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Technology, Collaboration Drive Offshore Development

April 24th, 2014 vaddison Posted in Uncategorized | Comments Off

By Jennifer Presley, Hart Energy

As we step closer to another Gulf Coast summer, two things are a given: the arrival of hurricane season and the start of the Offshore Technology Conference (OTC). While one brings the potential for torrential rains and winds, the other delivers—without fail—a torrent of people from all corners of the globe to Houston’s open doors. Set for May 5-May 9, OTC is an exciting, adrenaline-packed four days of networking and knowledge building—two of the softer but highly important skills in a career toolbox—that will help further development of offshore resources in the years to come.

While the focus of OTC is not specifically centered on the Gulf of Mexico (GoM), many of the technologies showcased on the exhibit floor or presented to packed rooms have been applied with success in its waters. From the timber-built platform of the first offshore well in the GoM—drilled in a field called Creole off the coast of Louisiana in 1938—to the steel giants of today in fields like Mars and Na Kika, technology and collaboration have each played a key role in the development of the GoM.

Each has helped push offshore development farther out and deeper into the GoM. Results from the recent Lease Sale 231 for the Central Planning Area attracted more than $850 million in high bids on 326 blocks covering 1.7 million acres on the U.S. Outer Continental Shelf (OCS) offshore Louisiana, Mississippi and Alabama, according to Bureau of Ocean Energy Management (BOEM)-issued press release. A total of 42 offshore energy companies participated in submitting 380 bids. Of those 380 bids, 156 were for tracts located in water depths greater than 800 m (2,624 ft), with the lion’s share of the bids (108) for tracts in water depths greater than 1,600 m (5,250 ft), according to a BOEM-issued presale statistics report.

Industry watchers will cast their gazes towards New Orleans in August when the results for the Lease Sale 238 for the Western Planning Area are announced. According to BOEM, the sale will include approximately 3,992 blocks, covering roughly 21.4 million acres in water depths ranging from 5 m to 3,336 m (5 ft to 10,978 ft). Safely developing these leases will, in some cases, require the development of new technologies and approaches. Major operators like BP, with its Project 20K, are working on projects today to develop those new technologies.

Many of today’s technologies developed for use in the deep water have found uses in other industries. This transfer of technologies has benefitted numerous industries, including automotive, aviation, petroleum, and military. For example, the AUVs discussed in this month’s Offshore Connect interview with Mark Hall, president of Kongsberg Oil and Gas, originally developed for academic research in the 1970s, have found uses not just in the oil and gas industry conducting subsea pipeline inspections but also black box recovery missions.

Jennifer Presley is senior editor, offshore, for E&P. Editor’s Note: If you happen to be attending OTC this year, be sure to visit the Hart Energy booth (#3109) to pick up the latest issues of E&P and the official OTC newspaper.

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Will The U.S. Fracking-Led Shale Boom Soon Go Bust?

April 22nd, 2014 vaddison Posted in Uncategorized | Comments Off

By Tom Zeller Jr., Bloomberg

It’s not surprising that a survey of energy professionals attending the 2014 North American Prospect Expo overwhelmingly identified “U.S. energy independence” as the trend most likely to gain momentum this year. Like any number of politicians and pundits, these experts are riding high on the shale boom—that catch-all colloquialism for the rise of hydraulic fracturing and horizontal drilling that have unleashed a torrent of hydrocarbons from previously inaccessible layers of rock.

But this optimism belies an increasingly important question: How long will it all last?

Among drilling critics and the press, contentious talk of a “shale bubble” and the threat of a sudden collapse of America’s oil and gas boom have been percolating for some time. While the most dire of these warnings are probably overstated, a host of geological and economic realities increasingly suggest that the party might not last as long as most Americans think.

For the better part of two centuries, the American oil and gas industry drew its treasure from porous underground formations where hydrocarbons moved comparatively easily to the surface. The best of those resources began to dry up in the 1970s and imports began to rise. Enter hydraulic fracturing and horizontal drilling, technologies that allow developers to extract oil and gas from much deeper, tighter and far-less-porous rock formations, including shale.

The problems arise when you look at how quickly production from these new, unconventional wells dries up. David Hughes—a 32-year veteran with the Geological Survey of Canada and a now research fellow with the Post Carbon Institute, a sustainability think-tank in California—notes that the average decline of the world’s conventional oil fields is about 5% per year. By comparison, the average decline of oil wells in North Dakota’s booming Bakken shale oil field is 44% per year. Individual wells can see production declines of 70% or more in the first year.

