Quetzal makes oil discovery in Canaguaro Block

Brownstone Ventures announced an oil discovery in the Lower Mirador Formation at the well Canaguay - 1 on the Canaguaro Block in Colombia. Brownstone has a 25% working interest in the Canaguaro Block. Partners in the project are Quetzal (25% working interest and operator) and Condor (50% working interest).

Canaguay - 1 is the first well to be drilled on the Canaguaro exploration drilling program. The well began drilling on June 3, 2010, and finished drilling at a final total depth ("TD") of 15,850 feet on August 4, 2010.

Quetzal began completion and testing operations on September 9, 2010. To date, the Une/Lower Sandstone, Gacheta, Barco and Lower Mirador intervals have been perforated and tested. The Upper Mirador - which had the majority of the indicated oil pay on the well logs - is expected to be perforated and tested in the next several weeks.

Anadarko announces Brazil post-salt discovery at Itauna well

Anadarko Petroleum Corporation has announced interim results at the Itauna #1 well in block BM-C-29 Offshore Brazil. To date, the well has encountered in excess of 275 net feet of oil and natural gas pay in two separate post-salt zones on which show reports were filed with the Agencia Nacional do Petroleo, Gas Natural e Biocombustiveis (ANP).

"We are pleased that our first well on block BM-C-29 is a substantial discovery in the post-salt section," Anadarko Sr. Vice President, Worldwide Exploration Bob Daniels said. "The already significant post-salt pay count could increase when we perform a bypass to obtain additional information that should address the unconsolidated formations in the existing hole. We are drilling ahead to test two targeted pre-salt objectives and expect to complete activities in the well by the end of the year."

The Itauna #1 well, which is located in approximately 250 feet of water, has been drilled to a current depth of approximately 15,250 feet with a planned total depth of nearly 18,000 feet. Following activities on this well, the rig will go to work for another operator, and then is expected to return to Anadarko in 2011 to conduct appraisal activity on the block. Anadarko operates block BM-C-29 with a 50% working interest.

Ecopetrol is the co-owner in the block with a 50% working interest.

Total acquires interest in block offshore Malaysia

Total announces that it has signed an agreement with the national oil company Petronas to acquire a 85% interest in the Block SK317B, Offshore Malaysia. Under the terms of the agreement, Total will operate the Block alongside its partner Petronas Carigali holding the remaining 15% interest.

The Block SK317B is located around 100 kilometers Offshore Sarawak, in water depths ranging from 200 to 1,000 meters. It covers an area of more than 700 square kilometers. The work commitments during the exploration period encompass seismic data acquisition and deep Offshore exploration drilling, an area in which Total enjoys a recognized expertise.

"This acquisition reflects Total’s strategy to expand its exploration acreages in new areas or on new themes while developing its partnerships with national oil companies such as Petronas," stated Jean-Marie Guillermou, Senior Vice President Asia-Pacific at Total Exploration & Production.

OGX makes discovery in well OGX-22 in the Parnaiba Basin

OGX Petróleo e Gás Participações announced that, through its subsidiary OGX Maranhão, it has identified the presence of gas in the Upper Devonian section of well 1-OGX-22-MA, in block PN-T-68, in the onshore basin of Parnaiba. OGX Maranhão, an entity formed by OGX S.A. (66.6%) and MPX Energia S.A. (33.3%), is the operator and holds a 70% stake in this block, while Petra Energia S.A. holds the remaining 30%.

“The drilling of this second successful well, performed at a new wildcat and independent structure, located 12.5km away from 1-OGX-16-MA (California), confirmed the presence of a petrolific province in the region and highlighted the potential of our blocks”

After drilling the first 10 meters in the Upper Devonian section with significant gas shows, at a depth of 1,520 meters, OGX Maranhão has decided to conduct a drillstem test. The well was opened to a flow which reached a wellhead pressure of 1,950 psi with flames of approximately 20 meters long. After the conclusion of the test, the drilling of well OGX-22, Fazenda São José prospect, will continue until the estimated total depth of 3,200 meters, targeting new exploratory objectives.

“The drilling of this second successful well, performed at a new wildcat and independent structure, located 12.5km away from 1-OGX-16-MA (California), confirmed the presence of a petrolific province in the region and highlighted the potential of our blocks,” commented Mr. Paulo Mendonça, General Executive Officer of OGX.

