Local Participation Push for Major Australian Developments

Leaders of Australia's oil and gas industry are working together in an effort to develop methods towards increasing the amount of local content on major developments.

Locally based suppliers servicing the growing liquefied natural gas sector in Western Australia (WA) have expressed concern in recent years about being overlooked for development contracts.

Developers have cited the high Australian dollar, high labor costs and rising energy costs as reasons for opting to award contracts to competing foreign companies, often from Asia.

Despite these obstacles, developers have been urged to do more to increase local participation in projects.

Local suppliers are also being encouraged to develop a better understanding of the criteria to help them win contracts.

The issue was a key topic at the Australasian Oil & Gas Conference in Perth recently where industry groups, government representatives, and oil and gas companies discussed how more local participation could take place.

Paul Johnson, the Australian Government's Energy Resources Supplier Advocate, spoke at the conference and believes oil and gas developers need to take into account the capability and capacity of Australian suppliers if they want to boost the level of local content on their projects.

Johnson, who was appointed to this position in August of last year, said there was much good work happening in the sector to raise the capability of Australian firms to win work, but more could be done by both developers and suppliers.

"Project developers should take into account the limitations faced by Australian suppliers in undertaking large procurement packages, accessing the necessary finance and obtaining sufficient numbers of skilled workers," Johnson said.

"Small adjustments to the way projects are designed, engineered and procured can make a big difference to local suppliers.

"Early consideration of what can be done here should inform the design and engineering approach and basing some of the procurement team in Australia will lead to better engagement with local suppliers."

While major developers have been questioned for the amount of local content on their projects, Chevron reinforced its commitment to local suppliers through its conference presentation.

Colin Beckett, Chevron's general manager at the Gorgon LNG development, explained that the project had so far awarded $18.7 billion (AUD $18 billion) in contracts to local suppliers and created 9.000 jobs in the country.

However, he conceded that many Australian companies had not met the pre-conditions for tendering for work, with reasons including a lack of experience or capacity.

To assist in preparing local firms to win work, Australia's Department of Industry, Innovation, Science, Research and Tertiary Education last year engaged economic advisory firm, Development Impacts, to undertake a project examining best practices by companies successfully supplying into the sector to determine how they meet the needs of project proponents.

Pia Turcinov, Development Impacts director, explained to Rigzone that it found there was more to the issue than obstacles such as a high Australian dollar, a lack of financial profile and Australia's skills shortage.

"They are huge hurdles for Australian companies, but there are other issues surrounding what the benchmarks are that local companies need to meet before they are considered… even in the tender stage," Turcinov, who also addressed the conference, said.

"Our work on this project identified 22 key factors companies need to focus on.

"Yes, price was a major factor, but other key factors were about quality, flexibility, design capabilities, QA systems, technical expertise, after sale service, and financial capabilities and risk profile.

"We looked at factors such as these and how the better performing companies compare and where they are outperforming against expectations."

Turcinov explained that suppliers needed to establish a clear capability beyond just a normal website and marketing brochure, and it was advisable for them to look at forming alliances with other local companies to build profile and capability.

In an election year, both at a federal and state level in WA, political parties in Australia have been prioritizing this issue.

WA's governing Liberal Party regularly produces an industry participation framework aimed at ensuring the local industry receives opportunity to participate in major resource projects.

The opposing Labor Party in WA has also shown its commitment by releasing a discussion paper outlining its openness to the issue.

At a federal level, the governing Labor Party is focusing on strengthening opportunities for the local industry through a proposed plan administering the issue.

Under the plan, major projects worth $519 million (AUD $500) million or more will be required to have an Australian industry participation plan identifying opportunities for local firms.

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

Local Participation Push for Major Australian Developments

Leaders of Australia's oil and gas industry are working together in an effort to develop methods towards increasing the amount of local content on major developments.

Locally based suppliers servicing the growing liquefied natural gas sector in Western Australia (WA) have expressed concern in recent years about being overlooked for development contracts.

Developers have cited the high Australian dollar, high labor costs and rising energy costs as reasons for opting to award contracts to competing foreign companies, often from Asia.

Despite these obstacles, developers have been urged to do more to increase local participation in projects.

Local suppliers are also being encouraged to develop a better understanding of the criteria to help them win contracts.

The issue was a key topic at the Australasian Oil & Gas Conference in Perth recently where industry groups, government representatives, and oil and gas companies discussed how more local participation could take place.

Paul Johnson, the Australian Government's Energy Resources Supplier Advocate, spoke at the conference and believes oil and gas developers need to take into account the capability and capacity of Australian suppliers if they want to boost the level of local content on their projects.

Johnson, who was appointed to this position in August of last year, said there was much good work happening in the sector to raise the capability of Australian firms to win work, but more could be done by both developers and suppliers.

"Project developers should take into account the limitations faced by Australian suppliers in undertaking large procurement packages, accessing the necessary finance and obtaining sufficient numbers of skilled workers," Johnson said.

"Small adjustments to the way projects are designed, engineered and procured can make a big difference to local suppliers.

"Early consideration of what can be done here should inform the design and engineering approach and basing some of the procurement team in Australia will lead to better engagement with local suppliers."

While major developers have been questioned for the amount of local content on their projects, Chevron reinforced its commitment to local suppliers through its conference presentation.

