DNV Inks Contract for LLOG's Delta House FPS

Det Norske Veritas (DNV) will classify LLOG Exploration Company LLC's Delta House floating production platform, which is scheduled to begin production in the deepwater Gulf of Mexico in 2015.

The U.S. Coast Guard will accept plan review and inspection functions conducted by DNV for the project as part of the unit's certification under Title 33 Code of Federal Regulations. The acceptance follows from a general acceptance given by the U.S. Coast Guard in 2007, and will provide owners and operators of offshore floating units a new option for classification and certification work.

Until 2007, legislation stated that the American Bureau of Shipping (ABS) was the only company that could classify floaters in the Gulf of Mexico, a DNV spokesperson told Rigzone. U.S. Coast Guard and legislative requirements were changed that year, but uncertainty has existed in the market as to whether it would really be straightforward to use anyone else but ABS, a DNV spokesperson told Rigzone in an email statement.

"Owners have expressed a strong desire for choice of classification society's for floating offshore installations in American waters and we know there are many owners, designers, operators and yards who would prefer to work with DNV, and this contract is proof that they can do so, confident of legal and regulatory approval," said Kenneth Vareide, DNV's director of operations for maritime in North America, in a statement.

Besides the associated benefits of free choice and competition, DNV's extensive research and development efforts means the company can bring deep, often new knowledge and competence to challenges facing the industry, the spokesperson said. For example, the company was the first the comprehensively address the risks associated with all the systems and software that are critical for offshore units, and often a case of unexpected delay and downtime, when not properly addressed.

With local capabilities and expertise, DNV is a well-established alternative and experienced partner for classifying floaters and complex projects in the Gulf of Mexico.

"We now look forward to address the industry's needs and desires for increased safety, reliability, cutting edge technology and, of course, reduced downtime," Vareide commented. "We are confident that both owners and regulatory agencies will benefit from this."

The company will carry out approvals for classification and verification work, and surveys related to activities in the United States. DNV also is the certified verification agent (CVA) for the Bureau of Safety and Environmental Enforcement for the structure, mooring and riser, which will be handled from DNV's Houston office.

DNV has carried out extensive verification and independent analysis for many Gulf of Mexico floaters over the past 20 years, including many high profile failure and accident investigations. The company has a wide portfolio of CVA and development projects for the Gulf of Mexico oil and gas industry, including the first U.S. Gulf floating production, storage and offloading system at the Cascade and Chinook field.

The design basis agreement for Delta House, as approved by the Coast Guard, is based largely on DNV's offshore rules for a floating offshore installation.

LLOG Exploration and partners last December approved the Delta House project, which will include a floating production system (FPS), an oil export line, a natural gas export line and a number of subsea systems. Development costs for the project are estimated at over $2 billion.

The FPS, which will be located in Mississippi Canyon Block 254 in approximately 4,500 feet of water, will have production capacity of 80,000 barrels of oil per day (bopd) and 200 million cubic feet per day (MMcf/d) of gas, as well as peaking capability of up to 100,000 bopd and 240 MMcf/d. The facilities are expected to process and transport production from six initial wells when commercial operations begin.

The facility will be capable of accommodating production from nearby fields, including LLOG's previously announced discoveries in Mississippi Canyon Blocks 300 and 431. It will have space for 20 risers, which will allow production from up to nine simultaneously producing fields with dual flowlines.

The Delta House FPS will be constructed using Exmar Offshore Company's OPTI-11000 semisubmersible hull design at Hyundai Heavy Industries Ulsan, South Korea shipyard. Audubon Engineering will design and procure the topsides equipment.

Once construction is complete, the FPS hull will be transported by Dockwise to Kiewit Offshore Services yard in Ingleside, Texas. Kiewit will manufacture and integrate the topsides with the hull. Intermoor will moor and install the FPS.

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

Dart Targets Several CBM Developments in the UK

Coal-bed methane (CBM) is one of a number of unconventional sources of natural gas that several countries around the world are currently exploring – particularly in the developed world where coal itself is being increasingly seen as too dirty a fuel to use and too expensive to mine from deep beneath the ground.

CBM (also known as coal seam gas) has become an important source of energy in the United States and a number of other countries. Australia, for example, has very rich deposits of CBM and its industry has expanded significantly since the beginning of this century.

Recently, a firm that has its roots in the Australian CBM industry successfully tested a CBM well in Scotland. Dart International Ltd. reported in late January that during a three-month production test at its Airth 12 well, on the PEDL 133 license, it achieved sustained gas flow rates in excess of 500,000 standard cubic feet per day and is now powering an electricity generator with the gas – making Dart the first company in Scotland to produce electricity from CBM.

In the UK, total CBM resource is estimated at 97 trillion cubic feet (2,900 billion cubic meters of gas), according to a 2004 British Geological Survey study. Although this study estimated that as little as 1 percent of this resource could be recovered – because of perceived widespread low seam permeability, low gas content, resource density and planning constraints – the UK's Department of Energy and Climate Change (DECC) points out that analogous CBM developments in the United States have been proven to achieve recovery of between 30 and 40 percent in some fields.