The OGX-22 well, located in the PN-T-68 block, is situated approximately 260 kilometers from São Luis, the capital of the state of Maranhão. The rig QG-1 initiated drilling activities there on October 23, 2010.

Pars discovers one of Iran’s biggest oil layers beneath Offshore field

Iran has discovered a major oil layer beneath the country's Ferdowsi gas field off the coast of Persian Gulf in southern Iran, a top Iranian official says.

Managing director of Pars Oil and Gas Company Ali Vakili said the new layer has an in-place reserve capacity of 34 billion barrels.

"The new oil layer is regarded as one of the biggest layers in the country and it is located beneath Ferdowsi gas field," Vakili said at a meeting of Iranian oil industry's senior managers in Tehran on Sunday."We are currently digging an oil rig to complete our assessments," he was quoted by SHANA as saying.

Regarding Iran's giant South Pars gas field, Vakili said all the wells in phases 9 and 10 have come on stream while phases 15 and 18 will begin production next year.

Phase 12 of the South Pars field is scheduled to come online in 2012, he added.

Iran sits on the world's second-largest gas reserves after Russia.

Newfield Exploration to acquire 50,000 acres in Marcellus

Newfield Exploration Company has announced the signing of a purchase and sale agreement with EOG Resources, Inc., for approximately 50,000 net acres in the Marcellus Shale. Substantially all the acreage is located in Bradford County, Pennsylvania, in the Susquehanna River Basin. This transaction, valued at $405 million, will more than double Newfield's current acreage position in the Marcellus Shale and will provide a deep inventory of future development drilling locations. The closing is expected before year-end 2010 and is subject to customary terms and conditions.

Newfield plans to finance the transaction under the Company's revolving credit facility (an undrawn $1.25 billion facility). Longer term, borrowings under the credit facility would be reduced with proceeds from the sale of certain non-strategic assets.

Gross production from the properties is approximately 7 MMcf/d from five wells. There is an inventory of 11 uncompleted wells and plans to drill 10 additional wells by year-end 2010. Current gathering capacity is 25 MMcf/d with capability to expand to 95 MMcf/d in early 2011. Newfield estimates that more than 400 gross operated well locations exist on the acreage and that net unrisked reserve potential is 1.5 - 2.0 Tcfe.

Newfield plans to run two operated rigs and invest approximately $100 million in 2011 to substantially hold the acreage by production. The Company plans to defer exploratory drilling in the Deepwater Gulf of Mexico in 2011, allowing for a re-allocation of approximately $70 million to its Appalachian development program. Net production in 2011 from the acquired Marcellus properties is expected to exceed the production associated with the non-strategic assets planned for divestment in 2011.

"This transaction doubles our footprint in the Marcellus and adds core acreage with attractive development drilling opportunities," said Lee K. Boothby, Newfield Chairman, President and CEO. "This Marcellus acreage is high-quality and has a low cost structure. It will complement our portfolio of oil assets and provide us with greater flexibility in future commodity price cycles. The deal is consistent with our strategy of building a business in the Appalachian region, just as we have done in the Mid-Continent and the Rocky Mountains. The acreage is contiguous and has a gathering system in place that will allow us to access markets and grow production."

Newfield entered the Appalachian Region in October 2009 and assembled a team of professionals with experience in assessing and developing resource plays. The Company's initial entry into the region came through a joint venture with Hess Corporation covering approximately 70,000 gross acres primarily in Wayne County, Pennsylvania. The partnership has drilled three exploratory wells in Wayne County to date. Newfield operates the venture with a 50% interest.

San Leon, Liesa expand unconventional gas acreage in Poland

San Leon and its Polish subsidiary Liesa Energy have signed a binding agreement with Mazovia Energy Resources Sp. z o.o. to acquire a 100% interest in three additional concessions (the "Concessions") in southern Poland on very favorable terms.

The Concessions, adjacent to the Company's existing Nowa Sol and Wschowa Concessions, will expand San Leon's position in western Poland from 2,245 sqkm to 3,560 sqkm (879,695 acres).

San Leon's technical team continues to pioneer new exploration plays in Poland.