Colin Beckett, Chevron's general manager at the Gorgon LNG development, explained that the project had so far awarded $18.7 billion (AUD $18 billion) in contracts to local suppliers and created 9.000 jobs in the country.

However, he conceded that many Australian companies had not met the pre-conditions for tendering for work, with reasons including a lack of experience or capacity.

To assist in preparing local firms to win work, Australia's Department of Industry, Innovation, Science, Research and Tertiary Education last year engaged economic advisory firm, Development Impacts, to undertake a project examining best practices by companies successfully supplying into the sector to determine how they meet the needs of project proponents.

Pia Turcinov, Development Impacts director, explained to Rigzone that it found there was more to the issue than obstacles such as a high Australian dollar, a lack of financial profile and Australia's skills shortage.

"They are huge hurdles for Australian companies, but there are other issues surrounding what the benchmarks are that local companies need to meet before they are considered… even in the tender stage," Turcinov, who also addressed the conference, said.

"Our work on this project identified 22 key factors companies need to focus on.

"Yes, price was a major factor, but other key factors were about quality, flexibility, design capabilities, QA systems, technical expertise, after sale service, and financial capabilities and risk profile.

"We looked at factors such as these and how the better performing companies compare and where they are outperforming against expectations."

Turcinov explained that suppliers needed to establish a clear capability beyond just a normal website and marketing brochure, and it was advisable for them to look at forming alliances with other local companies to build profile and capability.

In an election year, both at a federal and state level in WA, political parties in Australia have been prioritizing this issue.

WA's governing Liberal Party regularly produces an industry participation framework aimed at ensuring the local industry receives opportunity to participate in major resource projects.

The opposing Labor Party in WA has also shown its commitment by releasing a discussion paper outlining its openness to the issue.

At a federal level, the governing Labor Party is focusing on strengthening opportunities for the local industry through a proposed plan administering the issue.

Under the plan, major projects worth $519 million (AUD $500) million or more will be required to have an Australian industry participation plan identifying opportunities for local firms.

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

Local Participation Push for Major Australian Developments

Leaders of Australia's oil and gas industry are working together in an effort to develop methods towards increasing the amount of local content on major developments.

Locally based suppliers servicing the growing liquefied natural gas sector in Western Australia (WA) have expressed concern in recent years about being overlooked for development contracts.

Developers have cited the high Australian dollar, high labor costs and rising energy costs as reasons for opting to award contracts to competing foreign companies, often from Asia.

Despite these obstacles, developers have been urged to do more to increase local participation in projects.

Local suppliers are also being encouraged to develop a better understanding of the criteria to help them win contracts.

The issue was a key topic at the Australasian Oil & Gas Conference in Perth recently where industry groups, government representatives, and oil and gas companies discussed how more local participation could take place.

Paul Johnson, the Australian Government's Energy Resources Supplier Advocate, spoke at the conference and believes oil and gas developers need to take into account the capability and capacity of Australian suppliers if they want to boost the level of local content on their projects.

Johnson, who was appointed to this position in August of last year, said there was much good work happening in the sector to raise the capability of Australian firms to win work, but more could be done by both developers and suppliers.

"Project developers should take into account the limitations faced by Australian suppliers in undertaking large procurement packages, accessing the necessary finance and obtaining sufficient numbers of skilled workers," Johnson said.

"Small adjustments to the way projects are designed, engineered and procured can make a big difference to local suppliers.

"Early consideration of what can be done here should inform the design and engineering approach and basing some of the procurement team in Australia will lead to better engagement with local suppliers."

While major developers have been questioned for the amount of local content on their projects, Chevron reinforced its commitment to local suppliers through its conference presentation.

Colin Beckett, Chevron's general manager at the Gorgon LNG development, explained that the project had so far awarded $18.7 billion (AUD $18 billion) in contracts to local suppliers and created 9.000 jobs in the country.

However, he conceded that many Australian companies had not met the pre-conditions for tendering for work, with reasons including a lack of experience or capacity.

To assist in preparing local firms to win work, Australia's Department of Industry, Innovation, Science, Research and Tertiary Education last year engaged economic advisory firm, Development Impacts, to undertake a project examining best practices by companies successfully supplying into the sector to determine how they meet the needs of project proponents.

Pia Turcinov, Development Impacts director, explained to Rigzone that it found there was more to the issue than obstacles such as a high Australian dollar, a lack of financial profile and Australia's skills shortage.

"They are huge hurdles for Australian companies, but there are other issues surrounding what the benchmarks are that local companies need to meet before they are considered… even in the tender stage," Turcinov, who also addressed the conference, said.

"Our work on this project identified 22 key factors companies need to focus on.

"Yes, price was a major factor, but other key factors were about quality, flexibility, design capabilities, QA systems, technical expertise, after sale service, and financial capabilities and risk profile.

"We looked at factors such as these and how the better performing companies compare and where they are outperforming against expectations."

Turcinov explained that suppliers needed to establish a clear capability beyond just a normal website and marketing brochure, and it was advisable for them to look at forming alliances with other local companies to build profile and capability.

In an election year, both at a federal and state level in WA, political parties in Australia have been prioritizing this issue.

WA's governing Liberal Party regularly produces an industry participation framework aimed at ensuring the local industry receives opportunity to participate in major resource projects.

The opposing Labor Party in WA has also shown its commitment by releasing a discussion paper outlining its openness to the issue.

