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April update. Drilling soon to start in Tasmania.
Monday, Apr 09 2012 by GoldenAuras 0 comments
Malcolm Bendall (EEGC CEO) & Tim Baldwin (TXO CEO) have returned from several weeks of meetings in Korea with business partners, which my sources say went well.
Myself and other investors will be looking forward to several Press releases which will be out soon with the outcome of the Korea meetings and information on the mobilisation of oil rigs and other progress made.
April and May should be exciting months.
A note to other Investment readers: Be patient. Investors and General public are really the last to know about proposals for Licences, start dates etc… due to the fact that that there are many people involved; Business partners, Creditors, Local Government and other regulatory authorities. Press releases can not often reveal this information until transactions have been made or contracts signed as it could potentially jeopardise deals until they have been completed.
http://www.stockopedia.co.uk/content/april-update-drilling-soon-to-start-in-tasmania-65213/
Copied from advfn - for info
BLACK G0LD - 23 Feb'12 - 17:27 - 4219 of 4238 moderate post | add to banned list
Guys, where is the information that proves the Warrants expire on 10th March? My understanding is that they expire on 14th April 2012. That said, there is a big drive going on for people to exercise early. TXO have been ringing round. My sources tell me TB is going to Korea Monday and then onto Tasmania.
But it's now a possibility as it is being demobilised by CTP and not tied up long term as some had suggested.
Surprised there has been no comment on Central Petroleum releasing the Hunt Rig #3 yesterday. Maybe it will be on the way back to Tasmania.
I don't know if that is the plan but it seems like good timing given the recent timeline on expected drilling etc..
Hunt Rig #3 was used to do the original drilling at Bellevue #1 in 2008. So pretty relevant IMO.
Hunt Rig #3
ASX ANNOUNCEMENT & PRESS RELEASE ASX CODE: CTP
17 February 2012
TO: The Manager, Company Announcements ASX Limited
CONTACT: John Heugh +61 8 9474 1444
Rig Demobilisation
Central Petroleum Ltd (ASX:CTP) (“Central”) advises that the drilling of an appraisal well over the Surprise structure has been deferred pending the outcome of the planned Extended Production Test of the Surprise-1 RE H well and acquisition of 3D seismic over the Surprise structure.
Accordingly the Company will not be exercising the option to retain Hunt Rig #3.
John Heugh
Managing Director
Central Petroleum
TXO News Release 17 February 2012
TXO PLC
("TXO" or the "Company")
TXO PLC: EMPIRE ENERGY CURRENTLY APPLYING FOR EXPLORATION LICENSES
The Board of TXO Plc ("TXO") announces today that Empire Energy Corporation International ("Empire") (Pink Sheets: EEGC.pk) is applying for exploration licenses with the intent to develop identified Tasmania Basin black coal potential. TXO has a US$1.5m convertible loan note in Empire which gives the Company a call option to acquire a 19.9% equity interest in Empire (on a fully diluted basis) or be paid back in full.
Subject to shareholder approval of the amendment to TXO's investing policy at the forthcoming AGM, TXO will be awarded by Empire, in recognition of previous support and introductions, 10 per cent carried interest in the ordinary share capital in the Special Purpose Vehicle ("SPV").
Two Exploration Licence Applications over the Mt Lloyd Area have been submitted by Empire to the Director of Mines at Mineral Resources Tasmania. Both are Category 2 Minerals including Coal and Coal Bed Methane. The first covers approximately 250km2 of land in the Northern Mt Lloyd area of Southern Tasmania. The second covers approximately 250km2 of land in the Southern Mt Lloyd area of Southern Tasmania.
Tim Baldwin, Chairman of TXO commented "We are excited that TXO shareholders will be able to directly benefit from any upside from Empire's proposed drilling and further seismic surveys to prove up possible resources and reserves to a Joint Ore Reserves Committee (JORC) code reporting standard on the license areas."
For further information, please contact:
TXO PLC
Tim Baldwin, Executive Chairman +44 (0) 20 7518 4300
Beaumont Cornish Limited
Roland Cornish and James Biddle +44 (0) 20 7628 3396
This information is provided by RNS
From advfn - TXO at OilBarrel Conference
911chris - 16 Feb'12 - 16:01 - 4001 of 4005 moderate post | add to banned list
Just got back from oil barrel conference - TXO gave an interesting presentation. T Baldwin stated that he believed the funds had started to arrive into Empire account from NBD and that he had personally been invited by NBD to meet with them in Korea the week after next.
Interestingly he also mentioned that TXO was going to look into developing local coal resources for the international market by applying new technology to reduce the transportation costs of the coal.
Seems like there might be more to come and there was a lot of interest which might explain the rise in the share price soon after his speech finished.
freedosh - 16 Feb'12 - 16:13 - 4005 of 4006 (premium)
OK I was there as well. Don't think a write up is important (not much new from platform) but read 911's words carefully. Something was said that is not in the public domain, as of yet.
Malcolm Bendall was there - interesting character.
