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Posted 11:24 pm Sunday, February 24, 2013
The drilling report was produced with data from the Texas Railroad Commission, from February 10 to 16. The following counties were searched: Anderson, Angelina, Camp, Cass, Cherokee, Dallas, Ellis, Freestone, Gregg, Harrison, Henderson, Houston, Kaufman, Leon, Limestone, Marion, Nacogdoches, Navarro, Panola, Rains, Robertson, Rusk, San Augustine, Shelby, Smith, Upshur, Van Zandt and Wood. For information contact Business Editor Casey Murphy at cmurphy@tylerpaper.com or 903-596-6289.
Monday, April 1, 2013
Sembcorp Marine Sees Profit Dip, Admits 2012 Challenging Year
Sembcorp Marine posted late Thursday a net profit for the final quarter of 2012 at $135 million (SGD167 million), down 27 percent from the same period last year. In 4Q 2011, Sembcorp Marine booked a net profit of $185 million (SGD229 million).
Operating profit for the quarter was $120 million (SGD 148 million), down 26 percent from one year ago.
Sembcorp Marine also saw its net and operating profits slide on a full year basis. For the year ended Dec. 31, 2012, the company posted a net profit of $435 million (SGD 538 million) and an operating profit of $448 million (SGD 554 million), down 28 percent and 25 percent respectively.
Sembcorp Marine noted in its earnings release that it was operating in a challenging environment last year. The company ended last year having to grapple with the aftermath of an offshore accident; the Noble Regina Allen (400' ILC jackup) tilted during a jacking system test Dec. 3, 2012. The incident led to some 89 workers being injured.
Sembcorp Marine revealed in its earnings report that the company has a net order book of $11 billion (SGD 13.6 billion) with completion and deliveries stretching into 2019.
"Amid the fragile global environment, the long-term industry fundamentals for the Offshore Oil and Gas sector remain sound underpinned by high oil prices and projected increases in offshore exploration and production spending," Sembcorp Marine said in a statement.
"Yard activity level will remain high over the next two years, supported by Sembcorp Marine's $11 billion net order book. However, margins may continue to normalize. In this rig order cycle, price increase is slower and we believe this is attributed to rising competition for offshore orders," OSK Research's analyst Jason Saw said in an opinion statement.
"The jackup rig replacement theme is still intact but this market segment will see competition from Chinese and Middle East yards," Saw noted.
Quintella has reported on the upstream and downstream oil and petrochemicals markets from 2004. Email Quintella at quintella.koh@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.US, States Mull Extending $16B Oil-Spill Settlement Offer to BP
The U.S. Justice Department and Gulf Coast states are mulling offering BP PLC a $16 billion deal to settle civil claims related to the deadly 2010 Deepwater Horizon incident, according to people familiar with the discussions.
The settlement offer would cover potential fines owed by BP under the Clean Water Act and payments under another process known as the Natural Resources Damage Assessment, or NRDA, the people said. The fines stem from the massive Gulf of Mexico oil spill that ensued from the Deepwater Horizon well blowout in April 2010.
BP's potential Clean Water Act fines could run as high as $17.6 billion, but the company has argued they would likely be less than $5 billion. The NRDA payments could also run into the billions, but they are tax deductible for BP. BP must be found to have been grossly negligent in its role leading up to the blowout and spill to receive the highest penalty. The company argues it wasn't grossly negligent and prosecutors and plaintiffs have a very high bar to clear to prove otherwise.
The potential settlement offer helps illustrate the thinking of federal and state governments about the largest penalty BP faces in the wake of the Deepwater Horizon saga, a figure that has been subject to wildly ranging guesses. But it is far from certain that even if the offer is made, it will bring the U.K.-based oil company closer to a deal.
The first of two Deepwater Horizon trials is set to begin Monday before a federal judge in New Orleans.
It isn't clear if the offer has been formally proposed to BP, which declined to comment. BP said previously it was open to negotiations but that it was fully prepared to start trial Monday. The Justice Department, which also stated earlier this week it was prepared to go to trial, declined to comment as well.
Federal and state officials met in Washington, D.C., last week to work on terms of a settlement offer and continued discussions throughout this week, according to the people familiar with the negotiations.
The people said among the disagreements between the governments are how much of the fines will fall under the Clean Water Act and how much will fall under NRDA. A law passed by Congress would give the states control over 80% of Clean Water Act fines, while NRDA fines would go to specific wildlife and natural habitat restoration projects. Louisiana would likely receive the most NRDA funds since that state's coast line and waters were most directly affected by the spill.
Terms of the offer and settlement discussions could continue even through the beginning of the trial, the people said.