At a federal level, the governing Labor Party is focusing on strengthening opportunities for the local industry through a proposed plan administering the issue.

Under the plan, major projects worth $519 million (AUD $500) million or more will be required to have an Australian industry participation plan identifying opportunities for local firms.

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

Shell May Be Less Than 2 Years Away from Major China Shale Advancements

Royal Dutch Shell says it may be less than two years away from a major advance in shale gas production in China, bringing the Asian country closer to being the first outside of North America to cash in on technology that's transformed the U.S. energy industry.

Unlocking the gas trapped inside China's shale rock reserves, the world's biggest, would provide much needed energy supplies to the energy-hungry economy and help cut down on expensive imports of gas. It would also provide a windfall for western energy giants who provide the complex hydraulic fracturing technology.

Shell is on track to have spent $2 billion by the end of this year exploring the central province of Sichuan, and has drilled nearly 30 wells in joint-venture projects with China National Petroleum Corp.

"Mid-decade we will be able to decide" on the so-called final investment decision that will determine whether to go into full commercial production, said Maarten Wetselaar, who heads Shell's integrated gas operations worldwide excluding North America, and was speaking in an interview.

The multinational energy company is already producing tiny amounts of shale gas as part of its exploration work that it pumps into Sichuan's natural gas network. How quickly output can be ramped up after further investment isn't clear.

Beijing has set an ambitious target of producing 6.5 billion cubic meters of shale gas annually by 2015, and as much as 100 billion cubic meters by 2020, from nearly zero now. Getting the Shell project into operation will be critical in meeting those goals.

In the U.S., which pioneered the technology to extract gas and oil trapped in shale rock formations, gas production has soared, bringing down prices of fuel for manufacturing and chemical production. It has also raised the prospect of liquefied natural gas exports from North America of as much as 70 million tons a year within a decade, equivalent to deliveries from current world leader Qatar, Mr. Wetselaar said.

The U.S. Energy Information Administration has a preliminary estimate of some 36 trillion cubic meters of recoverable shale-gas resources in China, more than the U.S. and Canada combined, which if extracted could transform China's energy profile.

Those estimates have also sent rival Chevron Corp. into China searching for shale, while ConocoPhillips and Total SA are also planning exploration projects. Foreign companies are obliged to have local partners when exploring for shale in China.

China's government has not yet given a formal go-ahead to Shell's draft production-sharing pact with partner CNPC, but Mr. Wetselaar said he isn't worried.

"We will get the correct regime in place," he said. "I don't think it is lack of intent."

Other obstacles in China to successful exploitation include scarce supplies of water required to get the gas out of shale rock, and more complicated geology than in Canada and the U.S.

Still, "outside of North America, China is the most mature in terms of wells, in terms of activity on the ground," said Mr. Wetselaar.

But after China, next ready to produce commercial quantities for shale gas is likely to be Ukraine, where Shell is in the early stages of a drilling program, said Mr. Wetselaar.

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

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

Barnett Shale to Remain Major Contributor to US Gas Production

The Barnett shale play will continue to be a major contributor to U.S. natural gas production through 2030, despite a slow decline in production through 2030 and beyond, according to a new study from the University of Texas at Austin's Bureau of Economic Geology (BEG).

The study, which brought together the related research in engineering, geoscience and economics, examined on a well-by-well basis production data from over 16,000 individual wells in the Barnett play through mid-2011. The study results indicate significant recoverable resources remain in the Barnett play, with total recovery at greater than three times cumulative production to date.

The study's base case forecasts the Barnett, at a base price of $4 per thousand cubic feet of gas, will produce approximately 44 trillion cubic feet (Tcf) of gas through 2050 based on already drilled wells and well that will be drilled through 2030. In the base case, production will plateau from a current high of 2 Tcf per year and slowly decline to about 900 billion cubic feet per year by 2030.

The BEG team's calculations show 86 Tcf of technically recoverable free gas in 8,000 square miles that the play covers, of which 12 Tcf has been produced and 7 Tcf is proven. Of the 67 Tcf remaining, 45 Tcf is in drilled blocks and 22 Tcf is in undrilled acreage.

The 45 Tcf of technically recoverable free gas in 4,172 square miles of drilled areas exceeds the U.S. Energy Information Administration's July 2011 estimates of 23.81 Tcf for the 4,000 miles of active area. The 67 Tcf of remaining technically recoverable reserves across the full Barnett play also exceeds EIA's full estimate for the Barnett of 43.37 Tcf, which covered 6,500 square miles. It also exceeds the U.S. Geological Survey's 2003 assessment of 26 Tcf, which covered 5,000 square miles of the Barnett.

Other assessments of the Barnett have relied on aggregate views of average production, offering a "top down" view of production, said Scott Tinker, director of the BEG and co-principal investigator for the study, in a statement. Instead, the BEG study takes a "bottoms up" approach, starting with the production history of every well and then determining what areas remain to be drilled, which the study authors say creates a more accurate and comprehensive view of the basin.

The BEG team enhanced the view by identifying and assessing the potential in 10 production quality tiers and then using those tiers to more accurately forecast future production. The economic feasibility of production varies tremendously across the basin depending upon production quality tier.