Consequently, DECC believes that if 10 percent of the UK's CBM resource potential could be developed it would correspond to more than three years of the country's natural gas supply.

CBM extraction exploits the fact that natural gas in a coal reservoir is stored differently to how it is stored in a conventional reservoir. Instead of occupying spaces as a free gas between sand grains, the methane is held to the surface of the coal by a process called adsorption. Large numbers of micropores in the coal mean a very large surface area that methane molecules can be attached to. Indeed, due to these micropores in its structure one pound of coal typically has the equivalent surface area of a few dozen football fields.

This means that an individual lump of coal can contain a very large amount of methane. Typically, companies looking to extract methane from a coal seam judge it economical if it contains in excess of 50 cubic feet of natural gas per ton of coal.

The gas in the coal is held in place by the pressure of surrounding water and rock, so simply by drilling through a coal seam this natural gas can be pumped out.

Dart is in a good position to exploit this potential in the UK since it has acquired 40-plus onshore licenses there that enable it to conduct unconventional gas projects, said Dart Chief Commercial Officer Eytan Uliel.

The company first developed its CBM expertise in Australia and has since honed the practice at projects in China and Indonesia.

"The well design for Scotland was first developed in Australia but it was perfected at one of our projects in China and has been adapted for the geological conditions you find in Scotland," Uliel explained to Rigzone in a recent interview.

"That's really the magic of CBM. People make a big song and dance about it being a technology-driven thing, but actually the technology is vanilla. It's nothing when you compare it to offshore conventional wells. The technology is very simple. You are drilling shallow holes, you are intersecting coal mines, drilling a horizontal-section hole. It's not complicated by any means.

"The expertise you need is what you might call the diagnostic tool kit. The ability to take a particular coal system in a particular place and then figure out the right well design, the right completion architecture and then the right surface solution that creates a viable economic project."

In the immediate future, Dart is focused on its Airth development in Scotland. Rather than embark on a rapid rollout of CBM in the UK, Dart prefers to take a "slow but steady" approach.

"The lesson learnt in Australia and the lesson to be applied here is that people want to see a result and everyone is skeptical. And for good reason," said Uliel.

"A lot of [companies] have tried and a lot have failed, so the focus of this company is very much to get a project up and running, and prove to people it can be done both commercially but also viable in a community sense. You are working with local communities. People need to see that you are responsible and you create jobs and you don't damage the environment. So, we do one project and we do it well."

The Airth project was previously a joint venture between Composite Energy (since acquired by Dart) and BG Group plc. Although the companies drilled a few exploration wells, proved gas was there and it flowed, it has taken Dart's involvement to make the project it work.

"They hadn't quite figured out how to flow it sustainably, and how to maximize the production, and they hadn't quite come up with the right development plan for that license," Uliel said.

While, vertical drilling into a coal seam can – and has – yielded commercial gas at certain projects in the United States, it is horizontal drilling that has made CBM a viable source of gas in Australia and elsewhere.

"In Australia, we adapted horizontal drilling technology to CBM. So what we did was, instead of drilling a simple vertical well, what we would do was drill a vertical and then off that vertical we would drill a very long horizontal well in the coal seam. And what that does is it effectively creates a channel along which the gas can flow back to the vertical and then out to the surface.

"Now, if you've got a coal seam that's 10 meters thick and you drill a vertical well, you've got access to a 10-meter area of coal. But if you drill a horizontal well, you can drill them one, two or three thousand meters through the coal seam. And so from the same well, you are opening up a huge area of coal. You are draining a very large area and that's what made the industry work in Australia."

Uliel explained that this is what Composite and BG Group had been trying to do in Scotland.

"The problem was that the seams are so thin that even drilling one single lateral for a long way through a coal seam didn't give you enough gas volume to justify the economic cost of the well you are drilling," he said.

"So, what we've done, and this is the 'architecture' we've brought from Australia via China to Scotland, is instead of drilling one horizontal into the seam you drill four. So you have different coal seams at different depths and from the one vertical well you drill four horizontal sections.

"Each horizontal is about 2,000 meters so from the well you are accessing 8,000 meters of coal from four different seams. So there's a lot of know-how that sits with that, because the pressure at which the gas is held in each seam is different, the flow rates are different, the water rates you get are different and the knowledge you have about how to drill it and then how to operate that well."

Uliel continued explained that the production test that Dart undertook at the end of last year at Airth saw the firm take one of these wells in order to see how it would flow.

"We produced on a sustainable basis about half a million cubic feet of gas per day and we let it run for a short while and we got up to about 800,000 cubic feet. And that's a viable, economic, doable proposition," he said.

Dart expects to start selling the gas produced – up to 10 billion cubic feet per annum initial and perhaps double that over time – into the UK's national gas grid.