San Leon is pleased to announce that its wholly owned Polish subsidiary Liesa Energy Sp. z o.o. has entered into a binding agreement to acquire three additional concessions for oil and gas reconnaissance and exploration, including the associated mining usufruct agreements, for a total of USD$1.0 million in cash and shares. On completion, San Leon will have a 100% interest in the Concessions. The company expects to make a further announcement in due course as the transaction is subject to final regulatory approval.

The 30/2008/p Gora, 20/2009/p Winsko, and 39/2009/p Rawicz Concessions totaling 1,314 sqkm, are located in the southern area of the Fore Sudetic Monocline of the Permian Basin, onshore western Poland.

These Concessions include portions of license blocks 245, 265, 266, 267, and 268.

The Concessions are valid for up to 5 years.

Gastar, Atinum finalize Marcellus Shale partnership

Gastar has closed its joint venture agreement funding with Atinum Marcellus I, an affiliate of Atinum Partners. Pursuant to the agreement, Gastar has assigned to Atinum an initial 21.43% interest in all of its existing Marcellus Shale undeveloped lease acreage in West Virginia and Pennsylvania, along with certain producing shallow conventional wells.

With the closing of the transaction, Atinum has paid Gastar $30 million in cash and now owns a 21.43% interest in the 34,200 net acres of Marcellus Shale rights previously owned by Gastar. Also under the terms of the agreement, Atinum has committed to an additional $40 million in the form of a drilling carry to Gastar by funding 75% of Gastar's 50% share of drilling completion and infrastructure costs in addition to its own 50% share of these same costs. Upon the completion of the funding of the $40 million drilling carry, Atinum will own a 50% interest in the acreage, making the transaction valued at approximately $70 million. A post-closing title review period could result in certain purchase price adjustments.

Gastar and Atinum have an initial three-year development program that calls for them to drill one horizontal Marcellus Shale well during the remainder of 2010 and a minimum of 12 horizontal wells in 2011 and 24 in each of 2012 and 2013. Gastar will continue to serve as operator of all of the Marcellus Shale interests in the joint venture.

J. Russell Porter, Gastar's President and CEO, commented, "We are excited to be moving forward with our partnership with Atinum, which will allow us to accelerate development of our Marcellus Shale assets. We have already spudded our first operated horizontal Marcellus Shale well in Marshall County, West Virginia -- the Wengerd #1. Under the terms of the partnership, Atinum will pay 87.5% of the cost of the well for a 50% interest. We expect to have the well completed by late first quarter 2011, and due to the close proximity of this well to existing pipelines, if successful, we should be able to place it on production quickly."

"Atinum is also participating with us in an agreement with an operator of adjacent acreage, to pool acreage in Butler County, Pennsylvania, and participate in the drilling of seven horizontal wells targeting the Marcellus Shale. Under terms of that agreement, collectively Atinum and GST own 38.4% of seven horizontal wells to be drilled. Atinum will pay 87.5% of our net cost (or 33.6% for a 19.2% working interest). Currently the other operator is completing the drilling of the vertical section of the seven wells from one pad and will return later this year with a larger rig to drill horizontal sections in all seven wells. Completion activity is expected to begin in the first quarter of 2011 with the wells scheduled to be fracture stimulated and put on production starting early in the second quarter," added Porter.

GeoGlobal provides update on Israeli operations

GeoGlobal Resources Inc. announced today that joint operating agreements relating to each of the two offshore Israel deepwater licenses known as 347 "Myra" and 348 "Sara" have been executed and GeoGlobal has paid the consideration of US$1.2 million for the two licenses.

This completes GeoGlobal's purchase of these interests that were previously announced in June 2010.

CNOOC, Chesapeake close Eagle Ford deal

Chesapeake Energy Corp. and CNOOC Limited announced the closing of a project cooperation agreement whereby CNOOC International Limited, a wholly owned subsidiary of CNOOC Limited, purchased a 33.3% undivided interest in Chesapeake's 600,000 net oil and natural gas leasehold acres in the Eagle Ford Shale project in South Texas. The consideration for the transaction was $1.08 billion in cash, plus an additional $40 million payment adjustment at closing. In addition, CNOOC Limited has agreed to fund 75% of Chesapeake's share of drilling and completion costs up to $1.08 billion, which Chesapeake expects to occur by year-end 2012.

Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "We are very pleased to have partnered with CNOOC Limited in completing our fifth industry shale development transaction. We look forward to accelerating the development of this large domestic oil and natural gas resource, resulting in a reduction of our country's oil imports over time, the creation of thousands of high-paying jobs in the U.S. and the payment of very significant local, state and federal taxes."

Fu Chengyu, Chairman of CNOOC Limited, stated, "We are delighted to close the transaction and further grow our business in line with our overseas development strategy. With our partner's expertise and experience in the shale oil and natural gas development, I believe the project will bring substantial benefits to both parties."

Chesapeake's advisor on the transaction was Jefferies & Company, Inc., and CNOOC Limited's advisor was Tudor, Pickering, Holt & Co. Securities, Inc.

Anadarko makes oil discovery in the Mercury-1 exploration well offshore Sierra Leone

Anadarko Petroleum Corporation has announced the Mercury-1 exploration well offshore Sierra Leone encountered approximately 135 net feet of oil pay in two Cretaceous-age fan systems. Mercury is the company’s second deepwater test in the Sierra Leone-Liberian Basin and was drilled to a total depth of approximately 15,950 feet in about 5,250 feet of water.

“The Mercury well demonstrates that the stratigraphic trapping systems we’ve identified are working, and that the petroleum system is generating high-quality oil,” Anadarko Sr. Vice President, Worldwide Exploration Bob Daniels said. “In the primary objective, the Mercury well encountered approximately 114 net feet of light sweet crude oil with a gravity of between 34 and 42 degrees API, with no water contact. An additional 21 net feet of 24-degree gravity crude was encountered in a shallower secondary objective.

“These results continue to build momentum in the basin and enhance our confidence in the team’s seismic interpretation and geologic modeling,”
added Daniels. “We are preserving the wellbore for potential re-entry, DST (drillstem testing) or a down-dip sidetrack to further delineate the reservoir’s areal extent, quality and deliverability. We also plan to continue working with the government of Sierra Leone and our partnership to accelerate exploration and appraisal activity in the area in 2011.”

The Mercury discovery is located in offshore block SL-07B-10 approximately 40 miles east-southeast of Anadarko’s previously announced Venus discovery.

Anadarko holds an interest in more than 4.6 million acres on five deepwater blocks offshore Sierra Leone and Liberia, and has identified more than 17 prospects and leads on 3-D seismic on this acreage. Once operations are complete at the Mercury well, the company has committed to mobilize the drillship to Ghana to accelerate the appraisal program at the Owo and Tweneboa fields, which the company anticipates sanctioning in 2011.

Statoil’s Gjøa Field begins production

The Gjøa oil and gas field developed by Statoil began production at 15.24 yesterday, 7 November, opening the way for more activity in the northernmost part of the Norwegian North Sea.

“We envisage that its facilities can make this field a hub for developments in this area,” says Øystein Michelsen, executive vice president for Exploration & Production Norway.

The Vega gas satellite is also due to come on stream in the near future. Operated by Statoil, it has been developed with subsea installations tied back to Gjøa.

“Oil and gas are set to flow from Gjøa for at least 15 years to come,” says Michelsen. “However, we’ve seen that technology advances and the recovery factor constantly improves.

“There are also openings for further development in the area, so the field’s platform and infrastructure has been designed for a producing life of at least 30 years.Bringing Gjøa on stream marks the completion of an extensive development job for Statoil, notes project director Kjetil Digre. “Almost 20 million work-hours have been performed. I’m now very pleased that production is under way.”

Gjøa is named after the ship used by Norwegian Polar explorer Roald Amundsen, and the vision for the development has been “based on history, built for the future”.

The project has been implemented in line with that slogan, says Digre: “We’ve taken good care of our historical experience from earlier developments.

“At the same time, creativity and foresight have been important for the many complex decisions we’ve had to take along the way. That’s taught us new lessons.”

The Gjøa platform is the world’s first production floater to receive its power from land. Electricity is transmitted through a 100-kilometre cable from Mongstad north of Bergen. This reduces carbon emissions on the field by about 210,000 tonnes per year. It is only the second Norwegian offshore installation to be powered in this way, after Troll A.

Work on fabricating the platform and its associated infrastructure began in 2007. Costing some NOK 40 billion, the Gjøa/Vega project has been completed on schedule. “This is a profitable investment, both for the licensees and for Norway,” emphasizes Digre.