The study's model centers around a base case of $4-gas, but it also allows for variations in price, volume drained by each well, economic limit of a well, advances in technology, gas plant processing incentives and many other factors to determine how much gas operators will be able to extract economically. This forecast falls in between some of the more optimistic and pessimistic predictions of production from the Barnett, the study authors noted.

While the BEG model shows the correlation between price and production, it suggests that price sensitivity is not overly dramatic, at least in the early phase of a formation's development.

"This is because there are still many locations to drill in the better rock, which is cost effective even at lower prices," Tinker commented.

While this drilling won't last forever, there are still a few more years of development remaining in the better rock quality areas.

The study was funded by the Alfred P. Sloan Foundation, a non-profit grant-making institution, and conducted a by team of 12 researchers from the University of Texas as well as Rice University. BEG will complete similar studies of the Marcellus, Haynesville and Fayetteville plays by year-end.

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

Barnett Shale to Remain Major Contributor to US Gas Production

The Barnett shale play will continue to be a major contributor to U.S. natural gas production through 2030, despite a slow decline in production through 2030 and beyond, according to a new study from the University of Texas at Austin's Bureau of Economic Geology (BEG).

The study, which brought together the related research in engineering, geoscience and economics, examined on a well-by-well basis production data from over 16,000 individual wells in the Barnett play through mid-2011. The study results indicate significant recoverable resources remain in the Barnett play, with total recovery at greater than three times cumulative production to date.

The study's base case forecasts the Barnett, at a base price of $4 per thousand cubic feet of gas, will produce approximately 44 trillion cubic feet (Tcf) of gas through 2050 based on already drilled wells and well that will be drilled through 2030. In the base case, production will plateau from a current high of 2 Tcf per year and slowly decline to about 900 billion cubic feet per year by 2030.

The BEG team's calculations show 86 Tcf of technically recoverable free gas in 8,000 square miles that the play covers, of which 12 Tcf has been produced and 7 Tcf is proven. Of the 67 Tcf remaining, 45 Tcf is in drilled blocks and 22 Tcf is in undrilled acreage.

The 45 Tcf of technically recoverable free gas in 4,172 square miles of drilled areas exceeds the U.S. Energy Information Administration's July 2011 estimates of 23.81 Tcf for the 4,000 miles of active area. The 67 Tcf of remaining technically recoverable reserves across the full Barnett play also exceeds EIA's full estimate for the Barnett of 43.37 Tcf, which covered 6,500 square miles. It also exceeds the U.S. Geological Survey's 2003 assessment of 26 Tcf, which covered 5,000 square miles of the Barnett.

Other assessments of the Barnett have relied on aggregate views of average production, offering a "top down" view of production, said Scott Tinker, director of the BEG and co-principal investigator for the study, in a statement. Instead, the BEG study takes a "bottoms up" approach, starting with the production history of every well and then determining what areas remain to be drilled, which the study authors say creates a more accurate and comprehensive view of the basin.

The BEG team enhanced the view by identifying and assessing the potential in 10 production quality tiers and then using those tiers to more accurately forecast future production. The economic feasibility of production varies tremendously across the basin depending upon production quality tier.

The study's model centers around a base case of $4-gas, but it also allows for variations in price, volume drained by each well, economic limit of a well, advances in technology, gas plant processing incentives and many other factors to determine how much gas operators will be able to extract economically. This forecast falls in between some of the more optimistic and pessimistic predictions of production from the Barnett, the study authors noted.

While the BEG model shows the correlation between price and production, it suggests that price sensitivity is not overly dramatic, at least in the early phase of a formation's development.

"This is because there are still many locations to drill in the better rock, which is cost effective even at lower prices," Tinker commented.

While this drilling won't last forever, there are still a few more years of development remaining in the better rock quality areas.

The study was funded by the Alfred P. Sloan Foundation, a non-profit grant-making institution, and conducted a by team of 12 researchers from the University of Texas as well as Rice University. BEG will complete similar studies of the Marcellus, Haynesville and Fayetteville plays by year-end.

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

Aker Wins Major Subsea Deal with Statoil

Norwegian oilfield services firm Aker Solutions reported Wednesday that it has been awarded a "major" frame agreement with Statoil to deliver subsea operation and services on the Norwegian continental shelf. The deal will see the expansion of Aker's Aagotnes facility on the west coast of Norway.

Aker said that it had booked some $1 billion of orders as a preliminary estimate of the work to be generated in the initial five-year period of the agreement, which has three additional three-year options for extension.

The subsea operations and services covered by the agreement include: subsea equipment, maintenance, upgrade and recertification of tools and installed equipment. The agreement includes workover activities and life extension of subsea wells.

"Aker Solutions has worked with Statoil for decades and we are very honoured by this major award. We are not only refurbishing subsea trees to guarantee an extended lifetime, but we are also upgrading to accommodate more functionality, enabling Statoil to increase production capacity from each well," said Alan Brunnen, head of Aker Solutions' subsea business division.

Aker Solutions' facility at Aagotnes, near Bergen on the west coast of Norway, will support the Statoil projects. As a result of the frame agreement, Aker expects to further develop its service base at the facility in 2013 and 2014 with new workshops, increased logistics capability and a new office block.

Aagotnes currently employs approximately 800 people.

The agreement will see Statoil immediately execute a subsea refurbishment project to be performed by Aker on the Troll field, located in the northern part of the North Sea approximately 40 miles west of Kollsnes in Norway.