"There is a main trunk pipeline that runs to our license area that is owned and operated by Scottish and Southern Energy (SSE). And we have a gas sale contract agreed with them. So, as and when we we're ready to start delivering the gas, we will.

"The issue there is you need to compress [the gas] so it gets to the pressure that the pipeline can receive it. And so we're currently going through a process of planning and permitting so that we can put in the compressor facility and drill more wells. And once we've done that we'll be in a position to start delivering gas to SSE.

"In the meantime, for the early gas that we're generating from the first few wells we've drilled we have a small electricity generator on site and the gas goes into that. We manufacture electricity and we sell it into the electricity grid. So we're doing that already."

Dart is investing up to $150 million into the Airth project, and much of this will go into the local economy. The project will support between 40 and 50 local jobs as well.

Once the Airth project begins exporting gas to the grid, Dart will turn its focus onto the Canonbie project, located on onshore license PEDL 159, which straddles the England/Scotland border.

"It will be a very similar project in terms of scale, scope, size and profile to the one at PEDL 133," Uliel explained. "So there, we've done early exploration work. We've drilled some core holes. We need to know about the coal and the gas content and permeability. So the next thing we would need to do there, which is on our agenda for either this year or early next year, is to put down a couple of pilot wells and run a production test, and see how well the coal there will produce."

The Canonbie project could also produce between 10 and 20 billion cubic feet of gas per annum, according to Uliel, who pointed out that while such numbers represent a "drop in the bucket" in the context of the overall energy equation for the UK, they will also help the country reduce its dependence on imported gas.

"Every molecule of domestically-produced gas means a molecule less of Russian or Norwegian gas that needs to be purchased," he said.

"The UK is blessed with considerable shale gas resources and considerable coal-bed methane resources, and if they can be sensibly tapped over the next several years they will make a big difference to the energy dynamic here. That's for sure!"

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

Dart Targets Several CBM Developments in the UK

Coal-bed methane (CBM) is one of a number of unconventional sources of natural gas that several countries around the world are currently exploring – particularly in the developed world where coal itself is being increasingly seen as too dirty a fuel to use and too expensive to mine from deep beneath the ground.

CBM (also known as coal seam gas) has become an important source of energy in the United States and a number of other countries. Australia, for example, has very rich deposits of CBM and its industry has expanded significantly since the beginning of this century.

Recently, a firm that has its roots in the Australian CBM industry successfully tested a CBM well in Scotland. Dart International Ltd. reported in late January that during a three-month production test at its Airth 12 well, on the PEDL 133 license, it achieved sustained gas flow rates in excess of 500,000 standard cubic feet per day and is now powering an electricity generator with the gas – making Dart the first company in Scotland to produce electricity from CBM.

In the UK, total CBM resource is estimated at 97 trillion cubic feet (2,900 billion cubic meters of gas), according to a 2004 British Geological Survey study. Although this study estimated that as little as 1 percent of this resource could be recovered – because of perceived widespread low seam permeability, low gas content, resource density and planning constraints – the UK's Department of Energy and Climate Change (DECC) points out that analogous CBM developments in the United States have been proven to achieve recovery of between 30 and 40 percent in some fields.

Consequently, DECC believes that if 10 percent of the UK's CBM resource potential could be developed it would correspond to more than three years of the country's natural gas supply.

CBM extraction exploits the fact that natural gas in a coal reservoir is stored differently to how it is stored in a conventional reservoir. Instead of occupying spaces as a free gas between sand grains, the methane is held to the surface of the coal by a process called adsorption. Large numbers of micropores in the coal mean a very large surface area that methane molecules can be attached to. Indeed, due to these micropores in its structure one pound of coal typically has the equivalent surface area of a few dozen football fields.

This means that an individual lump of coal can contain a very large amount of methane. Typically, companies looking to extract methane from a coal seam judge it economical if it contains in excess of 50 cubic feet of natural gas per ton of coal.

The gas in the coal is held in place by the pressure of surrounding water and rock, so simply by drilling through a coal seam this natural gas can be pumped out.

Dart is in a good position to exploit this potential in the UK since it has acquired 40-plus onshore licenses there that enable it to conduct unconventional gas projects, said Dart Chief Commercial Officer Eytan Uliel.

The company first developed its CBM expertise in Australia and has since honed the practice at projects in China and Indonesia.

"The well design for Scotland was first developed in Australia but it was perfected at one of our projects in China and has been adapted for the geological conditions you find in Scotland," Uliel explained to Rigzone in a recent interview.

"That's really the magic of CBM. People make a big song and dance about it being a technology-driven thing, but actually the technology is vanilla. It's nothing when you compare it to offshore conventional wells. The technology is very simple. You are drilling shallow holes, you are intersecting coal mines, drilling a horizontal-section hole. It's not complicated by any means.

"The expertise you need is what you might call the diagnostic tool kit. The ability to take a particular coal system in a particular place and then figure out the right well design, the right completion architecture and then the right surface solution that creates a viable economic project."