The licensees in the Gjøa Field are GDF Suez 30% (production operator), Petoro 30% , Statoil 20% (development operator), Shell 12% and RWE Dea 8%.

Pacific Rubiales makes new discovery at Buganviles Block

Pacific Rubiales announced new exploratory success at its Visure-1X well, located in the Buganviles Block, Upper Magdalena Valley Basin, Colombia.

The Visure-1X well, located in the Visure prospect, close to the southeastern border of the Buganviles Block, was drilled to evaluate a structural trap, similar to the nearby Abanico field to the northeast. The well had three main exploratory targets: the Cretaceous Lower and Upper Intervals of the Guadalupe Formation and the Tertiary Barzalosa Formation. The well was spudded on October 16, 2010, and reached a final depth of 3,380 feet measured depth (MD) or 2,205 feet true vertical depth (TVDSS) on November 1, 2010. The well was drilled slightly deviated at an angle of 9 degrees and found the top of the Barzalosa Formation at 2,206 feet MD (1,040 feet TVDSS), the Upper Guadalupe Interval at 2,995 feet MD (1,825 feet TVDSS), the Lower Guadalupe Interval at 3,079 feet MD (1,908 feet TVDSS), and the top of Villeta Formation at 3,272 feet MD (2,099 feet TVDSS).

The petrophysical evaluation of the well in the Barzalosa and Upper and Lower Guadalupe Formations indicated a total net pay of liquid hydrocarbons of 114 feet in the three intervals, ranging from 24.5 to 45.5 feet of net pay and 16% to 26% average porosity. In addition to the oil-bearing sandstones, the well also showed gas saturated sandstones in the Barzalosa Formation (3 feet thick).

The Visure-1X well was drilled in the southwestern flank of the Visure prospect, and confirmed an oil-water contact at 1,970 feet TVDSS in the Lower Guadalupe Formation. According to the seismic interpretation, the crest of the structure at this level, 0.7 km to the northeast, has been mapped at 1,915 feet TVDSS, which could imply an additional 65 feet of hydrocarbon column for the Visure prospect in the Lower Guadalupe Formation Interval. The Company is now preparing the testing plan for the well to complete it as a producer in the Guadalupe Formation.

The Company is the operator in the block and holds a 19.875% participation in the prospect where the Visure well was drilled. The remaining interest is held by Petrodorado South America, S.A. (TSXV: PDQ) and other private investors. This is an association contract with Ecopetrol.

Ronald Pantin, CEO of the Company, commented, "The results of the Visure-1X well in the Buganviles Block brings new exploration opportunities in the area, so the Company is planning to drill additional exploratory wells in the Block during the last quarter of 2010 and the first quarter of 2011. The first of these, the Tuqueque-1X well, will be spudded shortly."

Bonanza, Bluescape acquire stakes in Italy

Bonanza and Bluescape have completed the acquisition of 100% of the membership interests in AleAnna Energy LLC. AleAnna Energy LLC owns a 15% membership interest in AleAnna Resources LLC, which holds eleven exploration permit applications in the Italian Po Valley and Bradano basins, encompassing a total of 3,100 sq kilometers (760,000 acres).

Bluescape is an equity owner in AleAnna Energy along with Bonanza and provided interim bridge financing to Bonanza to close the acquisition. Once permanent financing is in place, Bonanza and Bluescape will own 49% and 51% of AleAnna Energy, respectively.

In Northern Italy's Po Valley, AleAnna Resources currently holds five active exploration permits. The fifth permit, on the Bugia block, covering 197.8 sq kilometers (48,877 acres), was awarded on September 28th, 2010. AleAnna Resources has four additional permit applications in the Po Valley Region, all of which are expected to be awarded by the end of 2011 or early 2012.

In the Bradano basin in Southern Italy, AleAnna Resources received its first exploration permit for the Torrente Acqua Fredda block, covering 66.24 sq kilometers (16,368 acres) in late October 2010. AleAnna Resources has submitted a second application for a property in the Bradano basin which is expected to be awarded in 2011 or early 2012. These permit application areas are on trend with several recent oil / gas discoveries in the Bradano basin.