I cannot emphasise too much how excited I am by the near future here and at EEGC
freedosh
911chris - 16 Feb'12 - 16:16 - 4006 of 4006 moderate post | add to banned list
Pem-
TB - confirmed that GBG had its licence and that they will now start to supply marine lubricants and develop out a quay side facility in Freeport. He showed some video footage of the area and it looked like a busy port. He said the plan was to recycle oil to fuel as there is demand for such from the power stations on the island. He also mentioned that Morgan Oil USA was hoping to undertake horizontal drilling in Kentucky that would push the production well above 40bopd.
He brushed over east africa oil on the basis that it was commercially sensitive at the moment.
As regards empire - they had a dr clive burrett who was over from Tasmania and he confirmed that they were read to start drilling and the drilling contractors were on standby. In the Q&A section he was asked when would drilling start he said as soon as possible before the harsh weather comes in. So fingers crossed could happen sooner rather than later!!
Hope this helps
TXO PLC
20 October 2011
TXO PLC
("TXO" or the "Company")
ADDITIONAL INVESTMENT
TXO RECEIVES REPAYMENT OF LOAN TO GRAND BAHAMA GROUP AND ACQUIRES A FURTHER 4.3% SHAREHOLDING IN GRAND BAHAMA GROUP
The board of TXO Plc ("TXO" or "the Company") announces that it has received full repayment of the unsecured GBP112,500 loan made to the Grand Bahama Group Limited ("GBG" or the "Group").
The Company also announces that it has made an additional investment in the Group. The Company has purchased a further 43 Ordinary Shares in the share capital of the Group for an investment of GBP212,500, representing a further 4.3% shareholding. This further investment takes the number of ordinary shares held by TXO to 143 and a shareholding of 14.3% in the Group. Further information on the Group is set out in the announcement made on 30 June 2011.
In addition, Morgan Oil is expecting to receive a report on the recoverable reserves of the wells in Kentucky, USA and the board of Morgan Oil Marine are expecting further news on the Port Authority Licence in the Bahamas. Further announcements will be made in due course.
TXO Plc is also securing funding for the completion of the Empire Energy International investment.
For further information, please contact:
TXO PLC
Tim Baldwin, Chairman +44 (0) 771 287 2820
Beaumont Cornish Limited
Roland Cornish and James Biddle +44 (0) 20 7628 3396
This information is provided by RNS
The company news service from the London Stock Exchange
Growth Company Investor Article
Companies: TOM
16/04/2008
AIM-quoted TomCo Energy could have half of 100 million barrels of oil in Israel’s Heletz field, suggests chief executive Howard Crosby.
Crosby, an American resources entrepreneur claiming recent multi-million successes with the Cadence and High Plains Uranium ventures, says the AIM-quoted company is this year re-working eight existing wells in the southern Israeli project, first worked 50 years ago with old technology. He hopes this way to lift oil production nearly fivefold to 300 barrels a day, while arguing the company’s potential oil shale reserves in Utah could be in the order of 230 million barrels.
Citing acquisition costs of $10 to $11 a barrel and lifting costs below £5 a barrel – against current levels well above £$110 – Crosby says Isle of Man-based Tomco has so far raised £2 million in shares and convertibles. He contends management and friends hold sway over 45 per cent of the the company, which is paying £500,000 towards Heletz and is committed to put up another £2.25 million over three years to earn its half share in the project.
Crosby argues that Heletz, which is near some major gas finds, has ‘blue sky’ potential in as-yet-untested deeper reserves, which he opines could exceed 100 million barrels. But he says TomCo, which lost £1.2 million in the year to last September, sees even greater potential in its Utah commercial oil shale leases, granted by the state.
According to Crosby, the company paid the equivalent of 10 cents a barrel for shale oil in place in the Utah property and now hopes to do deals with a floor price of $4 to $5 a barrel. He says new treatment processes, devised by Shell, have transformed the viability of hitherto uneconomic oil shale projects.
The stockmarket has as yet been unresponsive to TomCo’s charms. Floated at 25p eight years ago, the shares fell to 0.14p in 2005 and now trade at 1.73p, valuing the company at £9.3 million, where their appeal is speculative
News : Drilling Programme
Tomco Energy Drilling Programme
RNS Number:6346J
TomCo Energy PLC
11 December 2007
TomCo Energy Plc ("TomCo" or the "Company")
TomCo (TOM.L) is pleased to announce an agreement with Mark III Energy Holdings LLC, its 50 per cent. joint venture partner at the Abel leases on the Hull Salt Dome oil field, Liberty County, Texas, and at the Saratoga leases on the Saratoga Salt Dome oil field, Hardin County, Texas. The agreement has the objective of drilling up to six new production wells after a comprehensive
Production Optimization Study has been completed. The study will build on previous reports and studies and develop a better understanding of the oil bearing sands. The study will be used by the joint venture to generate economically attractive forward programmes to increase current oil production from these leases.
The Hull and Saratoga Salt Dome oil fields are located in East Texas where numerous similar oil fields have been developed over the last eighty years. These oil fields have characteristically had multiple oil bearing reservoirs and excellent reservoir characteristics.