In the immediate future, Dart is focused on its Airth development in Scotland. Rather than embark on a rapid rollout of CBM in the UK, Dart prefers to take a "slow but steady" approach.

"The lesson learnt in Australia and the lesson to be applied here is that people want to see a result and everyone is skeptical. And for good reason," said Uliel.

"A lot of [companies] have tried and a lot have failed, so the focus of this company is very much to get a project up and running, and prove to people it can be done both commercially but also viable in a community sense. You are working with local communities. People need to see that you are responsible and you create jobs and you don't damage the environment. So, we do one project and we do it well."

The Airth project was previously a joint venture between Composite Energy (since acquired by Dart) and BG Group plc. Although the companies drilled a few exploration wells, proved gas was there and it flowed, it has taken Dart's involvement to make the project it work.

"They hadn't quite figured out how to flow it sustainably, and how to maximize the production, and they hadn't quite come up with the right development plan for that license," Uliel said.

While, vertical drilling into a coal seam can – and has – yielded commercial gas at certain projects in the United States, it is horizontal drilling that has made CBM a viable source of gas in Australia and elsewhere.

"In Australia, we adapted horizontal drilling technology to CBM. So what we did was, instead of drilling a simple vertical well, what we would do was drill a vertical and then off that vertical we would drill a very long horizontal well in the coal seam. And what that does is it effectively creates a channel along which the gas can flow back to the vertical and then out to the surface.

"Now, if you've got a coal seam that's 10 meters thick and you drill a vertical well, you've got access to a 10-meter area of coal. But if you drill a horizontal well, you can drill them one, two or three thousand meters through the coal seam. And so from the same well, you are opening up a huge area of coal. You are draining a very large area and that's what made the industry work in Australia."

Uliel explained that this is what Composite and BG Group had been trying to do in Scotland.

"The problem was that the seams are so thin that even drilling one single lateral for a long way through a coal seam didn't give you enough gas volume to justify the economic cost of the well you are drilling," he said.

"So, what we've done, and this is the 'architecture' we've brought from Australia via China to Scotland, is instead of drilling one horizontal into the seam you drill four. So you have different coal seams at different depths and from the one vertical well you drill four horizontal sections.

"Each horizontal is about 2,000 meters so from the well you are accessing 8,000 meters of coal from four different seams. So there's a lot of know-how that sits with that, because the pressure at which the gas is held in each seam is different, the flow rates are different, the water rates you get are different and the knowledge you have about how to drill it and then how to operate that well."

Uliel continued explained that the production test that Dart undertook at the end of last year at Airth saw the firm take one of these wells in order to see how it would flow.

"We produced on a sustainable basis about half a million cubic feet of gas per day and we let it run for a short while and we got up to about 800,000 cubic feet. And that's a viable, economic, doable proposition," he said.

Dart expects to start selling the gas produced – up to 10 billion cubic feet per annum initial and perhaps double that over time – into the UK's national gas grid.

"There is a main trunk pipeline that runs to our license area that is owned and operated by Scottish and Southern Energy (SSE). And we have a gas sale contract agreed with them. So, as and when we we're ready to start delivering the gas, we will.

"The issue there is you need to compress [the gas] so it gets to the pressure that the pipeline can receive it. And so we're currently going through a process of planning and permitting so that we can put in the compressor facility and drill more wells. And once we've done that we'll be in a position to start delivering gas to SSE.

"In the meantime, for the early gas that we're generating from the first few wells we've drilled we have a small electricity generator on site and the gas goes into that. We manufacture electricity and we sell it into the electricity grid. So we're doing that already."

Dart is investing up to $150 million into the Airth project, and much of this will go into the local economy. The project will support between 40 and 50 local jobs as well.

Once the Airth project begins exporting gas to the grid, Dart will turn its focus onto the Canonbie project, located on onshore license PEDL 159, which straddles the England/Scotland border.

"It will be a very similar project in terms of scale, scope, size and profile to the one at PEDL 133," Uliel explained. "So there, we've done early exploration work. We've drilled some core holes. We need to know about the coal and the gas content and permeability. So the next thing we would need to do there, which is on our agenda for either this year or early next year, is to put down a couple of pilot wells and run a production test, and see how well the coal there will produce."

The Canonbie project could also produce between 10 and 20 billion cubic feet of gas per annum, according to Uliel, who pointed out that while such numbers represent a "drop in the bucket" in the context of the overall energy equation for the UK, they will also help the country reduce its dependence on imported gas.

"Every molecule of domestically-produced gas means a molecule less of Russian or Norwegian gas that needs to be purchased," he said.

"The UK is blessed with considerable shale gas resources and considerable coal-bed methane resources, and if they can be sensibly tapped over the next several years they will make a big difference to the energy dynamic here. That's for sure!"

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

Musings: PwC Says Shale Oil 'The Next Energy Revolution' - Really?