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

Aker Wins Major Subsea Deal with Statoil

Norwegian oilfield services firm Aker Solutions reported Wednesday that it has been awarded a "major" frame agreement with Statoil to deliver subsea operation and services on the Norwegian continental shelf. The deal will see the expansion of Aker's Aagotnes facility on the west coast of Norway.

Aker said that it had booked some $1 billion of orders as a preliminary estimate of the work to be generated in the initial five-year period of the agreement, which has three additional three-year options for extension.

The subsea operations and services covered by the agreement include: subsea equipment, maintenance, upgrade and recertification of tools and installed equipment. The agreement includes workover activities and life extension of subsea wells.

"Aker Solutions has worked with Statoil for decades and we are very honoured by this major award. We are not only refurbishing subsea trees to guarantee an extended lifetime, but we are also upgrading to accommodate more functionality, enabling Statoil to increase production capacity from each well," said Alan Brunnen, head of Aker Solutions' subsea business division.

Aker Solutions' facility at Aagotnes, near Bergen on the west coast of Norway, will support the Statoil projects. As a result of the frame agreement, Aker expects to further develop its service base at the facility in 2013 and 2014 with new workshops, increased logistics capability and a new office block.

Aagotnes currently employs approximately 800 people.

The agreement will see Statoil immediately execute a subsea refurbishment project to be performed by Aker on the Troll field, located in the northern part of the North Sea approximately 40 miles west of Kollsnes in Norway.

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

Aker Wins Major Subsea Deal with Statoil

Norwegian oilfield services firm Aker Solutions reported Wednesday that it has been awarded a "major" frame agreement with Statoil to deliver subsea operation and services on the Norwegian continental shelf. The deal will see the expansion of Aker's Aagotnes facility on the west coast of Norway.

Aker said that it had booked some $1 billion of orders as a preliminary estimate of the work to be generated in the initial five-year period of the agreement, which has three additional three-year options for extension.

The subsea operations and services covered by the agreement include: subsea equipment, maintenance, upgrade and recertification of tools and installed equipment. The agreement includes workover activities and life extension of subsea wells.

"Aker Solutions has worked with Statoil for decades and we are very honoured by this major award. We are not only refurbishing subsea trees to guarantee an extended lifetime, but we are also upgrading to accommodate more functionality, enabling Statoil to increase production capacity from each well," said Alan Brunnen, head of Aker Solutions' subsea business division.

Aker Solutions' facility at Aagotnes, near Bergen on the west coast of Norway, will support the Statoil projects. As a result of the frame agreement, Aker expects to further develop its service base at the facility in 2013 and 2014 with new workshops, increased logistics capability and a new office block.

Aagotnes currently employs approximately 800 people.

The agreement will see Statoil immediately execute a subsea refurbishment project to be performed by Aker on the Troll field, located in the northern part of the North Sea approximately 40 miles west of Kollsnes in Norway.

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

Expiry of NY Fracking Regulations Not Major Setback for Industry

Regulations proposed in September 2011 to govern hydraulic fracturing in New York State will expire Feb. 27, but contrary to media reports, this does not mean that the ban on hydraulic fracturing will be extended another year, said an attorney who represents oil and gas company interests in New York State.

Regulations proposed in 2011 would have implemented recommendations of the draft Supplemental Generic Environmental Impact Statement (SGEIS). New York Gov. Andrew Cuomo decided he wanted to implement hydraulic fracturing regulations based on recommendations made in the draft SGEIS because that's what environmentalists wanted, said Thomas S. West, founder and managing partner with The West Firm, an upstate New York-based law firm.

The regulations introduced in September 2011 faced adverse commentary from the oil and gas industry, who found the regulations poorly drafted, duplicative and unnecessarily stringent without any flexibility, West told Rigzone in an interview.

Under the state's administrative procedure act, the proposed regulations introduced in 2011 had to be finished within one year of the dated last hearing. A 90-day extension was granted for the regulations in November 2012, but no additional extensions are available, meaning that the proposed regulations will lapse at the end of this month.

While the rulemaking process will have to start over once the regulations expire, it doesn't affect the SGEIS, and a new rulemaking process could be proposed at any time, West noted.

New York Department of Health Commission Dr. Nirav R. Shah announced Feb. 12 that he would need a few more weeks to finish his health review on the impacts of hydraulic fracturing in New York in order to meet with the U.S. Environmental Protection Agency and those at the University of Pennsylvania and Geisinger Health Systems who are conducting studies on high volume hydraulic fracturing. Shah will then present his finding to Department of Environmental Conservation Commissioner Joe Martens.

Martens said in a statement that if Shah determines the SGEIS to have adequately addressed health concerns, and is adopted by Martens on that basis, then DEC can accept and process high volume hydraulic fracturing permit applications 10 days after the issuance of the SGEIS.

While the expiry of the regulations will delay the process further, it's not a significant setback because once the SGEIS is finalized, the DEC can process and issue permits.

“Whether permits will be issued before new regulations are proposed and finalized remains an open issue,” West said. "Theoretically, they could finish a new rulemaking before they could issue the permits because it will take 6 to 9 months for the first permits to be issued under the complex requirements recommended in the SGEIS."

From the industry's perspective, the lapsing of the proposed regulations is a good thing. While there some improvements in the regulations, they were still inflexible.