TomCo has instructed GeoExperts, a Houston based Consultancy Company, to carry out the Production Optimization Study of the two leases, with an estimated completion date in the First Quarter 2008. GeoExperts will also report on the viability of drilling a water disposal well which can be commercially exploited with other producers in the area in addition to joint venture use.
Howard Crosby CEO said: "This programme, to increase our production at these two leases represents an opportunity to fully exploit these assets and cement our relationship with a well known fast growing local oil operator with whom we are also examining a number of other potential oil propositions."
This announcement has been read and approved by GeoExperts of Houston, Texas, USA an independent firm of Geologists.
Enquiries:
TomCo Energy Plc +44 (0)20 7808 4857
Stephen Komlosy
Strand Partners Ltd. +44 (0)20 7409 3494
Warren Pearce
Bankside Consultants Ltd. +44 (0)20 7367 8888
Simon Rothschild
This information is provided by RNS
The company news service from the London Stock Exchange
Hi Noli
Market whispers suggest will be moving along nicely again soon...
Tomco Energy Holding(s) in Company
RNS Number:8397I
TomCo Energy PLC
30 November 2007
TomCo Energy Plc
('TomCo' or 'the Company')
Holding in Company
TomCo received notification on 28 November 2007, pursuant to the FSA Disclosure and Transparency Rules, that Douglas Wright has an interest in 17,775,000 ordinary shares of 0.5p each in the company. This represents approximately 4.01 per cent. of the Company's issued ordinary shares.
For further information, contact:
TomCo Energy Plc +44 (0)20 7808 4857
Stephen Komlosy
Strand Partners Ltd. +44 (0)20 7409 3494
Warren Pearce
Bankside Consultants Ltd. +44 (0)20 7367 8888
Simon Rothschild
This information is provided by RNS
The company news service from the London Stock Exchange
http://www.investegate.co.uk/Article.aspx?id=200711300730058397I
Oil shale may finally have its moment...
In a dusty corner of northwestern Colorado, an energy of the future is beginning to look like the real thing. Can oil shale work? Fortune's Jon Birger reports.
FORTUNE Magazine
By Jon Birger, Fortune senior writer
November 1 2007: 11:12 AM EDT
(Fortune Magazine) -- Touring a drilling site on a dusty mountain plateau above Rifle, Colo., Harold Vinegar stops, grins and then announces out of the blue, "I love that smell!"
No, the Royal Dutch Shell chief scientist is not referring to the crisp fragrance of the high desert air or the conifer scent wafting from the nearby stand of evergreens. Rather, it's the faint, asphalt-like aroma of oil shale - a sedimentary rock rich in kerogen, a fossil fuel that is now the focus of Shell's single biggest R&D investment.
Vinegar is the energy industry's leading expert on the complex petroscience of transforming solid oil shale into synthetic crude - a liquid fuel that can be refined into diesel and gasoline. The breakthroughs this 58-year-old physicist has achieved could turn out to be the biggest game changer the American oil industry has seen since crude was discovered near Alaska's Prudhoe Bay in 1968.
If that sounds like hyperbole, then consider this: Several hundred feet below where Vinegar is strolling lies the Green River Formation, arguably the largest unconventional oil reserve on the planet. ("Unconventional oil" encompasses oil shale, Canadian tar sands, and the extra-heavy oils of Venezuela - essentially, anything that is not just pumped to the surface.)
Spanning some 17,000 square miles across parts of Colorado, Utah and Wyoming, this underground lakebed holds at least 800 billion barrels of recoverable oil. That's triple the reserves of Saudi Arabia.
The reason you probably haven't heard about the Green River Formation is that most of the methods tried for turning oil shale into oil have been deeply flawed - economically, environmentally or usually both. Because there have been so many false starts, oil shale tends to get lumped with cold fusion, zero-point energy, and other "miracle" fuels perpetually just over the horizon.
"A lot of other companies have bent their spears trying to do what we're now doing," Vinegar says of his 28-year quest to turn oil shale into a commercial energy source. "We're talking about the Holy Grail."
Unlike the Grail, though, Shell is convinced that oil shale is no myth and that after years of secret research, it is close to achieving this oil-based alchemy. Shell is not alone in this assessment. "Harold has broken the code," says oil shale expert Anton Dammer, director of the U.S. Department of Energy's Office of Naval Petroleum and Oil Shale Reserves.
Vinegar has developed a cutting-edge technology that, according to Shell, will produce large quantities of high-quality oil without ravaging the local environment - and be profitable with prices around $30 a barrel. Now that oil is approaching $90, the odds on Shell's speculative bet are beginning to look awfully good.
Shell declines to get too specific about how much oil it thinks it can pump at peak production levels, but one DOE study contends that the region can sustain two million barrels a day by 2020 and three million by 2040. Other government estimates have posited an upper range of five million. At that level, Western oil shale would rival the largest oilfields in the world.