Tuesday, a judge agreed with BP and the Justice Department that 810,000 gallons of the estimated 4.9 million gallons the government has said leaked from the well were successfully captured by spill-response vessels and shouldn't count against any future fines. That ruling effectively reduced the maximum possible Clean Water Act fines by $3.48 billion.
BP previously agreed to a $4 billion settlement of criminal charges related to the blowout on the Deepwater Horizon drilling rig and the ensuing spill, as well as a $525 million civil settlement with the Securities and Exchange Commission. Transocean Ltd. (RIG, RIGN.VX), the owner of the rig, agreed to a $400 million criminal settlement and $1 billion civil settlement for violations of the Clean Water Act.
BP says it is eager to fight it out in court, believing past settlement offers didn't adequately reflect the company's legal position. In an interview with The Wall Street Journal this week, BP General Counsel Rupert Bondy said of the few Clean Water Act cases that go to trial, the per-barrel penalties are significantly less than the maximum allowed. He also noted judges take into account several other factors when determining penalties, such as a company's efforts to address the environmental impacts of the spill.
BP has spent more than $14 billion on spill response and cleanup, paid out more than $9 billion to Gulf Coast businesses and individuals impacted by the spill, and committed billions more to environmental restoration and research.
"Facing demands that we believe are excessive, not anchored in reality or the merits of the case, we are preparing ourselves to start the trial in one week's time," Mr. Bondy had said Monday.
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.Sembcorp Marine Sees Profit Dip, Admits 2012 Challenging Year
Sembcorp Marine posted late Thursday a net profit for the final quarter of 2012 at $135 million (SGD167 million), down 27 percent from the same period last year. In 4Q 2011, Sembcorp Marine booked a net profit of $185 million (SGD229 million).
Operating profit for the quarter was $120 million (SGD 148 million), down 26 percent from one year ago.
Sembcorp Marine also saw its net and operating profits slide on a full year basis. For the year ended Dec. 31, 2012, the company posted a net profit of $435 million (SGD 538 million) and an operating profit of $448 million (SGD 554 million), down 28 percent and 25 percent respectively.
Sembcorp Marine noted in its earnings release that it was operating in a challenging environment last year. The company ended last year having to grapple with the aftermath of an offshore accident; the Noble Regina Allen (400' ILC jackup) tilted during a jacking system test Dec. 3, 2012. The incident led to some 89 workers being injured.
Sembcorp Marine revealed in its earnings report that the company has a net order book of $11 billion (SGD 13.6 billion) with completion and deliveries stretching into 2019.
"Amid the fragile global environment, the long-term industry fundamentals for the Offshore Oil and Gas sector remain sound underpinned by high oil prices and projected increases in offshore exploration and production spending," Sembcorp Marine said in a statement.
"Yard activity level will remain high over the next two years, supported by Sembcorp Marine's $11 billion net order book. However, margins may continue to normalize. In this rig order cycle, price increase is slower and we believe this is attributed to rising competition for offshore orders," OSK Research's analyst Jason Saw said in an opinion statement.
"The jackup rig replacement theme is still intact but this market segment will see competition from Chinese and Middle East yards," Saw noted.
Quintella has reported on the upstream and downstream oil and petrochemicals markets from 2004. Email Quintella at quintella.koh@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.Crude-Oil Futures Settle Up After Steep Two-Day Losses
Crude-oil futures prices, battered in a sharp two-day selloff on demand worries, settled modestly higher Friday, while gasoline futures prices rebounded.
"It seems the blood-letting ran its course and the market's trying to catch its breath," said Gene McGillian, broker and analyst at Tradition Energy.
Front-month U.S. benchmark crude-oil futures prices dropped $4.58 a barrel in the previous two days, ending Thursday at a new 2013 low. Prices barely staggered to their feet after the two-day pounding, in which commodity funds shed their expectations of near-term higher prices, helped by a large jump in U.S. crude-oil inventories.
Market anxieties may not let up next week as the March-delivery contracts for reformulated-gasoline and heating-oil futures expire at Thursday's settlement and the March 1 deadline to break a government impasse and reach a deal to avoid $85 billion in automatic spending cuts looms. Failure to reach a deal likely would unnerve markets, traders said.
Light, sweet crude-oil futures for April delivery on the New York Mercantile Exchange settled 29 cents higher, at $93.13 a barrel. The contract fell 3.4%, the worst weekly performance for Nymex crude since Oct. 26, 2012.
April ICE Brent crude oil, which lost $3.99 over the previous two days, settled 51 cents higher Friday, at $114.10 a barrel. The contract lost 3% in the week, the biggest decline since the week ended Dec. 7, 2012.
