspection by government scientists and hope cooperation will lead to a favorable view of fracking in the closely watched EPA study, which is due next year and is seen by both sides as having a major effect on the future of natural-gas drilling in the U.S.

The EPA says its study also will include sites where contamination has already been reported, including drilling projects by Pioneer Natural Resources Co. (PXD), Denbury Resources Inc. (DNR), Cabot Oil and Gas Corp. (COG), and others.

But some of the most important work involves before-and-after testing of water quality and Chesapeake's participation will give the agency access to an active drilling project.

The EPA, which earlier expressed concern that such studies couldn't be completed in time for next year's report, now is expressing more confidence. An agency official said the results will be included so long as work starts before the spring.

Chesapeake, the second-largest U.S. gas producer after Exxon Mobil Corp. (XOM), and the EPA are "very close" to settling on a location and a start date, the official said. A spokesman for Oklahoma City-based Chesapeake declined to comment.

"The value of these tests is that they are really the first independent review of what's happening from start to finish. It is a data set that doesn't really exist right now," said Briana Mordick, a scientist at the Natural Resources Defense Council.

However, Glenn Miller, a University of Nevada, Reno, professor of environmental science who studies water issues, said the EPA's test results should be taken with a grain of salt.

"If a company knows they're being followed closely, they're going to be very, very careful," Mr. Miller said.

U.S. production of natural gas has surged following advances in technology that allow energy companies to extract the fuel from hard-to-reach spots. In fracking, drillers pump a mix of water, sand and chemicals deep underground at high pressure to break apart energy-rich rocks and allow gas and oil to flow to the surface. The technique, used in many onshore drilling projects, is essential to harvesting huge oil and gas deposits trapped in shale.

The boom in production has stoked fears of water contamination. Some environmental groups, such as the Sierra Club, have called for stringent new controls.

Several natural-gas companies already test water supplies before they start to drill to establish existing conditions in case they are later accused of contaminating the water. Duke University researchers also are testing water samples in areas where drilling is likely to occur to perform before-and-after analysis.

The EPA declined to identify the location of the Chesapeake drilling site. The agency had said in December it had planned to do testing at a Chesapeake project in Louisiana's DeSoto Parish, but scheduling conflicts forced it to abandon those plans.

"We're confident in the science and the facts, and that [the EPA] will reach the same conclusions as everyone else," said Matt Pitzarella, a spokesman for Fort Worth, Texas-based Range Resources.

Range Resources "would very much like to work" with the EPA, Mr. Pitzarella said. While there is a holdup related to liability waivers for EPA employees at the site, "we're confident that we can reach an agreement," he said. Range Resources has been looking at letting the EPA conduct tests at a site in Washington County, Pa.

In 2010, the EPA accused Range Resources of causing natural gas to seep into water wells near some of its gas wells in North Texas, but it dropped the claim last year. The EPA is still working on a study of natural gas drilling in Pavillion, Wyo., after the site producer, Encana Corp. (ECA, ECA.T), and other government agencies challenged a 2011 draft EPA report that suggested a link to water contamination at Pavillion.

-Daniel Gilbert contributed to this article.

Copyright (c) 2012 Dow Jones & Company, Inc.

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Great Barrier Reef has lost half its corals since 1985, new study says

Australia’s Great Barrier Reef has lost more than half its coral cover since 1985, according to a new study published Monday. The loss has been spurred by a combination of factors including hurricanes, coral-eating starfish and coral bleaching.The paper, in the Proceedings of the National Academy of Sciences, is the most comprehensive survey of a reef system over such a long period. The researchers from the Australian Institute of Marine Science found that reef cover fell from 28 percent to 13.8 percent over the past 27 years, with two-thirds of the decline occurring since 1998.

The sobering findings highlighted how even the world’s most protected marine areas are under assault from natural forces and causes linked to the human activity that is resulting in climate change. The Great Barrier Reef is the world’s largest coral reef ecosystem, featuring nearly 3,000 individual reefs within 133,205 square miles. A third of the Great Barrier Reef Marine Park is off-limits to fishing and collecting.

“We are basically losing an ecosystem that is so iconic for Australia and the rest of the world,” said institute scientist Katharina E. Fabricius, one of the paper’s authors.