Of course, considering the U.S. uses almost 21 million barrels a day and imports about ten million (and rising), even the most optimistic projections do not get the country to the nirvana of "energy independence." What oil shale could do, though, is reduce the risk premium built into oil prices because energy traders could rest easy knowing that the flow of oil from Colorado or Utah won't ever be cut off by Venezuelan dictators, Nigerian gunmen or strife in the Middle East. In a broader sense, U.S. energy security lies in diversity of supply, so enhancing domestic sources is appealing.
Oil shale has one other big appeal: It's not vulnerable to the steep depletion rates that have afflicted other big oilfields. Alaskan oil production is now 775,000 barrels a day, down from its peak of two million in 1988. In contrast, there's enough oil shale to maintain high production levels for hundreds of years. "Companies just aren't discovering new Prudhoe Bays anymore," says Bear Stearns oil analyst Nicole Decker, who thinks Shell has hit on a breakthrough technology. "This could be very significant - certainly bigger, to our knowledge, than any new discoveries that might be available globally."
Vinegar has been visiting northwest Colorado since 1979. For most of those years, his friends and co-workers back in Houston, and even his children, had no idea what he was doing there. They would have been even more mystified had they known that this Brooklyn-raised, Harvard-educated Ph.D.- a man who looks about as outdoorsy as Alan Greenspan in hiking boots - spent many of the project's early days camped out in rough terrain miles from the nearest motel.
The other side of carbon trading
But now the veil of secrecy has lifted. With some 200 Shell (Charts) oil shale patents already filed and approvals needed from Colorado and the U.S. Department of the Interior to proceed with commercial production, Shell knows it has to make the public case for developing the country's oil shale potential.
So after months of negotiations, Shell and Vinegar agreed to give FORTUNE an exclusive look at a new technology - inelegantly dubbed the In Situ Conversion Process, or ICP - that could vindicate Shell's 28-year, $200 million (at least) bet on oil shale research.
In a nutshell, ICP works like this: Shell drills 1,800-foot wells and into them inserts heating rods that raise the temperature of the oil shale to 650 degrees Fahrenheit. To keep the oil from escaping into the ground water, the heater wells are ringed by freeze walls created by coolant piped deep into the ground; this freezes the rock and water on the perimeter of the drill site. Eventually the heat begins to transform the kerogen (the fossil fuel embedded in the shale) into oil and natural gas. After the natural gas is separated, the oil is piped to a refinery to be converted into gasoline and other products
In essence, ICP simply accelerates Mother Nature's handiwork. Fifty million years ago, large swaths of what is now northwest Colorado, northeast Utah, and southwest Wyoming were covered by two great lakes. Algae, leaves and other prehistoric life forms sank to the bottom, leaving behind a thick layer of organic muck. Starved of oxygen, these sediments could not decay, and periodically they would be covered and compacted by sand and other rock deposits. Over millions of years, the pressure exerted by the weight of the rock layers transformed the organic layers into kerogen.
In its purest form, kerogen looks like ordinary black rock. In most parts of the Green River Formation, however, it exists as thin black or dark-gray stripes between lighter-colored layers of limestone or sandstone. Kerogen is an oil precursor. So given a few million more years, those layers would morph into an oozing crude. Of course nobody wants to wait that long, which is why there has been no shortage of attempts over the years to make use of Western oil shale. The Ute Indians called it "fire rock" and burned it for heating. Attempts to commercialize oil shale began in the early 20th century and accelerated during the 1970s Middle East oil crisis, when the Carter administration began pouring big money into synthetic fuels.
Problem was, the prevailing production process - known as surface retorting - was dirty and inefficient. Federal subsidies masked the problems, encouraging companies to build businesses they never would have created on shareholders' dimes. When oil prices collapsed, so did the economic rationale for shale oil. The day Exxon left town in 1982, turning some communities into ghost towns, is still remembered in northwestern Colorado as "Black Sunday."
The basic problem with surface retorting was that shale had to be mined, transported, crushed and then cooked at 1,000 degrees Fahrenheit. Not only were there toxic waste byproducts, but the oil thus produced had to be purified and infused with hydrogen before it could be refined into gasoline and other products. Vinegar may be a physicist by training, but he thinks like an MBA, and to him such a labor- and energy-intensive process reeked of bad economics.
Wouldn't it be better, he thought, if Shell could extract a liquid that could be pumped and pipelined instead of a solid that had to be mined and trucked? Upon visiting a Shell surface-retorting site for the first time in 1979, he came to a quick, life-changing conclusion: "Wow, we're going to have to do this in situ."
The term "in situ" is Latin for "in place." In an engineering context, it means liquefying the oil shale while it is still underground. That is what Vinegar set out to do. The Eureka moment came in 1981. During a field experiment in Colorado, Vinegar and his colleagues set up camp on a patch of Shell-owned land where the oil shale was close to the surface. Then they drilled seven 20-foot wells within a 36-square-foot zone.
They inserted heating rods into six of the holes and positioned the seventh as a production well. "It was a very low-budget operation," Vinegar chuckles. "The oil would drain into the production well, and every morning we used a fishing pole with a little bailer on the bottom to get it out."