AleAnna Resources has an excellent position in the Po Valley, one of the most prolific gas basins in Europe and is the second largest holder of permit application areas behind ENI/Agip. In March 2009, AleAnna Resources completed a 130 sq kilometer (32,124 acres), state-of-the-art 3-D seismic shoot in the Corte dei Signori license area, identifying several significant structural anticlines. AleAnna Resources will drill its first well on the Corte dei Signori license area – Gallare Field – in early 2011. AleAnna Energy is carried on the cost of drilling the first well. AleAnna Energy also holds an additional 20% back-in working interest after payout in AleAnna Resources, which will bring AleAnna Energy's total working interest in AleAnna Resources to 35% after payout.

Leni assessing potential JV for unconventional gas in Spain

Leni has signed a binding Non-Disclosure and non-binding Commercial Terms Agreement setting out the potential terms of an agreement to cooperate with Sorgenia and Rohöl-Aufsuchungs Aktiengesellschaft ("RAG") to assess a potential joint venture for the exploitation of unconventional gas opportunities in Spain.

As previously reported in May 2010, LGO has identified unconventional gas prospectivity in the Lower Jurassic within the acreage held by the Company which spans over 550 sqkm in the proven Basque-Cantabrian basin in northern Spain. These prospects are currently being assessed.

Sorgenia is a major European conglomerate engaged in the production, import and sales of electricity and gas, and is actively seeking shale gas acquisitions to increase its gas supply in Europe. RAG is major European gas exploration and production company with operations in Austria, Hungary, Germany and Poland and is a recognized leader in shale gas exploitation in Europe.

Under terms of the Agreements, LGO, Sorgenia and RAG have agreed an exclusivity period of 10 weeks to complete their assessment of the Company's unconventional gas opportunities in Spain and finalize full terms and conditions of a formal three way agreement between the parties based on the Commercial Terms Agreement.

David Lenigas, Executive Chairman, commented, "LGO has now attracted four international companies to potentially assist with the full exploitation of the Company's entire Spain acreage."

"The existing producing oilfields, developments and exploration prospects have been neglected for many years and with BP agreeing to take long term oil sales for their refinery on the east coast of Spain, Praxair participating in a nitrogen enhanced oil recovery joint venture announced last month and now this agreement with Sorgenia and RAG to co-explore and develop the unconventional gas potential of our acreage, we see tremendous medium to long term potential for the Company."

"The Sorgenia and RAG venture on completion will significantly de-risk the unconventional gas potential of our Spain acreage and shall accelerate the development of this very important and strategic asset."

Petromanas completes seismic operations in Albania

Petromanas announced the completion of 2D seismic operations on Blocks D and E onshore Albania incident free.

The 105 km of 2D seismic acquired on Block D and E fulfils the work commitments for the first exploration phase on those blocks. The interpretation of this new data and correlation with existing data will improve the quality of the existing prospect inventory and allow the geoscience team to reduce the exploration risk and high grade its exploration prospects.

Petromanas continues as planned with its seismic operations on Blocks 2 and 3. This seismic program is anticipated to be completed by early 2011. All operating licences and permits have been received, surveying and drilling operations for seismic shots are underway. This program includes 140 km of 2D seismic survey and will provide valuable data near the Spiragu discovery which was drilled in 2001. The majority of the seismic work will be carried out with heliportable rigs and the remainder through conventional shallow drilling rigs.

In conjunction with the seismic work, the Company is re-evaluating the un-risked resource assessment which was prepared on December 15, 2009 by Gustavson Associates LLC based on the seismic, geology and limited well data which was available at the time. In the normal course of the current geophysical and geological ("G&G") work, the risked resource potential will be evaluated and, as a result of incorporating risk assessments and new data, will be lower than the un-risked resource potential numbers which were presented in the Gustavson report.

The G&G analysis will be underway through year end as the new seismic data becomes available. It is anticipated that an updated independent resource evaluation report will be prepared early in 2011. Further updates to resource estimates will be prepared as the Company acquires new data from seismic programs and drilling operations. The geological work conducted to date has further confirmed the significant potential of the Petromanas acreage and the exploration prospectivity of both the shallow and deep prospects. Once Petromanas has the necessary data, it is anticipated that some of the deep target plays will be farmed out to industry partners. The Company remains on schedule for the planned completion of the seismic program leading to a drilling campaign in 2011.