Economists with the worldwide accounting firm of PricewaterhouseCoopers LLP (PwC) have just published an interesting and thought-provoking analysis of the long-term impact of shale oil on the global economy. While one might question some of the shale oil production numbers that evolve from the PwC analysis, the final couple of pages of the report, which focus on "opportunities and challenges for governments and companies" and touch on topics we have been devoting significant thought to with respect to the implications of the growth in output from unconventional oil and gas plays, is what we found most intriguing.

PwC begins its report with a brief review of the history to date of shale oil and shale gas in the United States. The economists point out that shale oil production has grown from 111,000 barrels per day (b/d) in 2004 to 553,000 b/d in 2011, or an annual growth rate of 26%, albeit starting from a very small base. We know shale oil production increased further in 2012. The oil production increase in North Dakota alone, where the Bakken tight oil formation dominates the output, rose by 233,805 b/d last year. Furthermore, the Energy Information Administration (EIA), in its supplemental information supporting its latest Short Term Energy Outlook (STEO), is calling for an increase in tight oil output between November 2012 and December 2014 of 1.13 million b/d, or nearly all of the projected total U.S. crude oil production increase during this period of 1.26 million b/d.

This optimistic outlook for tight oil production is driven both by the technical success producers are having in extracting the output and the high global price of oil. These two factors have contributed to the EIA estimating that the shale oil resources in this country have increased from 4 billion barrels in 2007 to 33 billion barrels in 2010, and we suspect the estimate will go higher when the next estimate is released. PwC says the EIA is estimating that U.S. shale oil production will grow at a much slower rate in the future than in the past, but it will reach 1.2 million b/d of output by 2035, or 12% of the nation's projected oil supply. They comment that this projection may be conservative given that other analysts are forecasting tight oil production to reach upwards of 3-4 million b/d by 2035. PwC believes that tight oil production will make the largest contribution to total U.S. oil supply growth by 2020, which would be consistent with the EIA's outlook in its latest STEO cited above. The implication of this forecast is that increased shale oil production will displace a significant volume of waterborne crude oil imports to the U.S., estimated to be potentially as much as a 35-40% decline.

In PwC's view, this scenario could lead to future oil prices being significantly lower than projected in current forecasts. Just how much lower the price might be becomes an interesting exercise in forecasting the global growth in shale oil production and the reaction of the leading conventional oil producers – primarily OPEC members. At the present time, the EIA estimates oil prices will reach $133 per barrel in real terms by 2035, which is a higher projected price than the International Energy Agency (IEA) forecasts, which is $127 per barrel.

PwC believes that global estimates of shale oil resources will be revised upwards significantly over time. That belief is based on the past pattern of shale oil and shale gas resource estimate changes in the United States. As a result, PwC believes that "global shale oil production has the potential to rise to up to 14 million barrels of oil per day by 2035," which would represent approximately 12% of global oil supply then. This production growth will have an impact on global oil prices according to PwC, depending on how OPEC members and Russia respond. PwC has developed two scenarios for predicting future oil prices – one that allows for OPEC to respond by lowering its output and the other with no OPEC response. In the former scenario, PwC sees the global oil price maintaining an average price of around $100 per barrel in real terms, while in the latter case it falls to $83 per barrel. Based on these two scenarios, PwC sees the potential for future global oil prices to be $33-50 per barrel lower than the EIA's reference case of $133 per barrel in 2035, in real terms. This reduced oil price is significant and raises numerous questions for governments and companies, while also creating significant opportunities and challenges.

By using the National Institute Global Econometric Model, PwC attempts to project the impact of its two price scenarios (a decline of $33 or $50 per barrel in real oil prices) on global economic activity. They conclude that at today's Gross Domestic Product (GDP) values, there could be "an increase in size of the global economy of around $1.7-2.7 trillion per annum. This could imply a rise by 2035 in average global GDP per person of between $230 and $370 per annum (at today's prices) relative to the EIA baseline case with minimal shale oil production." If the PwC price outlook proves correct, there will be a significant positive impact on future global economic activity and the wealth of various countries.

The economic model's results suggest that India and Japan could each see an increase in their GDP of between 4% and 7% by the end of the projection period. PwC sees other net oil importers such as the United States, China, Germany and the UK gaining between 2% and 5% in GDP over the period. On the other hand, OPEC member countries and Russia could experience deterioration in their current account balances due to the lower oil price. PwC points out, however, that the financial damage lower oil prices might cause for Russia could be offset if the country elects to exploit its large estimated shale oil resources. That would certainly favor ExxonMobil given its growing relationship with Russia's Rosneft Oil Company.

In the conclusion to its report, PwC briefly explores some of the implications growing global shale oil production will have on energy markets, energy companies and governments. It is the positive implications, on balance, from growing shale resource exploitation that gives us increased confidence that the long-term outlook for the United States will be positive, despite near-term domestic economic and political fears and growing concerns over the future geopolitical outlook. The magnitude of our optimism is likely to be shaded by the political, geopolitical and economic policies and actions of our leaders, but we don't doubt that the United States will reach the next decade in a surprisingly stronger relative position than most prognostications suggest today.