Shale gas wells face similarly swift depletion rates, so drillers need to keep plumbing new wells to make up for the shortfall at those that have gone anemic. This creates what Hughes and other critics consider an unsustainable treadmill of ever-higher, billion-dollar capital expenditures chasing a shifting equilibrium. “The best locations are usually drilled first,” Hughes said, “so as time goes by, drilling must move into areas of lower quality rock. The wells cost the same, but they produce less, so you need more of them just to offset decline.”

That’s a tall order when prices are low. Currently, natural gas is moving at about $4.50 per MMBtu—a welcome uptick, but by no means ideal for producers. Even if that climbed to $6, Hughes estimates that shale gas growth would last only another four years or so, at which point even-higher prices would be needed to maintain production, let alone keep it growing.

Speaking last month to Oilprice.com, Art Berman, a Houston-based geological consultant with a similarly sober (and often unpopular) view of the shale boom, called for more realistic assessments of its longevity. “I’m all for shale plays, but let’s be honest about things, after all,” Berman said. “Production from shale is not a revolution; it’s a retirement party.” Berman and Hughes both presented their concerns at the annual meeting of the Geological Society of America last fall.

Not everyone thinks this sort of pessimism is warranted. With funding from the Alfred P. Sloan foundation, Scott Tinker, a professor of geosciences at the University of Texas at Austin has been leading one of the most comprehensive, well-by-well analyses of the four biggest shale gas reserves in the U.S., including the contentious Marcellus formation in the Appalachians. Tinker doesn’t quibble much with Hughes’ and Berman’s observations about well depletion rates, though he interprets the implications differently.

“Just like conventional drilling, the broad message here is that these basins are going to continue to be drilled and there will be money made by some and lost by others,” Tinker said. He prefers to call the shale boom an evolution rather than a revolution, and he suggests that while new wells must consistently be plumbed to address the shortfalls of old ones, this has always been the case. Newer drilling technology that allows several well paths to proceed from a single surface installation will help minimize local impacts, Tinker says—adding that with higher prices, the shale gas boom could remain healthy as far out as 2040.

That’s not an immediate threat, but it’s also not exactly the 100-years-of natural gas that President Barack Obama has touted. Clearly, neither shale oil production, which even Tinker concedes is likely to peak just five or six years from now, nor shale gas will escort the U.S. into the era of energy independence. Getting there requires a much more deliberate diversification of the nation’s energy portfolio, along with far more aggressive efforts to increase efficiency and eliminate energy waste— steps that, by the way, are also critical in addressing that other nagging issue, global warming.

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Technology Extends Reach As Easy Oil, Gas Run Out

April 15th, 2014 vaddison Posted in Uncategorized | Comments Off

By Giacomo Del Panta, GE

Oil and gas currently accounts for close to 50% of total primary energy demand. While the total remaining recoverable resources are estimated to last for almost 200 years, we are facing an annual oil depletion rate of 8%, making it hard to anticipate how we can meet demand that is expected to increase by 28 MMbbl/d by 2040.

According to the International Energy Agency (IEA), 42% of worldwide recoverable gas is unconventional and three-quarters of ultimately recoverable resources will still remain to be recovered in 2035. The global reserves-to-production ratio of conventional gas based on current consumption levels is in the range of 55 to 60 years.

As far as oil is concerned, even with discoveries of new proven reserves, oil prices continue to rise as we deplete a finite natural resource. Even with these additional documented reserves, 40% are hard to reach offshore—two-thirds in the Arctic and one-third in deep water.

Deep water and subsea: the future of energy production

As the conventional “easy” reserves are exhausted, energy producers will need to push the limits of technology to gain access to resources in new and extreme locations, including distant offshore and deepsea resources, subsea production and shale deposits; reserves that might have been seen as economically unviable a few years ago.

There are three areas in particular that are receiving large amounts of investment to ensure we can meet future energy demand:

1. FLNG plants: Floating vessels with facilities to produce, liquefy, store and transfer LNG at sea, enable further access to natural gas, the cleanest-burning fossil fuel which is abundant and affordable. Having the ability to process gas at the point of extraction eliminates the need for costly long pipelines and onshore production facilities and the product can be shipped straight to market. You can read more on FLNG in our recent post on the topic.

2. Subsea extraction involves moving to ever deeper waters and more challenging environments. The deeper we go in future—3,000 m (9,843 ft) below sea level and beyond—the higher the costs and risks involved in processing resources topside. Even though subsea production is still in its infancy, it brings many potential benefits as outlined in one of our recent blog posts, including tapping into new reserves.