Storm damage accounted for 48 percent of the decline, scientists said, while crown-of-horns starfish contributed 42 percent. Coral bleaching, caused by warmer water, accounted for 10 percent of coral loss. Read more

 

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Another Study ‘Showing’ No Contamination from Fracking

Where to begin in a review of Pro Publica’s article on new research into the migration of subterranean brine to shallow water above? The inflammatory, overreaching headline? The leap from Duke University’s study to conclusions suggesting to the public that hydraulic fracturing is polluting drinking water?

Let’s start there. On that point the article is self-rebutting. See the fourth paragraph:

"No drilling chemicals were detected in the (shallow) water, and there was no correlation between where the natural brine was detected and where drilling takes place."

Then, near the end of the article:

"Nevertheless, (Robert) Jackson, one of the study's authors, said he still considers it unlikely that frack fluids and injected man-made waste are migrating into drinking water supplies. If that were happening, those contaminants would be more likely to appear in his groundwater samples, he said. His group is continuing its research into how the natural brine might have travelled, and how long it took to rise to the surface. 'There is a real time uncertainty,' he said. 'We don't know if this happens over a couple of years, or over millennia.'"

As for the study itself, Jackson and his team say they found that naturally occurring brine migrates upward to shallower depths. They say the risk of the migration could be greater in areas that have undergone hydraulic fracturing. Yet, there’s this from the study’s introductory summary:

“The occurrences of saline water do not correlate with the location of shale-gas wells and are consistent with reported data before rapid shale-gas development in the region …”

Energy In Depth has solid analysis on the study, here. Highlights:

The study fails (as Jackson notes above) to establish whether the migration occurs over 10 years or 10 million years. Without that, it’s impossible to determine whether the phenomenon is cause for concern.If brine is traveling up from thousands of feet below the surface, why haven’t the pathways Duke’s researchers identify allowed natural gas in the Marcellus region to leak out and disappear over time?There’s no discussion of whether the Marcellus Shale – which is largely a dry region with “virtually no free water,” according to Penn State’s Terry Engelder – even contains enough brinewater to leak.

Engelder, a Marcellus expert who was asked by the researchers to review their work, notes a number of questions the study leaves unanswered, reducing its usefulness. He writes:

"My review is predicated on the objective of your paper which is stated as a search for '...specific areas of shale-gas development in northeastern Pennsylvania that are at increased risk for contamination of shallow drinking water resources with deeper formation brines...' (the last sentence of your abstract). The term, risk, suggests that your paper veers from a conventional geology paper and enters into the realm of science-based advocacy or if you like, science policy."

Engelder is on target there. Unfortunately, the academics, wittingly or unwittingly, produced a study that is easily morphed into a siren call by opponents of natural gas production. Pro Publica’s article is Exhibit A. Exhibit B is a Bloomberg News story under this headline: “Pennsylvania Fracking Can Put Water at Risk, Study Finds” – despite the fact the study found no evidence of such a risk.

Words like “can,” “may” and “might” camouflage the point that the study didn’t find a correlation between the location of shale-gas wells and occurrences of saline water. To suggest otherwise in a news article is disingenuous and counterproductive in the national discussion of energy from shale.

As Engelder notes, the study is a platform from which advocates can mislead. On this story, The Associated Press got it right, focusing its report on what the study showed: “Gas drilling in northeastern Pennsylvania did not contaminate nearby drinking water wells with salty water, which is a byproduct of the drilling.”

View the original article here

Study: EPA’s Tier III Proposal Would Increase Fuel-Making Costs

At a time when just everyone is understandably concerned about fuel prices, EPA apparently didn’t get the memo. Its latest thinking on a Tier III refinery rulemaking would add significant costs to the making of gasoline, according to a new analysis by Baker & O’Brien, Inc.

During a recent conference call with reporters, API’s Bob Greco, group director for downstream and industry operations, talked about the impacts on refiners of the proposed rule to further reduce sulfur levels in gasoline:

Nearly $10 billion in new capital costs to industry.Increase of between 6 cents and 9 cents per gallon to the cost of manufacturing gasoline, according to Baker & O’Brien.Increase of as much as 25 cents per gallon if a vapor pressure reduction requirement, which EPA considered, is included.