Given PwC's belief in the potential for significant oil shale production and resulting lower future oil prices, the firm's economists say that the financial case for renewables becomes relatively less attractive. There is little doubt about that reality, but the argument for developing renewable energy projects has rarely been about their financial viability, but rather about the social responsibility from building them. To the extent that government mandates for greater investment in renewable energy projects increases, then the nation's future economy could be somewhat smaller as energy capital could be misdirected into investments that are uneconomic and have a greater likelihood of being abandoned in the future much like the wind farms built during the 1980s in California.

Lower oil prices will also impact the pace of development of more expensive and less environmentally attractive oil supplies such as Arctic and oil sands resources. While these two resources currently are being attacked on environmental grounds, their vulnerability to low returns on capital investment may be what actually curtails their future development. Given this trend, oil companies will need to reassess their current portfolios against lower future oil prices. This reassessment may become a catalyst for accelerated merger and acquisition activity as large, integrated oil companies target undervalued, financially challenged smaller oil and gas companies possessing attractive resource holdings. The lower cost of capital and greater financial resources to withstand periods of increased commodity price volatility, coupled with greater R&D capabilities to reduce finding and development costs gives the large, integrated oil companies a significant competitive advantage.

Companies that are targeting offshore oil and gas developments exclusively may find a need to seek diversification of focus. That goes for both oil and gas producers and oilfield service companies. Here again, M&A activity may be the easiest and fastest way for single-purpose entities to become more broadly diversified. In the same vein, the governments of OPEC members and other net oil and gas exporters may need to reassess the impact on their budgets of reduced oil prices and possibly lower oil production. While there always remains the possibility that reduced oil prices will stimulate greater oil consumption in the future, the changing demographics of the global population and recent legislative initiatives to reduce energy consumption will bake into the future energy outlook a flattish energy demand growth profile.

The big winners in the PwC scenarios are those companies and industries that use oil and its by-products in their own output. Lower energy prices have already produced a resurgence of on-shoring previously exported businesses. Changing demographics in historically cheap labor markets such as China and Asia has led to U.S. manufacturing companies restarting domestic production of capital equipment and durable goods. Importantly, the belief in the potential of abundant natural gas supplies and thus cheap feedstock costs is leading to a revival of the domestic petrochemical industry and the emergence of a nascent liquefied natural gas exporting business. As it took decades for these companies to abandon the rapidly growing high-cost energy environment that characterized the U.S. during the latter part of the last century and the early years of the current one, manufacturers will not be quick to shift out of the U.S. at the first uptick in energy costs as they perceive that our nation has built a long-term global competitive cost advantage.

So while we rail against the destructive economic and political decisions being made in our seats of government today, we see an opportunity for the domestic GDP pie to be larger in the future; just how much larger will be determined by the decisions of politicians in the near-term. At some point in the distant future, we anticipate looking backwards and marveling at how resilient the U.S. economy proved to be and how it overcame the many dire predictions of its demise due to the idiotic political and economic actions of our rulers. We will probably wind up tipping our hat to the benefits created by the great American shale revolution begun by the son of Greek immigrant parents from Galveston, Texas – George Mitchell. While many people would call him a true entrepreneur, and he was/is, based on our encounters with him, we would say he was more like Nellie from South Pacific fame that Rodgers and Hammerstein deemed "A Cockeyed Optimist."

G. Allen Brooks works as the Managing Director at PPHB LP. Reprinted with permission of PPHB.

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

Fitch Unlikely to Alter Petrobras Credit Rating

RIO DE JANEIRO - Brazilian state-run energy giant Petrobras is borrowing heavily to develop massive new oil fields, but the investments should result in a cash surge that offsets any concerns about the recent rise in the company's debt levels, said Ana Paula Ares, senior director of corporate finance at Fitch Ratings.

Petrobras's finances have come under increasing scrutiny after a series of billion-dollar losses in the company's refining unit, which has been hurt by subsidized imports of gasoline and diesel fuel. The company sells the expensive imported fuels at a loss in the domestic market because of government reluctance to raise fuel prices for fear of stoking inflation.

The losses have undermined Petrobras's earnings and called into question the company's ability to carry out ambitious plans to spend $237 billion through 2016 developing some of the largest oil discoveries made in the past 20 years. With Petrobras spending more than it makes, net debt jumped more than 30% in 2012 from 2011 while the company's cash on hand--once flush with proceeds from a $70 billion share offer in 2010--fell more than 20% to $13.5 billion.

Still, "the deterioration was pretty much in line with what we were expecting," Ms. Ares said in an interview. "At this point, it doesn't impact the rating." Petrobras is in the midst of a significant exploration and investment program, so the increased leverage isn't necessarily a red flag, she added.