3. Shale gas extraction has seen unprecedented growth in recent years and significant investments are being made in research and development to support the industry. The combination of horizontal drilling and hydraulic fracturing has allowed access to large volumes of shale gas that were previously uneconomical and unsafe to extract. While North America accounted for around 90% of unconventional gas production in 2012, other resource-rich countries, including China, Latin America and Russia, are set to accelerate production.

Electrification powers exploration

A key requirement for these oil and gas extraction techniques is electric power. In the case of FLNG plants, where space is at a premium and weight restrictions apply, electric drive motors are used to run the compression and cooling systems for liquefaction. In a deepsea scenario, HVDC extends transmission range, allowing us to power electrical equipment installed on the seabed from land or FPSO based power supplies. The shale gas boom, on the other hand, has driven a need for more sophisticated and flexible LNG distribution networks, for which small-scale LNG plays a key role.

The world’s power needs continue to grow at a substantial rate and our energy future remains a topic of significant debate. Unlocking the potential of these more challenging energy reserves is a core objective of the next decade of exploration, research and development, and electric technology has a key role to play.

Giacomo Del Panta leads the European region for oil and gas in GE’s power conversion business.

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Do You Know The One About Fracking And Fishing?

April 8th, 2014 vaddison Posted in Uncategorized | Comments Off

By Jonathan Weil, Bloomberg

There is a chance you missed an excellent story by Bloomberg News reporter Asjylyn Loder about the inherently unreliable methods energy companies use to measure how much oil they have in the ground. So allow me to direct you to it here.

The article focused on shale-oil reserves. The problem it described: Many drillers apply a formula developed in 1945 called the Arps equation to shale technology, which didn’t exist then. (The method is named for Jan Arps, the petroleum engineer who created it.) As a result, future energy production is being exaggerated.

But there is more to this story. And here’s where I can add some value, along with some ancient oil-patch humor. Estimates of companies’ petroleum reserves always have been sketchy, no matter what kind of crude or natural gas. The stuff sometimes is buried miles underground, often beneath deep water. It can be hard to measure.

One incident that comes to mind occurred a decade ago, when Royal Dutch Shell admitted that top executives had overstated reserve data. The financial press treated it like a big scandal. But investors mostly it shrugged off, which was understandable, because they knew that reserve numbers are far from precise.

Indeed, when U.S. accounting rulemakers back in the early 1980s first wrote the standards for disclosing companies’ proved oil-and-gas reserves, they decided that the figures should be reported as “supplementary” information outside the companies’ official financial statements. The reason they cited at the time: the numbers weren’t reliable enough to justify the cost of having them audited independently.

This brings me to the real purpose for this column: To share some old jokes with you. These have been around a long time. I’m not sure who first wrote them, and I’ve seen many variations over the years. This one comes from a slide presentation on the website of Ryder Scott Co., a Houston-based petroleum-consulting firm that does reserves certifications. And it goes like this:

Reserves are like fish …

• Proved developed: The fish is in your boat. You have weighed him. You can smell him, and you will eat him;
• Proved undeveloped: The fish is on your hook in the water by the boat, and you are ready to net him. You can tell how big it looks…and they always look bigger in the water;
• Probable: Fish are in the lake. You may have caught some yesterday. You may be able to see them today, but you have not yet caught any; and
• Possible: The lake has water. Someone may have told you there are fish in the lake. You have your boat on the trailer, but you may go play golf instead.

Old jokes are the best, aren’t they?

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U.S. Energy Assistance For Ukraine Has Limits

April 2nd, 2014 vaddison Posted in Uncategorized | Comments Off

By Frank A. Verrastro and Charles K. Ebinger, Center for Strategic and International Studies

Over the weekend, the crisis in Ukraine took a more ominous turn with the referendum in Crimea rejoining the peninsula with Russia while Russian troops amassed on the country’s eastern border. In addition, the United States and European Union’s imposition of what is forecasted to be the first salvo of economic sanctions was launched. On Wednesday, Ukraine’s defense minister announced that he would go to Crimea to seek a diplomatic solution, an offer immediately rebuffed by Crimea’s prime minister, thus setting back prospects for a reasoned solution (e.g., a more autonomous Crimea within an independent Ukraine).

At the same time, the focus of meaningful economic sanctions has increasingly honed in on energy—and for good reason. More than 90% of Russian gas exports and 80% of its oil sales go to Europe. (Overall, energy sales generate more than half of the revenues needed to meet the Kremlin’s budget.) Further, fully half of the natural gas sold to Europe is transported through Ukraine. While European gas demand in total is projected to remain flat for the rest of the decade and perhaps longer, supplies from other sources (Norway, Algeria and Netherlands) are in decline. Consequently, Russia expects European and especially eastern and central European dependency to increase even as Russia looks east to Asia for additional markets in China, Korea and Japan as well as into the Pacific LNG market.