Most of the oil Vinegar and his colleagues collected was, in his estimation, "gunky." However, Vinegar noticed that when temperatures in the ground were still comparatively low, the oil recovered was light and pure. "It was almost optically clear, and that fascinated me," he says. "What was it that allowed us to make this beautiful-quality product early on but not later on?"
The truth about oil
Answering that question took years of lab work, but the company dug in. "Shell continued doing research, even in the 1980s when most everyone else quit," says Glenn Vawter admiringly. Vawter, a veteran of Exxon's failed oil shale operation, is now an executive with an oil shale startup, EGL Resources. In 1998 - when the price for West Texas crude crashed to less than $15 a barrel - Shell spent $799 million on R&D; by comparison, the larger Exxon Mobil spent $549 million.
In 2006, Shell spent $855 million on R&D to Exxon (Charts, Fortune 500)'s $733 million. Both Vinegar and Shell Vice President for Unconventional Production John Barry confirm that oil shale is now the biggest piece of the company's R&D budget, though neither will specify exactly how much has been spent. One source briefed by Shell officials puts the total oil shale R&D investment at north of $200 million.
Shell has long been known for its science. It invented the first semi-submersible offshore drilling rig and pioneered the use of steam flooding to maximize oil well production; it's also the industry leader in natural-gas-to-liquids (GTL) technology. Much of its research originates at its Bellaire Research Center in Houston, where Vinegar has spent most of his career.
The lab's most famous alumnus is the late M. King Hubbert, of Hubbert's Peak fame. Hubbert was the first geologist to understand the mechanics of oilfield depletion and the first to make a reasonably accurate assessment of recoverable oil reserves - initially for the U.S. and later for the world. The founding father of peak-oil theory, Hubbert predicted that U.S. production of conventional oil would peak around 1970 (he was right) and that global oil production would taper off after 2000 (he was wrong, though by how much is the topic of heated debate).
Neither Vinegar nor Barry wants to get drawn into a discussion of peak-oil theory. They simply state that the rapid growth in worldwide oil demand necessitates the development of unconventional oils. (Shell has also invested in biofuels and solar power.)
That said, it's no coincidence the oil company Hubbert once called home is the one now making the biggest bet on unconventional oil - not only oil shale but GTL and Canadian tar sands too. Jim Spehar, a former Colorado community-relations consultant for Shell, remembers company scientists and executives talking at length about peak oil - and about oil shale as a potential "bridge" between conventional oil and renewable energy - when he worked for Shell in the late 1990s.
"They definitely believed that the conventional stuff being pumped out of the ground was a declining resource," Spehar says.
Vinegar and the Shell team of chemists, engineers and physicists eventually figured out why the oil they collected early in that 1981 field test was so light and clean and the later samples so dark and dirty. They found that a slower, lower-temperature process - 650 degrees Fahrenheit, versus the 1,000 degrees required in the retorting process - allows more of the hydrogen molecules that are liberated from the kerogen during heating to react with carbon compounds and form a better oil.
This was a crucial discovery, because one of the hallmarks of a light oil - the most valuable kind because it costs less to refine - is its elevated hydrogen content.
Best of all, Shell was able to replicate the lab results in several field tests; the most recent one, in 2005, yielded 1,700 barrels of light oil. In that test, carefully engineered heating rods were inserted several hundred feet into the ground in order to gradually raise the temperature of the oil shale to 650 degrees Fahrenheit. Now Shell had a proven technology that it believed could produce a barrel of oil for $30.
It also knew it could recover a lot more oil than surface retorting did, since the heating rods and wells reach the entire deposit, not just the oil shale close enough to the surface to be mined. There was just one problem: Except for a few small patches of land that it owned, it didn't have access to the deposits. More than 80 percent of U.S. oil shale is on federal property, including nearly all the most desirable drilling sites. And no mechanism existed for the U.S. Bureau of Land Management to lease this land for oil shale exploration or production.
The Energy Policy Act of 2005 changed that. It required the BLM to set up a process for granting "research development and demonstration leases" to companies seeking to develop oil shale. Under the terms of the RD&D leases, companies whose applications pass muster are given a ten-year lease on 160 acres.
They are then expected to prove the commercial and environmental viability of their process, and if they do, they will be granted a second RD&D lease for an additional 5,100 acres. (Five thousand acres may not sound huge, but Shell believes that the most promising parts of the Green River Formation could yield more than one million barrels per acre using ICP.) Shell applied for and received three RD&D leases; EGL, Chevron (Charts, Fortune 500), and Alabama-based Oil Shale Exploration Co. got one each.
Jeremy Boak, a researcher at the Colorado School of Mines and the organizer of an annual oil shale conference there, believes Shell's oil shale technology is far ahead of the competition. Indeed, when FORTUNE met last spring with Chevron's oil shale team and its partners from the Los Alamos National Laboratory, the Chevroners indicated they were still fine-tuning the production process outlined in their lease application.
This involves fracturing the oil shale using explosives or high-pressure carbon dioxide, and then decomposing the kerogen into liquid fuel using supercritical CO2 or other solvents. The idea has not been field-tested yet.