Analysts at Goldman Sachs said oil prices are now "in line with fundamentals" after moving too high on "forward-looking survey data generating renewed optimism" on the global economy and oil-demand growth. The reality of "lackluster" hard data on actual demand and weak physical markets for oil brought about the selloff, the analysts said in a note.
Pressure on U.S. crude prices built when the Energy Information Administration reported domestic crude-oil stocks rose by 4.1 million barrels last week, more than twice the expected level. Stocks are now sufficient to meet nearly 27 days of current low demand from refiners, EIA data show. That is the highest level of inventory cover since March 1994, and crude-oil stocks outright are at their highest level for this time of year on EIA data beginning in 1982.
Andy Lebow, senior vice president for energy futures at Jefferies Bache, said U.S. crude now appears set to trade in a range of $90-$95 for the near term, down from the recent $95-$100 span.
Meantime, fireworks may surround the expiration of the March-delivery reformulated gasoline futures contract next week. The contract dropped 9.8 cents a gallon in the previous three days from a 20-week high, before recovering to settle 1.4% higher Friday.
Price volatility is common at this time of year as refiners walk a fine line between producing enough fuel to meet the winter-grade specification for the March contract before switching to the costlier, cleaner-burning summer-grade fuel that meets the April contract specifications.
In the last four trading days of the March 2012 contract, RBOB futures, then at a seven-month high, fell 11.05 cents, or 3.5%.
March-delivery RBOB futures rose 4.31 cents a gallon Friday, to settle at $3.0796 a gallon.
March-delivery heating oil futures, which shed 12.8 cents over the previous four sessions, settled 0.85 cent higher, at $3.1042 a gallon.
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.Hercules Offshore to Acquire Jackup Ben Avon
Hercules Offshore, Inc. announced the execution of an agreement to acquire the offshore drilling rig Ben Avon (250' ILC) from a subsidiary of KCA Deutag. The purchase price is $55 million in cash. The Ben Avon is a LeTourneau Class 82 SD-C self-elevating drilling rig registered and flagged in Panama. Subject to completion of certain closing conditions, the Company expects the acquisition to close by late-March 2013.
Hercules Offshore also announced that it has signed a Letter of Agreement (LOA) for a three-year rig commitment with Cabinda Gulf Oil Company Limited (CABGOC) for use of the Ben Avon. The Company expects to generate total revenue of approximately $119 million over this three-year period under the contract. Subject to the execution of a mutually agreed drilling contract, the Company expects the rig to commence work as early as May 2013.
Chief Executive Officer and President of Hercules Offshore John T. Rynd stated, "We are very pleased to be able to acquire the Ben Avon and execute an LOA with CABGOC. With this transaction, we continue to opportunistically expand our international presence and scale, add significant long term backlog and cash flow, and reaffirm our commitment to CABGOC, a key global client, at economics that are beneficial for all parties. The LOA for the Ben Avon replaces our prior contract with CABGOC for the Hercules 185, at a substantial improvement in dayrate and provides for a new full three year term. The Ben Avon is a well-maintained rig that recently completed an extensive five year special survey. Given the good condition of the rig, and its close proximity to the drilling location, we expect to spend only minimal additional capital to get it on contract."
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.For More Information on the Offshore Rig Fleet:
RigLogix can provide the information that you need about the offshore rig fleet, whether you need utilization and industry trends or detailed reports on future rig contracts. Subscribing to RigLogix will allow you to access dozens of prebuilt reports and build your own custom reports using hundreds of available data columns. For more information about a RigLogix subscription, visit http://www.riglogix.com/.
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.
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.Magellan to Buy Pipelines from Plains All American
Magellan Midstream Partners, L.P. announced Friday that it has agreed to acquire approximately 800 miles of refined petroleum products pipeline from Plains All American Pipeline, L.P. for $190 million.
"This acquisition utilizes Magellan's expertise in transporting and storing petroleum products," said Michael Mears, chief executive officer. "These pipelines are a natural extension of our existing refined products distribution system and provide new markets for Magellan to serve."
Rocky Mountain pipeline system. The acquisition includes approximately 550 miles of common carrier pipeline that distributes refined petroleum products in Colorado, South Dakota and Wyoming. The system includes 4 terminals with nearly 1.7 million barrels of storage.
Magellan also will acquire about 250 miles of common carrier pipeline that transports refined petroleum products north from El Paso, Texas, delivering products to Albuquerque, New Mexico, and transports products south to the Texas-Mexico border for delivery via a third-party pipeline within Mexico.
Management expects the acquisition to be immediately accretive to the partnership's distributable cash flow per unit, with the potential for additional growth in cash flow from the assets over time.
The acquisition is expected to close in the second quarter of 2013 subject to regulatory approvals. Management expects to fund the acquisition with cash on hand and borrowings under its revolving credit facility, if necessary.
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.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.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.
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