Ironically, the seeds of Europe’s current dependency grew out of an effort to diversify energy imports in the wake of the energy crises of the 1970s. Construction of pipeline infrastructure linking Soviet supplies to European markets seemed like a win-win for both parties. The breakup of the Soviet Union a decade later, however, produced noticeable tensions with former Soviet states, now situated in key transit areas.

To some, the stark reversal in America’s energy fortunes—spawned by the dramatic resurgence in U.S. production as a consequence of the shale gas and tight oil revolutions provides the perfect foil for limiting Russian ambitions. The crisis in Ukraine has reinvigorated the debate in Washington over the Keystone XL pipeline, the accelerated permitting of LNG export facilities, and spurred calls for lifting the ban on crude oil exports to a beleaguered Europe. While the rhetorical flourish associated with the linkage is politically intoxicating, the underlying facts bear scrutiny.

For starters, while the acceleration of U.S. energy exports would add incremental barrels and gas volumes to the international market (a good thing for consumers everywhere), the volume and timing of their availability—outside of supplies from the Strategic Petroleum Reserve (SPR)—would not be available in time to have an immediate impact on the current crisis. The first available LNG export shipment from the United States will not be ready until late 2015 or the spring of 2016 at the earliest, and these volumes are already contractually committed.

On the oil side of the ledger, since Russia is one of the largest oil producers in the world—with exports averaging 7 MMbbl/d, incremental U.S. production or even a sizeable SPR release (the current maximum drawdown rate is about 4 MMbbl/d for the first 90 days and declining thereafter) would not be adequate to replace or offset Russian barrels lost as the result of potential sanctions. Consequently, in the absence of Russian barrels, world oil prices would undoubtedly spike—causing economic pain for the United States and its sanctions partners.

More importantly, however, is the impact more onerous sanctions will have on the relationship between the United States, the EU and Russia going forward. We can certainly opt to boycott this summer’s Group of Eight meeting in Sochi and limit Russia’s participation in other global fora, but to what end? Russia will remain a permanent member of the U.N. Security Council and an uneasy partner in multilateral efforts to promote constructive resolutions to at least two other important international crises—the ongoing strife in Syria and resolution of the nuclear standoff with Iran. And further to that point, the removal of Russian oil from global markets could actually work to undermine the sanctions on Iranian oil sales.

As for Europe—east and west—there are a variety of actions that can be taken over time to enhance their collective and individual member nation’s energy security, including:

• Increasing domestic production of indigenous resources of coal, shale gas and oil;
Promoting efficiency and revamping price structures;
• Developing alternative energy and integrating renewable supplies into the energy mix;
Revisiting bans on nuclear development and the planned shut downs/retirements of existing reactors;
• Developing fully integrated gas and electricity networks throughout Europe including pipeline interconnects, reversing or redirecting lines where feasible, and increasing storage of natural gas and oil;
• Building out LNG receiver facilities especially in places like Croatia to accept cargoes from a variety of suppliers;
• Reforming the highly inefficient and corrupt energy sector in Ukraine to reduce the vulnerability to Russian gas cutoffs to Europe and Ukraine;
• Removing the regulatory and physical bottlenecks to integrate fully Pan-European gas and electricity networks; and
• Conducting a crash assessment on how quickly rooftop solar and other distributed generation could reduce Ukraine’s vulnerability to natural gas curtailments.

For its part, the United States can provide regulatory, technical and financial assistance as well as encourage American companies (drawing on their experience in North American basins) to work with their European counterparts to develop unconventional energy resources.

Most importantly, we would be well advised to tamp down the public rhetoric and posturing and de-escalate the tensions currently surrounding the crisis unfolding in Ukraine before we either reach an impasse with only suboptimal outcomes or expand the crisis into a truly global one.

Frank A. Verrastro is senior vice president and James R. Schlesinger Chair for Energy & Geopolitics at the Center for Strategic and International Studies (CSIS). Charles K. Ebinger is director of the Energy Security Initiative and a senior fellow at the Brookings Institution. “The Geopolitical Realities of the Ukraine Crises, the Limits of U.S. Energy Assistance, and the Need to Tone down the Rhetoric” originally appeared on the CSIS website March 21.