"We look forward to Dr. Shah's report, which will pave the way for the DEC to issue the SGEIS and begin processing permits as early as next month," West commented.

It is unlikely that drilling will take place before early next year, given that it will take six to nine months for the first permit applications to get through the process, West said.

"Once the first group of applications has been processed, we expect that the process will get more streamlined and could take as little as two to three months, assuming that resource surveys have been conducted."

Operators such as Chesapeake Energy have acquired acreage in New York State with plans to drill in the Marcellus shale play. The play, which has transformed the economic landscape of Pennsylvania, also extends across the border into southern New York.

However, environmental groups and other groups opposed to hydraulic fracturing, including Yoko Ono, have sought to block hydraulic fracturing in the state, citing concerns over hydraulic fracturing's impact on local water supplies and the environment.

New York Gov. Andrew Cuomo refuted a suggestion Wednesday that his administration was playing politics in further delaying a decision on hydraulic fracturing, saying the issue is "too important to make a mistake," according to an Associated Press report.

"For more than four years, the state has kept the Southern Tier waiting for an answer to the economic struggles that have caused people to leave, family farms to go under and small businesses to go bankrupt," said Karen Moreau, executive director for the New York State Petroleum Council, a division of the American Petroleum Institute, in a statement.

However, "Given the DEC Commission's assurances that this delay will not mean delays for issuing permits, we respect the administration's needs to finish this last study and finally come to a resolution," Moreau commented. "We also know that it can and must end with a decision to move forward with creating jobs in the Southern Tier."

In 2011, the U.S. Geological Survey (USGS) estimated the Marcellus shale gas to contain approximately 84 trillion cubic feet of undiscovered, technically recoverable natural gas and 3.4 billion barrels of undiscovered, technically recoverable natural gas liquids. The USGS Marcellus assessment covered parts of Pennsylvania, New York, West Virginia, Ohio, Kentucky, Maryland and Tennessee.

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

Expiry of NY Fracking Regulations Not Major Setback for Industry

Regulations proposed in September 2011 to govern hydraulic fracturing in New York State will expire Feb. 27, but contrary to media reports, this does not mean that the ban on hydraulic fracturing will be extended another year, said an attorney who represents oil and gas company interests in New York State.

Regulations proposed in 2011 would have implemented recommendations of the draft Supplemental Generic Environmental Impact Statement (SGEIS). New York Gov. Andrew Cuomo decided he wanted to implement hydraulic fracturing regulations based on recommendations made in the draft SGEIS because that's what environmentalists wanted, said Thomas S. West, founder and managing partner with The West Firm, an upstate New York-based law firm.

The regulations introduced in September 2011 faced adverse commentary from the oil and gas industry, who found the regulations poorly drafted, duplicative and unnecessarily stringent without any flexibility, West told Rigzone in an interview.

Under the state's administrative procedure act, the proposed regulations introduced in 2011 had to be finished within one year of the dated last hearing. A 90-day extension was granted for the regulations in November 2012, but no additional extensions are available, meaning that the proposed regulations will lapse at the end of this month.

While the rulemaking process will have to start over once the regulations expire, it doesn't affect the SGEIS, and a new rulemaking process could be proposed at any time, West noted.

New York Department of Health Commission Dr. Nirav R. Shah announced Feb. 12 that he would need a few more weeks to finish his health review on the impacts of hydraulic fracturing in New York in order to meet with the U.S. Environmental Protection Agency and those at the University of Pennsylvania and Geisinger Health Systems who are conducting studies on high volume hydraulic fracturing. Shah will then present his finding to Department of Environmental Conservation Commissioner Joe Martens.

Martens said in a statement that if Shah determines the SGEIS to have adequately addressed health concerns, and is adopted by Martens on that basis, then DEC can accept and process high volume hydraulic fracturing permit applications 10 days after the issuance of the SGEIS.

While the expiry of the regulations will delay the process further, it's not a significant setback because once the SGEIS is finalized, the DEC can process and issue permits.

“Whether permits will be issued before new regulations are proposed and finalized remains an open issue,” West said. "Theoretically, they could finish a new rulemaking before they could issue the permits because it will take 6 to 9 months for the first permits to be issued under the complex requirements recommended in the SGEIS."

From the industry's perspective, the lapsing of the proposed regulations is a good thing. While there some improvements in the regulations, they were still inflexible.

"We look forward to Dr. Shah's report, which will pave the way for the DEC to issue the SGEIS and begin processing permits as early as next month," West commented.

It is unlikely that drilling will take place before early next year, given that it will take six to nine months for the first permit applications to get through the process, West said.

"Once the first group of applications has been processed, we expect that the process will get more streamlined and could take as little as two to three months, assuming that resource surveys have been conducted."

Operators such as Chesapeake Energy have acquired acreage in New York State with plans to drill in the Marcellus shale play. The play, which has transformed the economic landscape of Pennsylvania, also extends across the border into southern New York.

However, environmental groups and other groups opposed to hydraulic fracturing, including Yoko Ono, have sought to block hydraulic fracturing in the state, citing concerns over hydraulic fracturing's impact on local water supplies and the environment.

New York Gov. Andrew Cuomo refuted a suggestion Wednesday that his administration was playing politics in further delaying a decision on hydraulic fracturing, saying the issue is "too important to make a mistake," according to an Associated Press report.