Though there's no shortage of oil companies now looking to get into oil shale, Vinegar is confident that Shell's 200 oil shale patents, which cover everything from the composition and spacing of the heating rods to the molecular structure of the light oil ICP creates, will make it difficult for a competitor to come up with a competitive in situ process. (Indeed, there was some griping at the recent School of Mines conference about the breadth of Shell's patents.) Even so, it will probably be at least 18 months before Shell breaks ground on its first RD&D project and years before the oil hits market. The reason for the delay: another test.
Because there's no mining and because most of the action occurs underground, ICP is more environmentally benign than surface retorting or even tar sands production in Canada. But one big challenge is preventing the oil from leaching into ground water. Vinegar's solution was to create an impenetrable "freeze wall" of frozen rock and ice around the perimeter of the heating and production wells.
On a football-field-sized parcel of its own land, Shell is spending an estimated $30 million on a test that involves drilling 150 well bores and filling them with coolant in order to freeze surrounding rock and water to a temperature of minus-60 degrees Fahrenheit. "I do realize," says Vinegar, "that the whole idea of heating an area [to 650 degrees Fahrenheit] and simultaneously freezing around the circumference to keep the water out sounds almost like science fiction." Regardless, the freeze wall passed a smaller-scale test in 2004, and Vinegar says everything is proceeding as expected with the latest one.
All this cooling and heating, of course, consumes energy. Can it possibly be worth it? Yes, says Vinegar, who estimates ICP's ratio of energy produced to energy consumed will range from 3-to-1 to 7-to-1, depending upon the scale of the project. Moreover, the power needed to perform the heating and cooling will be generated entirely from natural gas produced onsite by the ICP process. Shell plans on building its own large power plant and is exploring ways to sequester any CO2 produced.
$90 oil won't kill the bull
Water is another worry. ICP uses a lot of water, mainly to refine the oil and purify the natural gas. (Shell plans on building a refinery onsite, which is news in itself: It would be the first new refinery built in the U.S. in 30 years.) Shell appears to be on solid legal footing with its water plans, as it owns senior rights for local river water.
And some of the water it intends to utilize will be salinated water pumped from deep aquifers that are not part of the conventional water supply. Nevertheless, the potential for political backlash remains high, given that this is a part of the country where water is scarce and fights over water rights get nasty. "It will certainly be an issue," says former Rifle mayor David Ling. "There's an old expression around here: We talk over whiskey and fight over water."
The last thing Shell wants is a fight with Coloradans. The 2005 energy act set up some guidelines for commercial leasing in addition to the RD&D program. Once Shell completes an environmental-impact report, presumably by 2008 or 2009, the Department of the Interior is expected to consult with the states to gauge whether there's sufficient support to proceed. Thus far, Colorado Governor Bill Ritter has been cool to the idea without damning it altogether.
In a September letter to a DOE panel exploring ways to expedite oil shale production, Ritter - a Democrat who took office in January - cautioned that "proposed oil shale development overlaps areas with increasing tourism and recreational opportunities. Oil shale leasing on top of this existing network of energy development and changing land uses will put more pressure on an already fragile ecosystem and public temperament."
Ritter also asserted Colorado's right to regulate any in-state oil shale projects, though his letter did hint at a possible compromise, one that (surprise, surprise) boils down to money: "Bonus lease payments from federal leases for local government facilities and services [would] help mitigate impacts to local communities and build public acceptance for oil shale developments."
PetroChina begins planning $9B IPO
At the moment, the greens have been quiet on oil shale, perhaps because ICP is an upgrade over the former method. (Shell says its reclamation methods will restore land to its former appearance.) If you ask environmentalists, they do raise objections. "All the information we have points to industrial oil shale development as an enormous threat to our environment and a huge backward step," says Amy Mall, a senior policy analyst based in Boulder with the Natural Resources Defense Council.
There is no question that any large-scale oil shale development would dramatically affect the area, and the problem of how to mitigate greenhouse gas emissions has not been solved. That said, opposition to oil shale is nowhere near as loud and organized as the fight to stop drilling in Alaska's Arctic National Wildlife Refuge. Northwestern Colorado is certainly scenic - high desert plateaus interspersed with lush river valleys - but it's no ANWR.
Around Rifle (pop. 6,800), people seem at peace with Shell's oil shale plans, says Ling. There's already a thriving natural-gas industry in the region, so the idea of digging for oil doesn't give locals the shivers the way it would in more touristed, populated parts of the state. All that being said, once Shell gets closer to commercial production - Vinegar says it will be no sooner than 2015 - the politics will surely get prickly.
Oil: No longer a heavyweight
Shell insists that it has no beef with Governor Ritter's desire to proceed slowly. Even so, it's not leaving anything to chance. Shell has a public relations team devoted to oil shale and, in a shrewd move, the company has hired former U.S. Secretary of the Interior Gale Norton as an in-house lawyer. The stakes are huge. Assuming only $20 in profit for each barrel produced (at today's inflated oil prices, it would be more like $50), 300,000 barrels per day would add $2.2 billion to Shell's annual pretax profits. And three million barrels a day would be worth $22 billion.