BP awarded seven exploration licenses in UK North Sea

BP confirmed that it has been awarded license interests in seven offshore exploration blocks in the UK’s 26th Seaward Licensing Round. The awards – five blocks operated by BP and two blocks operated by a partner – together represent the largest license award BP has received in the UK for more than a decade.

“These license awards are a significant success for BP and a further boost to the long-term future of our North Sea business,” said Trevor Garlick, Regional President for BP in the North Sea. “With six major projects currently underway in the UK and Norwegian sectors, BP is investing strongly in the North Sea to develop today’s resource base and we are also building a complementary portfolio of future opportunities.”The awards, made by the UK Department of Energy and Climate Change, support BP’s focused program of exploration and appraisal in the North Sea. The strategy is based on developing new fields which can be tied in to BP’s existing infrastructure hubs.

Cook Inlet Energy wins 3-year Alaska exploration license extension

Miller Energy Resources subsidiary Cook Inlet Energy has obtained approval for a three year extension of the Susitna Basin Exploration License 2, ADL 390078 which encompasses 471,474 acres.

The license makes up the majority of Miller's and Cook Inlet Energy's net undeveloped acres, and covers primarily natural gas prospects. The licensed acreage is located approximately 55 miles northeast of Anchorage. Scott M. Boruff, Miller's CEO, said today, "We appreciate the decision of the commissioner in granting this extension of the Susitna License. Extending the license was one of the key initiatives for our team in Alaska this quarter."

Under the terms of the license, the original term was seven years with an expiration date of 31 October, extendable for an additional three years at the sole discretion of the commissioner of the State of Alaska Department of Natural Resources. The license grants Cook Inlet Energy an exclusive license to explore for oil and gas on the specified lands, and upon fulfillment of the work commitment, the license for all or any part of the land could be converted into oil and gas leases.

The original work commitment of approximately US$3.5 million was fulfilled, and, prior to the granting of the extension of the license, Cook Inlet Energy had the right to convert the license for all or any portion of the acreage into oil and gas leases. Once the original term of the license expired, Cook Inlet Energy would have been required to pay a per acre fee in order to convert the acreage to leases to the state and commence drilling operations within specified timeframes. Cook Inlet Energy applied for an extension under the license terms and was granted a three-year extension on 29 October, extending the expiration date of the license to 31 October 2013.

To comply with extension terms, Cook Inlet Energy committed to a total additional work commitment of $750,000 over the term of the extension, with a minimum of $250,000 being required by the end of the first year and an additional $250,000 by the end of the second year. If it fails to meet its work commitment in either of the first two years of the extension, it would be required to relinquish a portion of the licensed acreage at the end of that year. Upon completion of the work commitment, it will have the option to convert any or all of the license acreage to oil and gas leases with a five year term and a royalty rate of 12.5%, with annual rentals of $3.00 per acre.

Statoil awarded eight new exploration licenses

Statoil has been awarded operatorship of parts of licences 8/15 and 9/11D, close to the Statoil-operated Mariner heavy oil discovery, and six licences in blocks 212 and 213 near the Faroe border.

“We are very pleased to secure this new Statoil operated acreage in the UK,” says senior vice president for global exploration Tim Dodson. “The North Sea blocks 8/15 and 9/11D will capture any north westerly extension of our Mariner oil discovery which Statoil is presently evaluating for development,” he says.

“The other blocks will further strengthen our position in the area between Statoil’s licences in the Faroes and the Rosebank field in UK waters, where Statoil is a partner in the Chevron operated field.”

The requirement for the acreage near Mariner are 2D seismic survey and evaluation prior to a drill or drop decision, while for the Faroes/Rosebank blocks a drill or drop decision has do be made after reprocessing of existing 2D seismic.

Cairn to begin Palar Basin exploratory drilling in early 2011

Cairn Energy is reported to be preparing to commence its exploratory drilling campaign on its shallow water Palar Basin Block PR-OSN-2004/1 on India's east coast, part of which lies within the prohibited zone over which is the Satish Dhawan Space Center's flight path. Cairn has obtained permission from the various government agencies to proceed.

The company has completed its initial studies, including geotechnical and pore pressure surveys as well as a 3,000 km 2D seismic survey, which has been processed and interpreted. It is now expected to spud the first of three planned wells in April 2011, and to employ a jackup drilling rig capable of drilling to 20,000 ft.