"For more than four years, the state has kept the Southern Tier waiting for an answer to the economic struggles that have caused people to leave, family farms to go under and small businesses to go bankrupt," said Karen Moreau, executive director for the New York State Petroleum Council, a division of the American Petroleum Institute, in a statement.

However, "Given the DEC Commission's assurances that this delay will not mean delays for issuing permits, we respect the administration's needs to finish this last study and finally come to a resolution," Moreau commented. "We also know that it can and must end with a decision to move forward with creating jobs in the Southern Tier."

In 2011, the U.S. Geological Survey (USGS) estimated the Marcellus shale gas to contain approximately 84 trillion cubic feet of undiscovered, technically recoverable natural gas and 3.4 billion barrels of undiscovered, technically recoverable natural gas liquids. The USGS Marcellus assessment covered parts of Pennsylvania, New York, West Virginia, Ohio, Kentucky, Maryland and Tennessee.

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

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Expiry of NY Fracking Regulations Not Major Setback for Industry

Regulations proposed in September 2011 to govern hydraulic fracturing in New York State will expire Feb. 27, but contrary to media reports, this does not mean that the ban on hydraulic fracturing will be extended another year, said an attorney who represents oil and gas company interests in New York State.

Regulations proposed in 2011 would have implemented recommendations of the draft Supplemental Generic Environmental Impact Statement (SGEIS). New York Gov. Andrew Cuomo decided he wanted to implement hydraulic fracturing regulations based on recommendations made in the draft SGEIS because that's what environmentalists wanted, said Thomas S. West, founder and managing partner with The West Firm, an upstate New York-based law firm.

The regulations introduced in September 2011 faced adverse commentary from the oil and gas industry, who found the regulations poorly drafted, duplicative and unnecessarily stringent without any flexibility, West told Rigzone in an interview.

Under the state's administrative procedure act, the proposed regulations introduced in 2011 had to be finished within one year of the dated last hearing. A 90-day extension was granted for the regulations in November 2012, but no additional extensions are available, meaning that the proposed regulations will lapse at the end of this month.

While the rulemaking process will have to start over once the regulations expire, it doesn't affect the SGEIS, and a new rulemaking process could be proposed at any time, West noted.

New York Department of Health Commission Dr. Nirav R. Shah announced Feb. 12 that he would need a few more weeks to finish his health review on the impacts of hydraulic fracturing in New York in order to meet with the U.S. Environmental Protection Agency and those at the University of Pennsylvania and Geisinger Health Systems who are conducting studies on high volume hydraulic fracturing. Shah will then present his finding to Department of Environmental Conservation Commissioner Joe Martens.

Martens said in a statement that if Shah determines the SGEIS to have adequately addressed health concerns, and is adopted by Martens on that basis, then DEC can accept and process high volume hydraulic fracturing permit applications 10 days after the issuance of the SGEIS.

While the expiry of the regulations will delay the process further, it's not a significant setback because once the SGEIS is finalized, the DEC can process and issue permits.

“Whether permits will be issued before new regulations are proposed and finalized remains an open issue,” West said. "Theoretically, they could finish a new rulemaking before they could issue the permits because it will take 6 to 9 months for the first permits to be issued under the complex requirements recommended in the SGEIS."

From the industry's perspective, the lapsing of the proposed regulations is a good thing. While there some improvements in the regulations, they were still inflexible.

"We look forward to Dr. Shah's report, which will pave the way for the DEC to issue the SGEIS and begin processing permits as early as next month," West commented.

It is unlikely that drilling will take place before early next year, given that it will take six to nine months for the first permit applications to get through the process, West said.

"Once the first group of applications has been processed, we expect that the process will get more streamlined and could take as little as two to three months, assuming that resource surveys have been conducted."

Operators such as Chesapeake Energy have acquired acreage in New York State with plans to drill in the Marcellus shale play. The play, which has transformed the economic landscape of Pennsylvania, also extends across the border into southern New York.

However, environmental groups and other groups opposed to hydraulic fracturing, including Yoko Ono, have sought to block hydraulic fracturing in the state, citing concerns over hydraulic fracturing's impact on local water supplies and the environment.

New York Gov. Andrew Cuomo refuted a suggestion Wednesday that his administration was playing politics in further delaying a decision on hydraulic fracturing, saying the issue is "too important to make a mistake," according to an Associated Press report.

"For more than four years, the state has kept the Southern Tier waiting for an answer to the economic struggles that have caused people to leave, family farms to go under and small businesses to go bankrupt," said Karen Moreau, executive director for the New York State Petroleum Council, a division of the American Petroleum Institute, in a statement.

However, "Given the DEC Commission's assurances that this delay will not mean delays for issuing permits, we respect the administration's needs to finish this last study and finally come to a resolution," Moreau commented. "We also know that it can and must end with a decision to move forward with creating jobs in the Southern Tier."

In 2011, the U.S. Geological Survey (USGS) estimated the Marcellus shale gas to contain approximately 84 trillion cubic feet of undiscovered, technically recoverable natural gas and 3.4 billion barrels of undiscovered, technically recoverable natural gas liquids. The USGS Marcellus assessment covered parts of Pennsylvania, New York, West Virginia, Ohio, Kentucky, Maryland and Tennessee.