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Greenhouse Gas Inventory May Not Reflect Full Scope Of Oil,Gas Emissions

March 25th, 2014 vaddison Posted in Uncategorized | Comments Off

By David Lyon, Environmental Defense Fund

The Environmental Protection Agency (EPA) recently released its draft inventory of annual U.S. greenhouse gas emissions. Reporting 2012 data, the inventory estimates methane emissions coming from natural gas and petroleum systems at around 7.6 million metric tons—that’s enough natural gas to provide energy to more than 7 million homes annually. This new estimate when compared with last year’s report, which estimates emissions for the 2011 calendar year, shows overall methane emissions from natural gas and petroleum systems are 1.2% lower.

Although this seems like good news, the new data is no cause for complacency, as it’s important to understand the cause of the changes which requires closer examination.

The draft inventory introduces some new methodological changes that reduce estimated emissions from previous years. The primary change was driven by the way EPA estimates emissions from gas well completions and workovers, the steps that follow hydraulic fracturing and clear liquids and sand from the well before production begins.

EPA’s previous calculation method first estimated the potential emissions from all well completions and workovers, assuming no emission controls were used, and then calculated actual emissions by subtracting estimated reductions resulting from compliance with state air regulations and from companies voluntarily participating in EPA’s Natural Gas STAR Program. The new method evolves the calculation to improve accuracy, using data from EPA’s mandatory GHG Reporting Program, to directly estimate emissions from wells that do not control emissions and those that utilize some combination of control technologies (which will become mandatory in 2015 for most natural gas wells).

Although the Reporting Program data better accounts for emission reductions from individual wells, EPA’s method for determining the number of overall well completions likely underrepresents total emissions from this source.

Co-producing wells: an overlooked emission source?

Another key issue is the way EPA estimates emissions from completions of oil-producing wells. Hydraulic fracturing is increasingly being used to develop new shale oil resources. Oftentimes, depending on the geology, shale resources can either be explored for oil or natural gas. Given today’s fuel prices, market forces are driving more onshore shale oil development. However, the inventory continues to base its emission estimates for these oil wells on data from the mid ‘90s pertaining to conventional, non-fractured oil wells. Several data sources—including the GHG Reporting Program, the UT study, and the Stanford Novim study—suggest that hydraulically fractured oil well completions have emissions more than a 100 times higher than the current estimate for conventional oil wells.

Fortunately, the same techniques that will soon be required to control completion emissions from natural gas wells can also be applied to many hydraulically fractured oil-producing wells (which we call “co-producing” wells, because they frequently produce both gas and liquids). In a white paper, we summarize the data we have collected on emissions from oil-producing well completions, and what they tell us about the potential to cost-effectively reduce emissions from these wells.

Good data, better outcomes

EPA’s Greenhouse Gas Inventory is a great tool for improving our understanding of the impact human activity has on climate change, and it underscores that there is an urgent need to mitigate methane emissions from the oil and gas sector. At the same time, it is important that the inventory appropriately characterizes all of the significant sources of methane from this sector.

Accordingly, EDF has submitted comments asking EPA to include estimated emissions from oil well completions with hydraulic fracturing based on recent data such as the GHG Reporting Program, the UT study, and our analysis of well production data. Because drilling activity has shifted more and more towards oil-producing formations, we estimate that emissions from oil well completions are similar in scale to gas well completions.

U.S. Petroleum and Other Liquids Supply, 1970-2040
Figure 1. U.S. Petroleum and Other Liquids Supply, 1970-2040 (Source: EIA)

It’s also critical that EPA regulations addressing emissions from the oil and gas sector keep up with our improved understanding of the methane inventory. Consistent with our findings on emissions from co-producing well completions, we’ve encouraged EPA to extend proven emission controls for well completions to oil and condensate-producing wells. These wells are largely unaddressed under EPA’s current New Source Performance Standards for the oil and gas sector, which only require “green completions” for wells that are drilled for the purpose of producing natural gas (read the UT study FAQ for more detail).

Reducing methane emissions from the oil and gas sector is critical to protecting human health and the environment from climate change, and deep reductions in methane emissions are necessary both to slow the near-term rate of climate change and to ensure that the use of natural gas in lieu of other fossil fuels yields net climate benefits. Data and cost-effective technologies needed to secure these urgently-needed emission reductions are available and it is imperative that we deploy them swiftly.

We’ve submitted comments to EPA to provide our suggestions and hope others will join us, as EPA is accepting comments on the draft inventory until March 26, 2014.

Tomás Carbonell and Peter Zalzal contributed to this post, which originally appeared on the Environmental Defense Fund’s website.