The approximately 9,400 sq km shallow water and transition zone Block PR-OSN-2004/1 is operated by Cairn with 10% interest in partnership with Oil and Natural Gas Corporation (ONGC), with 35% interest, Tata Petrodyne with 30%, and Coal India Ltd with 25%.

Atlas achieves record with Marcellus Shale well completion

Atlas Energy has just completed a new Marcellus Shale gas production well in the Appalachian region of southwestern Pennsylvania that has achieved initial output of 21 million cfd.

Atlas reported today that the company record producer was drilled in Westmoreland County as a step-out from existing infrastructure and has not yet been put on production. It said that the well will likely be tied into production during the second quarter of next year.

The company said that it has produced some 63.3 million cfed from its Appalachian operations in the Marcellus Shale out of the company's total output of about 118.3 million cfed during the last quarter. It said 19 horizontal Marcellus wells were drilled and fractured, and that it has completed 12, and put six of those on production at an average output of 6.8 million cfed. The company currently has 23 operated Marcellus wells in one stage or another.

CGGVeritas develops seismic applications for shale gas

CGGVeritas has developed seismic solutions to identify shale gas "sweet spots" which it is demonstrating at this year's SEG Conference in Denver.

The company said today that advanced seismic processing and analysis of high-resolution wide-azimuth 3D surveys can define key reservoir properties such as brittleness, pore pressure, and local stresses, and reservoir engineers can use this information to optimize drilling and completion locations. Unconventional reservoirs require some form of stimulation to obtain commercial production, however, and shale gas reservoirs require fracture stimulation to unlock gas from extremely low permeability formations.

As fracture stimulation is an important aspect of well completions, production companies need to know basic information about fractures such as whether they will open (and stay open), direction of fracture propagation, dimensions and type of fracture, and whether they will stay in zone. Increasingly, seismic is utilized to provide such information and guide drilling and completions.

Three types of information extracted from seismic are useful in optimizing drilling locations: fracture characterization, geomechanical properties, and principle stress measurements (vertical maximum and minimum horizontal stresses).

CGGVeritas uses a series of methods to derive this information, including appropriate data acquisition, careful AVAZ (Amplitude Versus Azimuth) processing, AVO, interpolation, and inversion. Some of these methods are mature and have found new applications for the characterization of unconventional reservoirs. Although information can be extracted from compression wave (P-wave) data alone, the inclusion of shear waves (S-waves) can be used as an additional source of observations to further constrain and narrow uncertainty in the results.

Given the target depth of formations in shale gas basins that are being exploited today, the maximum principle stress is vertical, giving rise to HTI (horizontal transverse isotropy). This means that the fracture system is comprised of vertical fractures which cause anisotropic effects on seismic waves as they pass through. These anisotropic effects are observed on 3D seismic data as changes in amplitude and travel time with azimuth.

In multicomponent data shear wave splitting can be observed. CGGVeritas uses the relationship between changes in P-wave amplitude with azimuth in anisotropic media to invert the observed seismic response and predict fracture orientation and intensity. This information is of great value to production companies because it indicates the optimum horizontal drilling azimuth and offers the prospect of subsequent fracture stimulation as a solution to tap into existing natural fracture systems.

A clear understanding of the geomechanical properties and their distribution explains the reservoir heterogeneity and thus the variation in economic ultimate recovery (EUR) between wells. CGGVeritas derives a host of geomechanical properties from migrated CDP gathers, including Young's Modulus, Poisson's Ratio, and shear modulus, by first inverting the data for P- and S-wave velocities and density. With this information, fracture dimensions can be predicted and wells drilled in the most brittle rock.

Linear Slip Theory for geomechanical properties is used to calculate stress values. Generally, the stress state is anisotropic leading to the estimation of both the minimum and maximum horizontal stress. As the seismic data measure dynamic stress, results are then calibrated to the static stress that is effectively borne by the reservoirs at depth, making it possible to predict the hoop stress and the closure stress as key elements defining the type and motion of fractures.

At locations where the differential horizontal stress ratio (DHSR - the ratio of the difference between the maximum and minimum horizontal stresses to the maximum horizontal stress) is low, tensile fractures will form in any direction, creating a fracture swarm. If the maximum horizontal stress is much greater than the minimum, then fractures will form parallel to the direction of maximum horizontal stress.