Fitch rates Petrobras triple-B with a stable outlook, two notches into investment grade and the same as Brazil's sovereign credit rating. While Ms. Ares doesn't anticipate any changes to the rating over the next 12 to 18 months, a change in the outlook for Brazil's sovereign rating to negative or an unexpected event could lead Fitch to re-evaluate Petrobras, she said.

Part of the credit-rating agency's confidence in Petrobras is based on its potential to quickly boost crude-oil production and reserves in coming years, Ms. Ares said. Petrobras's long history of exploration success, especially the discovery of multibillion-barrel oil fields buried under a thick layer of salt off Brazil's coast, make the company unique among its state-run and private-sector peers, she said.

Petrobras is "able on a yearly basis to replace in reserves the volume it has produced," Ms. Ares noted. Petrobras said that it ended 2012 with reserves of 12.3 billion barrels of oil-equivalent under Securities and Exchange Commission criteria, enough to keep Petrobras pumping oil for 15 years if it never discovered another drop. But the reserve figures currently include only a fraction of the newfound fields and should grow dramatically in coming years.

Petrobras is counting on the new fields to more than double current output to 4.2 million barrels per day by 2020. Fitch, meanwhile, expects crude oil production to start picking up in 2015, which should lead to a recovery in the company's finances as the new output generates cash, according to Ms. Ares.

The political tussle over domestic fuel prices, however, has Fitch watching closely, Ms. Ares said. Fuel-price increases granted in January and last year aren't enough to reverse Petrobras's losses on imports, but the hikes do suggest that the government is paying attention to Petrobras's losses, she said.

"There is a strong incentive for the government to have Petrobras performing and repaying its debt because of the significant financing resources Petrobras will need in coming years to fund its investments," Ms. Ares said.

Petrobras has faced similar situations where it lost money on imports in the past, only to later reap the rewards of selling local fuels at higher prices when international crude oil and fuel prices fell, she noted. The government's focus on fighting inflation, however, means future price hikes are uncertain.

"How politics play out this year will decide whether those price increases will come or not," Ms. Ares said.

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

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Max Petroleum Reaches TD at Zhana Makat Well

Max Petroleum Plc, an oil and gas exploration and production company focused on Kazakhstan, announced that the ZMA-A20 development well in the Zhana Makat Field has successfully reached a total depth of 3,032 feet (924 meters), encountering hydrocarbons in Necomian and Jurassic sandstone reservoirs in line with expectations. The Company plans to complete the well and then place it on production as soon as practicable. The Zhanros ZJ-20 rig will now move to drill the ZMA-A22 development well in the Zhana Makat Field.

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Kreuz's Expanded Fleet Gives 430% Boost to 4Q Profit

Singapore-listed Kreuz Holdings posted Friday a fourth quarter profit ended Dec. 31, 2012, of $5.7 million, up 430 percent from the same period last year. In 4Q 2011, Kreuz reported a net profit of $1.07 million.

For the full year ended Dec. 31, 2012, Kreuz booked a profit of $39.6 million, up 49 percent from one year ago.

Kreuz said in its earnings report that the acquisition of a dynamic positioning construction class diving support vessel in April last year contributed to an increase in gross profit margin, as it reduced the company's reliance on third party vessels.

"The subsea sector is maintaining its current trend of continued growth in the shallow, medium and ultra-deep waters as subsea technology becomes an economically viable solution for increasingly remote or ultra-deepwater fields," the company noted in its disclosure.

"The high demand expected in the subsea sector along with the need to reinvigorate aging offshore fields augur well for Kreuz's subsea construction and installation services, and inspection, repair and maintenance," the company added.

In the Southeast Asian region, oil-rich countries such as Malaysia and Indonesia are placing a renewed emphasis on reinvigorating their aging offshore oil fields. Both of these countries are also looking at promoting exploration deeper offshore and on their smaller oil fields.

Quintella has reported on the upstream and downstream oil and petrochemicals markets from 2004. Email Quintella at quintella.koh@rigzone.com.

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Shell Reassesses Development Plan for North Sea Fram Field

LONDON - Royal Dutch Shell PLC is reassessing its development plan for the Fram oil and gas field in the North Sea following "unexpected" initial drilling results, the company said late Thursday.

Shell had planned to produce an average of 35,000 barrels of oil equivalent a day from the field, with first production targeted within the next three years.

"Development drilling for the Fram field began last year but early assessments have shown unexpected well results. Development drilling will continue for the next several months and the results will inform a revised strategy for Fram," Shell said in a statement posted on its website.

Shell and its partner in the joint venture Esso Exploration & Production UK Ltd., a unit of Exxon Mobil Corp., is continuing to evaluate the potential of the Fram reservoirs, with a view to producing an alternative development plan for the field, Shell said.

Shell has already cancelled an order with SBM NV for a floating production storage and offloading vessel, or FPSO, that was to be used in the Fram project.

The Fram field is located 220 kilometers east of Aberdeen and 50 kilometers west of the median line between the U.K. and Norway in a water depth of approximately 100 meters.