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EU Must Curb Its Reliance On Russian Gas

March 18th, 2014 vaddison Posted in Uncategorized | Comments Off

Bloomberg

After the bogus referendum March 16 in Crimea, Russian President Vladimir Putin can be increasingly confident that his annexation of Ukrainian sovereign territory will stand: The European Union (EU) and the U.S. lack the will and the means to stop it. The main questions now are whether a line can be drawn at Crimea and how big a price Russia will pay for its land grab.

The short-term response turns on sanctions and diplomatic pressure. The calculations here are unavoidably complicated, especially for the EU, because its economy is now so interconnected with Russia’s. Too bad. If Putin gets away with Crimea, Russia should be made to pay, and Europe is in the best position to extract a price. Otherwise Putin will be encouraged to go further.

For the longer term, the U.S. and (especially) the EU need to fundamentally rethink their economic relations with Russia – not to pile on the punishment but as a matter of simple prudence. There’s no need to cast Russia as an implacable Cold War enemy to understand with new clarity that it is not a reliable friend. That means changing any policies based on the misconception that Russia is a good global citizen.

Energy policy is especially crucial. Europe’s economies are far too dependent on Russian supplies of natural gas. Russia is the EU’s main supplier of natural gas, accounting for roughly 30% of the total. In Germany, where successive governments have made stronger economic ties with Russia, the figure is about 40%.

Putin has been more than willing to enable this dependence. Russia and Germany cooperated in building a direct pipeline under the Baltic Sea, for example, bypassing Ukraine’s pipeline system (and allowing Russia to tighten the economic screws on its neighbor). Many EU businesses are heavily invested, literally and figuratively, in the Russian energy business.

Breaking these links can’t be done cheaply, easily or all at once, but a patient strategy to diversify from Russian energy supplies is long overdue. It should have four parts: a stronger negotiating approach over existing supplies; new regional sources for natural gas; new infrastructure to allow delivery and distribution of natural gas in liquefied form; and alternative domestic sources of energy.

EU members currently negotiate gas prices with Russia bilaterally. Bigger countries get lower prices, an advantage they won’t wish to surrender – but Russia increases its market power by dividing its customers and discriminating among them. At a meeting last week, Polish Prime Minister Donald Tusk told German Chancellor Angela Merkel that the EU should negotiate with Russia as a bloc. It’s a good idea.

Next comes new sources of supply. The Caspian Sea region, central Asia and north Africa are capable of providing far more natural gas than they do now. Heavy investment, including in pipelines, will be needed to tap this potential. Europe’s economic and geopolitical interests lie in supporting those efforts.

In recent years, Europe has increased its imports of liquefied natural gas, mainly from north Africa – but there’s scope for much more. Thanks to its shale-gas boom, the U.S. could play a central role in supplying Europe with LNG. The U.S. is now the world’s biggest producer of natural gas, but the approvals process for exports and their supporting facilities is slow and costly. The economic case for speeding and simplifying this system was already compelling. Putin’s master class in intimidation makes the geopolitical case equally strong.

Europe has shale gas of its own – maybe a 25-year supply at the current rate of gas consumption – but it has been in no hurry to exploit it. A U.S.-style boom may be unlikely for reasons of geology and population density, but that’s no excuse for failing to examine the possibilities. And there are other paths to energy diversification. If the annexation of Crimea makes Merkel regret her country’s dependence on Russian gas, it should also make her wonder about her decision to close Germany’s nuclear power plants years ahead of schedule.

In a way, it all comes down to price. Europe’s energy policies have taken cheap Russian gas for granted. Among many other things, the events of the last month make it clear: Russian gas isn’t as cheap as it looks.

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Anti-Fracking Activists Are Not What They Used to Be

March 12th, 2014 vaddison Posted in Uncategorized | Comments Off

By Dave Quast, Energy In Depth

Activists have long been a part of America’s public policy discussions, advocating tirelessly for social change.

Over the years, environmental activists specifically have pushed for policy options that were pragmatic, responsive to real problems and rooted in some form of reality. They have advocated for clean air and clean water protections, and have fought to preserve funding for public parks across the country. These resources, when protected, clearly benefit all of us. The results have been mixed, of course, but there is no denying the fundamental seriousness of early environmentalists’ intent.

One such activist is current California Gov. Jerry Brown, who has always made environmental issues, including addressing climate change and pushing for more renewable energy, his top priority. He has frequently opposed industry — especially California’s oil companies — regarding, among other things, the Global Warming Solutions Act (AB 32) and the Low Carbon Fuel Standard.

How times have changed. All one needs to know about the fundamental un-seriousness of today’s radical environmental activists is captured in the slogan of the anti-fracking campaign of one such group: Oil Change International (OCI).