It could be decades before Shell hits the really big numbers, if it happens at all. The logistics are daunting. It has taken the tar sands industry of Canada almost 30 years to reach its current production of about a million barrels a day (although it could be double that by 2010).
A mature oil shale industry might employ tens of thousands of workers in sparsely populated parts of Colorado, Utah and Wyoming - and that doesn't include the indirect employment from shop, restaurants and other businesses serving oil companies and their workers. "There's a real question of how we manage that kind of development," says Dammer of the DOE.
While it waits for its latest freeze wall to freeze and for the BLM to grind its way toward some sort of commercial leasing program, Shell is exploring other applications for ICP. It is negotiating with Jordan to test it on that country's oil shale reserves and investigating whether ICP can produce oil from Canadian tar sands - in which Shell also has major investments - more efficiently than current methods.
For his part, Vinegar's attention is focused squarely on Colorado. "So many Americans have no idea that they're sitting on a resource several times the size of Saudi Arabia's," he says. "The fact is that it's entirely possible to produce this stuff. Our technology works. There's no doubt about it."
- Telis Demos, reporter associate, contributed to this story. Top of page
http://money.cnn.com/2007/10/30/magazines/fortune/Oil_from_stone.fortune/index3.htm
Oil Shale: The Future of U.S. Energy Security
Posted on: Friday, 16 November 2007, 06:00 CST
By Henry, Darrell A
Lobbyists make their case in Washington against pending energy bill provisions. Darrell Henry
The Western Business Roundtable, a group of diverse business executives operating in the West from oil, gas and mining, to agriculture to engineering and utilities, recently hosted a briefing in Washington, D.C, for more than 60 representatives of Congressional offices on the tremendous potential of oil shale. The roundtable was also there to lobby against provisions in the looming energy bill that could slow oil shale and other fossil energy development.
The roundtable works on a variety of issues, including economic development, environmental protection, regulatory reform, energy policy, public lands use, waste management, and air and water quality.
This article is a summary of the Western Business Roundtables position on oil shale and its presentations by Darrell Henry of the Roundtables Washington, D.C, office; Jim Bartis of the Rand Corp.; Scott Stewart of Shell Unconventional Resources; and Jim Bunger, an independent oil-shale consultant.
THE POTENTIAL
While oil shale occurs in much of the world, the western United States is home to the world's largest deposits. Most oil shales are fine-grained sedimentary rock containing high amounts of organic matter from which oil and gas may be extracted via a distillation (heating) process.
Oil shale was formed millions of years ago by the deposition of silt and organic debris on lake beds and sea bottoms. During time, heat and pressure transformed the materials into oil shale in a process similar to that which forms oil; however, the heat and pressure were not as great. Oil shale can contain enough oil to burn without additional processing, so it is also known as "the rock that burns."
Total world resources of oil shale are estimated at 2.6 trillion barrels of oil, with the Green River formation in Colorado, Utah and Wyoming containing an estimated 1.2 trillion to 1.8 trillion barrels- the largest deposits in the world.
Even by conservative estimates, there are 800 billion barrels of recoverable oil from oil shale in the area, an amount three times greater than the proven oil reserves of Saudi Arabia.
INCREASED DOMESTIC ENERGY SECURITY
Energy independence is essential to preserve America's economic strength and national security. A recent report by the U.S. Department of Energy is the latest reminder that reducing our dependence on foreign imports of oil and refined products is essential to achieving the energy security objective.
Import reductions can be achieved in two fundamental ways: by reducing demand for oil through conservation and efficiency, and increasing production of fuels from domestic resources, including alternatives, biofuels and unconventional fuels. Oil shale has the potential to increase domestic energy security and make the U.S. less reliant on foreign sources of energy.
"The disturbing irony is that the world epicenter of anti- American hatred and terror is also the epicenter of our number one source of energy," said former New York Governor George Pataki.
In public opinion poll after poll, an overwhelming majority of citizens-nearly 85%-express strong support for weaning the U.S. from increasing foreign energy addiction. They want America to be as energy independent as possible. Soon, new American technologies can help Western oil shale do just that.
21ST CENTURY TECHNOLOGY
The greatest challenge to realizing the vast potential of oil shale in Colorado, Utah and Wyoming has been technology, extracting the resource in an economically viable and environmentally responsible way. With U.S. demand for petroleum products topping 20 million barrels per day, oil shale could be used to meet a quarter of that demand-800 billion barrels of recoverable resources, which would last more than 400 years.
A new era has begun for Western oil shale. We are closer to finding viable techniques for extracting the resource in an economically feasible and environmentally responsible way, with cutting-edge research and development under way by private companies in the region.
Oil shale must be mined and processed to generate oil similar to that pumped from the ground, but extracting oil from oil shale is more complex than conventional oil recovery and historically, more expensive. There are several methods to extract oil from shale; some are advancements to traditional techniques while others are being tested for the first time in the Green River formation.
Some companies are using new technology to improve on the traditional method of accessing oil shale. Oil shale is first mined and then heated to a high temperature (retorting); the resulting liquid is then separated and collected.