Greco:

“With the pump price of gasoline already above $4 a gallon in some parts of the country, this added burden clearly makes Tier III the wrong regulation at the wrong time. More importantly, EPA has yet to demonstrate any air quality benefits from reducing sulfur in the amount proposed. And, as the Baker & O’Brien analysis also shows, implementing the new requirements would increase refinery greenhouse gas emissions because of the use of energy-intensive hydrotreating equipment to remove sulfur from the gasoline.”

EPA claims the new rule wouldn’t be a hardship. But Greco said the agency cites a “low-ball cost estimate” that uses flawed modeling about what U.S. refineries would have to do to be in compliance. Although EPA has dropped the gasoline vapor pressure requirement, industry doesn’t believe the provision is off the table.

The Baker & O’Brien analysis found that while the sulfur requirement alone probably wouldn’t lead to refinery closures, Tier III in tandem with other potential EPA requirements could cause some refineries to close, resulting in diminished fuel manufacturing capacity and increased reliance on imported fuels – all for what Baker & O’Brien said would be modest environmental benefits. Greco:

“Refinery regulations clearly contribute to a cleaner environment and safer workplace, but, unnecessary, inefficient, and excessively costly requirements hamper our ability to provide and distribute fuels to America, while also employing hundreds of thousands of people and enhancing our national security. We have already seen some refineries close, at least in part due to the cumulative impact of environmental controls. We urge the administration to take a step back on Tier III and its other proposed rules. We must be sure that new regulatory proposals are necessary, properly crafted, practical, and fair to allow US refiners to remain competitive, preserve good paying refinery jobs, and ensure our energy security.”

View the original article here

Study: EPA’s Tier III Proposal Would Increase Fuel-Making Costs

At a time when just everyone is understandably concerned about fuel prices, EPA apparently didn’t get the memo. Its latest thinking on a Tier III refinery rulemaking would add significant costs to the making of gasoline, according to a new analysis by Baker & O’Brien, Inc.

During a recent conference call with reporters, API’s Bob Greco, group director for downstream and industry operations, talked about the impacts on refiners of the proposed rule to further reduce sulfur levels in gasoline:

Nearly $10 billion in new capital costs to industry.Increase of between 6 cents and 9 cents per gallon to the cost of manufacturing gasoline, according to Baker & O’Brien.Increase of as much as 25 cents per gallon if a vapor pressure reduction requirement, which EPA considered, is included.

Greco:

“With the pump price of gasoline already above $4 a gallon in some parts of the country, this added burden clearly makes Tier III the wrong regulation at the wrong time. More importantly, EPA has yet to demonstrate any air quality benefits from reducing sulfur in the amount proposed. And, as the Baker & O’Brien analysis also shows, implementing the new requirements would increase refinery greenhouse gas emissions because of the use of energy-intensive hydrotreating equipment to remove sulfur from the gasoline.”

EPA claims the new rule wouldn’t be a hardship. But Greco said the agency cites a “low-ball cost estimate” that uses flawed modeling about what U.S. refineries would have to do to be in compliance. Although EPA has dropped the gasoline vapor pressure requirement, industry doesn’t believe the provision is off the table.

The Baker & O’Brien analysis found that while the sulfur requirement alone probably wouldn’t lead to refinery closures, Tier III in tandem with other potential EPA requirements could cause some refineries to close, resulting in diminished fuel manufacturing capacity and increased reliance on imported fuels – all for what Baker & O’Brien said would be modest environmental benefits. Greco:

“Refinery regulations clearly contribute to a cleaner environment and safer workplace, but, unnecessary, inefficient, and excessively costly requirements hamper our ability to provide and distribute fuels to America, while also employing hundreds of thousands of people and enhancing our national security. We have already seen some refineries close, at least in part due to the cumulative impact of environmental controls. We urge the administration to take a step back on Tier III and its other proposed rules. We must be sure that new regulatory proposals are necessary, properly crafted, practical, and fair to allow US refiners to remain competitive, preserve good paying refinery jobs, and ensure our energy security.”

View the original article here