OCI has partnered with a laundry list of extremist groups including CREDO, Food & Water Watch and the Center for Biological Diversity claiming that there is a California politician who has blindly aligned himself with California’s energy industry, and has thus somehow abandoned reason and his lifelong commitment to environmental stewardship.

That politician? Gov. Jerry Brown, who — because he had the audacity to follow science and oppose an outright ban on “fracking” — has been dubbed “Big Oil Brown.”

OCI writes: “Jerry needs to pick a side: either he’s the climate champion he says he is, or he’s Big Oil Brown, champion of fracking and the oil companies.” Translation: If you don’t ideologically oppose a process that even the Obama administration has defended as safe, then you’re a sellout.

The fact is that Gov. Brown has listened to his scientific advisers, as well as scientists and regulators across the country, and recognizes that hydraulic fracturing is a fundamentally safe technology with manageable risks. As such, he and Democrats in the Legislature have decided that allowing fracking to continue in California, albeit with many more regulations, is consistent with their responsibility to jump-start the state’s economy and protect the environment.

Brown also knows that the United States leads the world in carbon dioxide emissions reductions because of the increased use of clean-burning natural gas. In fact, emissions are nearly at 1990 levels, which was the goal of California’s 2006 global warming law. Activists conveniently ignore this achievement, which would not have been possible without “fracking” unlocking a 100-year supply of domestic natural gas.

In fact, UC-Berkeley climate scientist Richard Muller said recently that environmentalists who oppose fracking are “making a tragic mistake.”

The governor also knows that every barrel of oil we produce in California is one less barrel we must import, often from countries with significantly fewer environmental protections than in California.

Additionally, by producing more oil domestically, tens if not hundreds of thousands of Californians will benefit with the creation of high-paying jobs. This is why President Obama’s energy and climate change adviser Dan Utech said recently: “It’s better to produce these things [oil and natural gas] here than import them.”

Sadly, activists could be heard yelling things like “we don’t want these new jobs!” at a series of recent public hearings around the state regarding the implementation of California’s new hydraulic fracturing regulations. Would the people of Kern County — where 97% of all “fracking” in California occurs, and where the unemployment rate is in double digits — agree?

Thankfully, the debate about banning fracking in California is over. A bill to impose a moratorium on the practice only garnered 24 votes in the 80-member Assembly last legislative session, a margin of defeat not unlike what the activists suffered in deep-blue Illinois.

We are better off today because of at least some of the efforts of old-school, serious environmental agitators. But for new-style fringe activists like OCI and its allies to suggest that California’s policymakers — particularly lifelong environmental leaders like Brown — intentionally gave succor to any industry merely because their policy prescription avoided shutting it down, is as preposterous as it is insulting.

This column was originally published by U-T San Diego.

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Fracking Doesn’t Threaten Russia’s Gas Power

March 5th, 2014 vaddison Posted in Uncategorized | Comments Off

By Leonid Bershisky, Bloomberg

It is an uncomfortable fact for European politicians professing resistance to Russia’s geopolitical assertiveness that their energy dependence on Russia is growing. In 2013, the Russian state-controlled natural-gas monopoly, Gazprom, increased its market share in Europe and Turkey to 30%, the company proudly announced. This share is bigger than the 2011 historic maximum of 27%. Gazprom’s exports to Germany increased by 21%, to Italy by 68% and to the UK by 54% in 2013.

While hydraulic fracturing – or fracking – of shale formations is helping the US achieve energy independence, giving it a freer hand in Middle Eastern policy, the expected effects of the shale revolution for Europe haven’t materialized. LNG from the Persian Gulf could have been diverted from the US, where demand has shrunk, to Europe. But in 2013, LNG supplies to Europe actually dropped: They mostly went to Asian markets where exporters could command higher prices. If the US manages to export LNG in significant quantities, its price will be roughly the same as what Gazprom charges, a little less than US $11 per million British thermal units, not counting delivery costs from ports to the heart of the continent, according to the International Energy Agency.

The US shale revolution, then, isn’t doing much to help Europe expand its range of energy sources. Sustainable energy subsidies are going out of fashion even in Germany: They are too much of a burden on industry, which already pays three times US rates for electricity. Only a shale boom of its own could help Europe out of this predicament. Or could it?

The Institute of Sustainable Development and International Relations at Sciences Po, the prestigious social sciences school in Paris, recently issued a policy paper saying that even in the US shale gas and tight oil have not had the touted effect on the economy, and that the EU shouldn’t count on unconventional extraction as a magic pill.