An alternative experimental process is referred to as "in-situ retorting." This involves heating the oil shale while it is still underground and then pumping the resulting liquid to the surface.
Shell Oil Co. has U.S. Bureau of Land Management research and development leases and is moving stage-by-stage to prove up and resolve the issues around extraction of shale through a proprietary process known as "thermally conductive in-situ conversion." Shell has carried out a small field-test, the Mahogany Demonstration Project South, on its private property in Rio Blanco County, Colorado, using an in-ground heating process to recover oil and gas from the shale formation.
The process involves heating underground oil shale using electric heaters placed in deep vertical holes drilled through a section of oil shale. The volume of oil shale is heated during a period of two or three years until it reaches 650[degrees]F to 700[degrees]F, at which point oil is released from the shale. The released product is gathered in collection wells positioned within the heated zone.
The field results have given confidence in Shell's insitu conversion process. A commercial decision on using this technology is anticipated early in the next decade, though possibly later depending on the sequence and outcome of research activities.
THE EFFECT OF EPACT 2005
Without the oil-shale provisions in the Energy Policy Act of 2005 (EPACT 2005), federal oil shale land would remain unavailable to the private sector, as it has since 1930 when President Herbert Hoover issued Executive Order No. 5327, withdrawing oil shale from leasing.
Even though President Harry S. Truman issued Executive Order No. 10355 in 1952, authorizing the Secretary of the Interior to rescind the Hoover order and lift the moratorium, to date it has not been lifted. (Limited leasing agreements in the 1970s were "prototypes" constructed so as not to have the effect of lifting the moratorium.)
With EPACT 2005, Congress provided clear direction in federal energy policy by instructing the Department of the Interior to develop a commercial leasing program and lift the leasing moratorium. With the exception of Shell, which is operating on private property, there has been no significant money put into oil- shale development on federal land since the prototype program in the 1970s.
EPACT 2005 was passed in August 2005, prior to the deadline for application of the leases in September 2005, and it is generally agreed among applicants and observers that it was the passage of EPACT 2005 and the prospect of obtaining additional contiguous acreage that generated enthusiasm for the experimental lease applications.
Some members of Congress wish to restore the barriers that have been in existence for nearly a century. If Congress succeeds in re- enacting barriers, we can expect the following:
* America's commercial oil-shale production will continue to be sidelined until the federal government provides clarity in its regulatory regime and leasing program;
* industry, and, more importantly, Wall Street, will perceive the proposed legislation as hostile to oil shale. This is a dangerous direction and could slow or halt any investment until favorable government policy is expressed;
* current lessees are likely to be discouraged from making large investments. In the case of the Utah lease, the 5,120-acre preference may not be sufficient to support a full-scale operation. Without a clear path to development, investors prudently will likely hold back from investing further in oil shale; and
* loss of oil shale as one of our domestic resources will exacerbate a future supply crisis. As we've seen from hurricanes Katrina and Rita in 2005 and the conflicts in the Middle East, the U.S. is highly vulnerable to supply disruptions, and with continued competition for the world's oil supply from China, India and other burgeoning economies, there is some urgency to begin the process.
Lawmakers should recognize the danger of removing this vast resource (richer and larger than the Alberta oil sands) from our domestic energy base.
The lack of clear government policy has inhibited development of this domestic resource for nearly a century. The first serious attempt with the passage of EPACT 2005 to remove century-old, government-induced impediments to development of this resource is in jeopardy because of legislation pending in Congress.
Members of Congress must recognize that delaying, and even cutting off, the regulatory and leasing process effectively removes this resource from our domestic supply options, at least while our government policy is in limbo. Given the competition for investment in energy supply in other parts of the world and the pressures to develop the resource, it's only a matter of time before retreating on the oil-shale provisions in EPACT 2005 is seen as a colossal mistake.
OIL SHALE AND THE WEST
Development of this vast domestic resource could supply the U.S. energy needs for up to 400 years. This presents an opportunity to improve the national energy security position and reduce the instability caused by dependence on foreign sources of energy.
Oil shale's economic benefits would be substantial, not just to our impacted communities, but to American consumers at large. Based on a 3-million-barrel-per-day production rate, estimates are the industry would generate:
* $20 billion annually in revenues through lease bonus payments, royalties on production and corporate income taxes. Roughly half of those profits would likely go to federal, state and local governments;
* several hundred thousand jobs in direct industry employment, plus the associated ripple effect; and
* an estimated 3% to 5% decline in, world oil prices, which would benefit consumers and business users in the U.S. by about $15 billion to $20 billion a year.
Author's note: Research content, credits and thanks go to the Rand Corp., Shell Unconventional Resources, the American Petroleum Institute and Jim Bunger, an independent oil shale consultant.
BY DARRELL A. HENRY, CONTRIBUTING EDITOR, WESTERN BUSINESS ROUNDTABLE
Copyright Hart Energy Publishing, LP Nov 2007
Source: Oil & Gas Investor
http://www.redorbit.com/news/science/1146906/oil_shale_the_future_of_us_energy_security/index.html>Link
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