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Bowleven Strikes Oil at Appraisal Offshore Cameroon

Bowleven announced that the IM-5 well drilling offshore Cameroon has now reached the Middle Isongo primary objective of the well and has encountered liquids-rich hydrocarbon-bearing pay in both this and the Intra Isongo reservoir objectives based on the results of drilling, core analysis, wireline logs, fluid samples and pressure data.

The well, which was designed to appraise the reservoir and fluid properties of the Middle Isongo and to explore the additional potential of the Intra Isongo, has reached TD of 3,430 meters MD. The forward program is to set liner and conduct testing operations.

Validation of sufficient gas volumes to meet fertilizer plant requirements.Samples obtained during logging confirm the presence of liquids-rich hydrocarbons in the Intra and Middle Isongo intervals.Approximately 82 feet (25 meters) of log evaluated net hydrocarbon-bearing pay over a gross interval of approximately 108 feet (33 meters) encountered in the Middle Isongo primary objective.Log evaluation indicates hydrocarbon water contact (HWC) at approximately 11,024 feet (3,360 meters) MD, extending and deepening the hydrocarbon column intersected at IM-3 by 305 feet (93 meters), with total column height intersected by the two wells of 476 feet (145 meters).A further 66 feet (20 meters) of high quality sands were encountered directly beneath the HWC.Approximately 230 feet (70 meters) of net hydrocarbon-bearing pay over a gross interval of approximately 262 feet (80 meters) now confirmed in the Intra Isongo following log evaluation, with hydrocarbon down to the base of the reservoir.Preparing for testing operations.

The primary objective of the IM-5 appraisal/development well was to appraise the reservoir and fluid properties of the Middle Isongo sands. The secondary objective of the well was to investigate the additional potential of the Intra Isongo exploration prospect, a potentially extensive amplitude supported channel system potentially comprising both structural and stratigraphic trapping elements. The well was also designed to intersect the Upper Isongo sands and confirm that these were present at this location and water-bearing as prognosed.

Since Bowleven's previous IM-5 drilling update announcement on 30 January 2013, the well, which is drilling in shallow water depths of around 184 feet (56 meters), has been drilled to a depth of 11,253 feet (3,430 meters) MD. Logging activities have been performed and core was acquired as planned in the Middle Isongo reservoir interval.

Bowleven, as operator, provides the following updates on the reservoir sections intersected:

The well has intersected a log evaluated gross hydrocarbon interval of approximately 108 feet (33 meters). The net pay is estimated to be approximately 82 feet (25 meters). Log evaluation indicates that a HWC has been encountered at approximately 11,024 feet (3,360 meters) MD, extending and deepening the hydrocarbon column encountered at the IM-3 well by 305 feet (93 meters). A further 66 feet (20 meters) of reservoir quality sands were encountered beneath the HWC and the well was still in sand at TD.

Core analysis and fluid samples acquired during operations confirm the presence of liquids-rich hydrocarbons. Initial sample analysis suggests a liquids to gas ratio in the region of 150 bbls/mmscf.

The well has intersected a log evaluated gross hydrocarbon interval of approximately 262 feet (80 meters) in reservoir sands which correspond to the seismic event identified pre-drill. The net pay is estimated to be approximately 230 feet (70 meters). No HWC was encountered.

Fluid samples acquired during logging activities confirm the presence of liquids rich hydrocarbons. Initial sample analysis suggests a liquids to gas ratio in the region of 200 bbls/mmscf.

The well has intersected approximately 105 feet (32 meters) of high quality reservoir sands in the Upper Isongo. As predicted, log evaluation indicates these sands are water-bearing at this location. Sand thickness and quality were consistent with pre-drill expectations.

The plan is to set liner prior to testing. The testing program is currently being finalized.

Updated volumetrics for the Middle and Intra Isongo will be generated following completion of the well (including testing) and the integration and evaluation of well and seismic data. Based on preliminary analysis an increase in both the P90 and P50 volumes is anticipated.

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Shell Reassesses Development Plan for North Sea Fram Field

LONDON - Royal Dutch Shell PLC is reassessing its development plan for the Fram oil and gas field in the North Sea following "unexpected" initial drilling results, the company said late Thursday.

Shell had planned to produce an average of 35,000 barrels of oil equivalent a day from the field, with first production targeted within the next three years.

"Development drilling for the Fram field began last year but early assessments have shown unexpected well results. Development drilling will continue for the next several months and the results will inform a revised strategy for Fram," Shell said in a statement posted on its website.

Shell and its partner in the joint venture Esso Exploration & Production UK Ltd., a unit of Exxon Mobil Corp., is continuing to evaluate the potential of the Fram reservoirs, with a view to producing an alternative development plan for the field, Shell said.

Shell has already cancelled an order with SBM NV for a floating production storage and offloading vessel, or FPSO, that was to be used in the Fram project.

The Fram field is located 220 kilometers east of Aberdeen and 50 kilometers west of the median line between the U.K. and Norway in a water depth of approximately 100 meters.

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