Thomas Spencer and his two co-authors from Sciences Po have calculated that unconventional oil and gas development in the US only added 0.88% to US gross domestic product between 2007 and 2012. Nor has the shale revolution done much to reduce the US’s manufacturing trade deficit, which increased from $662.2 billion in 2006 to $779.4 billion in 2012. According to the policy paper, gas-intensive sectors, such as basic petrochemicals, are responsible for only 1.2% of US GDP, and the increases in exports from these sectors have been a drop in the bucket.

The Sciences Po team points out that despite a steep fall in gas prices caused by the arrival of fracking, both household and industrial electricity prices in the US have kept rising. And natural gas prices will go up again, the paper predicts. “The dramatic decline of US natural gas prices does not appear sustainable in the longer term,” the document says, pointing to short-term factors that led to the price collapse, such as a limited export capacity and inelastic gas consumption. “Longer-term expectations of production costs for shale is situated closer to $6-10/MBtu,” according to the report. The high end of this prediction is close to Gazprom’s European prices.

All in all, the Sciences Po team predicts, the shale revolution will give the US 0.84% in GDP growth from 2012 to 2035 – not annually, but in total.

Europe, according to the policy paper, can’t even count on that much. The US drilled 17,268 exploratory natural gas wells between 2000 and 2010; Europe has only 50 such wells now. Science Po predicts that by 2035, shale gas will cover between 3% to 10% of its natural gas demand.

That still leaves Gazprom plenty of room on the European market. Besides, if it wanted to wage a price war on unconventional producers, it could. The Russian company’s production cost is about $1.5/Mbtu, which pipeline delivery to Europe roughly doubles.

It appears to many observers as if Russia has slept through the shale revolution, falling hopelessly behind the US Russian President Vladimir Putin was ridiculed for saying last year he did not “see much in the way of serious change for the global gas market.” If the Sciences Po experts are to be believed, Putin is reading the cards right, and Russia’s energy power in Europe faces no serious threats for the foreseeable future.

Any revolution is at least part hype, and the shale one is no exception. So far, its economic and geopolitical effects are in question, and large parts of the world are beyond the reach even of its theoretical influence. Europe is one example: No disruptive technology is likely to make Russia irrelevant here, and its virulent distrust of the West makes it a dangerous and unpredictable player. So far, the EU and the US have only fostered the hostility as if Russia could be written off. That is a mistake.

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States Must Contain Fracking’s Enormous Thirst For Water

February 25th, 2014 vaddison Posted in Uncategorized | Comments Off

By Bloomberg

Among the environmental worries posed by hydraulic fracturing, including the release of methane into the air and contamination of groundwater, one has recently escalated: the concern that the enormous quantities of water used in fracking will leave parts of the country parched.

In 2012, fracking consumed some 50 billion gallons of water – water that many communities can ill afford to spare. New practices can make fracking somewhat less thirsty, however. States should see that drilling companies are encouraged to use them.

Each fracking site needs 2 million to 4 million gallons of water, to create sufficient pressure to fracture oil- and gas-containing rocks deep underground. When fresh water is used, it may be diverted from other users, including farms, manufacturing plants and households. There’s not always enough to go around; 55% of the wells fracked since 2011 are in drought areas.

One way to minimize fracking’s drain on fresh water is to substitute, as much as possible, water that’s already been used to frack other wells. After fracking, 10% to 50% of the water flows back up through the oil or gas well and is typically disposed of through injection into deep wells, a practice that has been linked with minor but troubling earthquakes. If it is instead cleaned of chemical additives as well as metals and minerals from deep underground, it can be reused. Frackers can also use brackish water from aquifers or municipal and industrial wastewater. Some are even beginning to frack not with great quantities of water but with a foam that contains nitrogen, carbon dioxide and relatively small quantities of water. Some of these options even make fracking cheaper.

Regulators need to ensure these alternative practices are consistently adopted. Pennsylvania has the right approach. Before withdrawing water in that state, drillers must win approval for a water-use plan that discloses how much water a well will use, from where and what effect that will have on local sources. To be approved, these plans must include wastewater recycling.

Other states – including Kentucky, which exempts frackers altogether from its water-withdrawal rules, and Texas, which allows unlimited withdrawals from groundwater – should follow Pennsylvania’s lead.

By making approval for fracking contingent on responsible water practices, states can drive even greater innovation – perhaps to the point where frackers come to operate without using any water at all. Gasfrac, a Canadian company, has been using liquefied petroleum gas in gel form to fracture shale, which so far is relatively expensive. But as the technology improves – and water grows harder to come by – operators may find it to be the most attractive strategy.

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