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

US scientists’ consensus – Climate change is already having major effects on ecosystems and species

http://www.wildlifeextra.com/

Emerging consensus shows climate change is already having major effects on ecosystems and species

December 2012. Plant and animal species are shifting their geographic ranges and the timing of their life events – such as flowering, laying eggs or migrating – at faster rates than researchers documented just a few years ago, according to a technical report on biodiversity and ecosystems used as scientific input for the 2013 Third National Climate Assessment.

The report, Impacts of Climate Change on Biodiversity, Ecosystems, and Ecosystem Services, synthesizes the scientific understanding of the way climate change is affecting ecosystems, ecosystem services and the diversity of species, as well as what strategies might be used by natural resource practitioners to decrease current and future risks. More than 60 US federal, academic and other scientists, including the lead authors from the U.S. Geological Survey, the National Wildlife Federation and Arizona State University in Tempe, authored the assessment.

Wide-ranging change to ecosystems
"These geographic range and timing changes are causing cascading effects that extend through ecosystems, bringing together species that haven't previously interacted and creating mismatches between animals and their food sources," said Nancy Grimm, a scientist at ASU and a lead author of the report.

Other key findings of the report include:

Changes in precipitation and extreme weather events can overwhelm the ability of natural systems to reduce or prevent harm to people from these events. For example, more frequent heavy rainfall events increase the movement of nutrients and pollutants to downstream ecosystems, likely resulting not only in ecosystem change, but also in adverse changes in the quality of drinking water and a greater risk of waterborne-disease outbreaks. Changes in winter have big and surprising effects on ecosystems and their services. Changes in soil freezing, snow cover and air temperature affect the ability of ecosystems to store carbon, which, in turn, influences agricultural and forest production. Seasonally snow-covered regions are especially susceptible to climate change because small precipitation or temperature shifts can cause large ecosystem changes. Longer growing seasons and warmer winters are already increasing the likelihood of pest outbreaks, leading to tree mortality and more intense, extensive fires. Decreased or unreliable snowfall for winter sports and recreation will likely cause high future economic losses. The ecosystem services provided by coastal habitats are especially vulnerable to sea-level rise and more severe storms. The Atlantic and Gulf of Mexico coasts are most vulnerable to the loss of coastal protection services provided by wetlands and coral reefs. Along the Pacific coast, long-term dune erosion caused by increasing wave heights is projected to cause problems for communities and for recreational beach activities. However, other kinds of recreation will probably improve due to better weather, with the net effect being that visitors and tourism dollars will shift away from some communities in favour of others. Climate change adaptation strategies are vital for the conservation of diverse species and effective natural resource policy and management. As more adaptive management approaches are developed, resource managers can enhance the country's ability to respond to the impacts of climate change through forward-looking and climate science-informed goals and actions. Ecological monitoring needs to be improved and better coordinated among federal and state agencies to ensure the impacts of climate change are adequately monitored and to support ecological research, management, assessment and policy. Existing tracking networks in the United States will need to improve coverage through time and in geographic area to detect and track climate-induced shifts in ecosystems and species.

Read more at http://www.wildlifeextra.com/go/news/us-warming.html#cr

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Colorado mountains face major snow storm, Denver could see snow Tuesday

Font ResizeBy Joey Bunch
The Denver Postdenverpost.comPosted: 12/16/2012 03:21:47 PM MSTDecember 16, 2012 10:30 PM GMTUpdated: 12/16/2012 03:30:33 PM MST

The Colorado high country could see new snowfall measured in feet by midweek as a strong storm spins from the Pacific and cold from the Arctic moves into the state. Snow is in Denver's forecast on Tuesday and Wednesday.

The National Weather Service in Grand Junction said Sunday afternoon that northwest Colorado could get up to 10 inches by Monday night, another foot by Tuesday night, with heavy snow continuing to fall on Wednesday.

Wind gusts up to 25 mph — and up to 60 mph over ridges and along eastern mountain slopes — could create blinding driving conditions through the region as well. The same region saw more than a foot of snow a little over a week earlier.

Summit County and the Front Range mountains are expected to get up to 6 inches Monday

As of Sunday, the National Weather Service had not sized up the Denver metro area's potential accumulation, but put the city's chances of snow at 30 percent on Tuesday night and 50 percent on Wednesday with blustery conditions.

Temperatures in Denver on Monday, however, are expected to be above average with a high temperature of 52 degrees. The average for the date is 44 degrees.

A cold front is expected to drop in from the north and push nighttime temperatures below zero in western Colorado. Denver is expected to top out at 28 on Wednesday and 35 on Thursday, with lows each night in the teens. Sunny skies and seasonal temperatures will return on Friday, forecasters said. The freshly powdered mountains should warm into the 30s for the weekend before Christmas.

While a reliable forecast for Christmas Day was not yet available on Sunday, the National Weather Service noted that a White Christmas in Denver is unusual.

An inch of snow has been on the ground on Christmas Day just 42 of the last 112 years. Snow has fallen on Christmas Day in the city just six of the last 30 years, according to weather records.

That improved the state's snowpack to 41 percent of its 30-year average on Nov. 29 to 46 percent last Wednesday, with improvement from 37 percent to 52 percent during the same duration in northwest Colorado, according to the Natural Resources Conservation Service in Lakewood. The next winter storm should offer even more improvement.

Joey Bunch: 303-954-1174, jbunch

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