Chevron sanctions deepwater Big Foot project

Chevron Corp announced it has sanctioned development of its $4 billion Big Foot project in the Deepwater U.S. Gulf of Mexico.

“Sanctioning Big Foot underscores our commitment to the Gulf of Mexico and will contribute to future U.S. energy supply,” said George Kirkland, vice chairman, Chevron Corporation. “This project is another example of Chevron’s disciplined approach to advancing our enviable queue of major capital projects.”

Big Foot will be Chevron’s sixth operated facility in the Deepwater Gulf of Mexico and located approximately 225 miles (360 km) south of New Orleans, Louisiana, in water depths of 5,200 feet (1,600 m). The development will utilize a dry tree Extended Tension Leg Platform with an on-board drilling rig and have production capacity of 75,000 barrels of oil and 25 million cubic feet of natural gas per day. First oil is anticipated in 2014.

“We have industry leading expertise in developing Deepwater projects of this type and have repeatedly proven that we can do so safely,” said Gary Luquette, president, Chevron North America Exploration and Production Company.

Discovered in 2006, the Big Foot field lies in the Walker Ridge Area and is estimated to contain total recoverable resources in excess of 200 million oil-equivalent barrels. Primary pay sands are Middle to Upper Miocene ranging from 19,000 to 24,000 feet (5,800 to 7,300 m) and lie below a salt canopy ranging from 8,000 to 15,000 feet (2,400 to 4,500 m) thick. Three exploration and appraisal wells with multiple sidetracks have been drilled safely and successfully in the field to define the Big Foot structure. Chevron, through its subsidiary Chevron U.S.A. Inc., has a 60 percent working interest in the Big Foot project.

Chevron is one of the top leaseholders in the Gulf of Mexico, averaging net daily production of 149,000 barrels of crude oil, 484 million cubic feet of natural gas and 14,000 barrels of natural gas liquids during 2009.

Geotrace, BP to develop POCS seismic technology

Geotrace, an independent Reservoir services company that provides subsurface imaging solutions to the oil and gas industry, is teaming with BP to further develop POCS (Projection Onto a Convex Set) technology for use in seismic data processing for the oil and gas industry. BP originally developed POCS technology, which is a powerful tool for interpolating—or reconstructing—data.

POCS technology uses information surrounding data that may be missing, such as in a particular Reservoir formation, in order to reconstruct the missing data. The technology targets those companies specializing in oil and gas production and exploration risk management.

“By providing missing information, POCS’ primary advantage is that it helps minimize risk in assessing a reservoir,” says Bill Schrom, CEO of Geotrace. “The technology opens doors that were previously closed by allowing geoscientists to build missing data from the information they already have.

“Ideally, geoscientists acquire all the data they need to help them understand Reservoir formations. However, in some cases, certain valuable information may be missed in initial data acquisition. This is where POCS plays a valuable role in reconstructing missing data and eliminating the cost of acquiring new data to fill in the gaps,” Schrom explains.

POCS technology is commonly used in many fields where data are corrupted or missing, such as Synthetic Aperture Radar (SAR) and Magnetic Resonance Imaging (MRI).

Petrobras, Statoil makes discovery Offshore Brazil

Statoil and Petrobras of Brazil have struck oil on the Indra prospect in the Espirito Santo basin off the coast of Brazil.

Petrobras is operator for licence BM-ES-32, where the discovery was made and where Statoil holds a 40% stake.

The exploration well was drilled at a depth of 2,130 metres and both oil and Reservoir quality is good. The Reservoir thickness is approximately 70 metres and is of good quality. The preliminary analysis of the oil shows a density in the range between 25 and 30 degrees API.

“We are very pleased to have struck oil here and the result will have an important bearing on our decision regarding further exploration activity in this area,” says Tim Dodson vice president, international exploration.

The Inndra find was made by the semi-submersible rig Paul Wolfe. The location is situated 140 kilometres from land and some 400 kilometres north of the Peregrino field.

At the moment Statoil is also participating in exploratory drilling in the Campos basin on licence BM-C-33, where Repsol is the operator.

Statoil is operator on the Peregrino field and will hold a 60% share once the 40% divestment to Sinochem has been approved by the Brazilian authorities. Peregrino is planned to come on stream in the latter half of the first quarter of 2011.

By next year Statoil plans to operate three exploration wells in Brazil, two in the Peregrino area in order to prove additional resources on the field, as well as an exploration well in the Camamu basin.

Eni becomes operator of three Polish Baltic Basin licenses

Eni has reached an agreement for the acquisition of Minsk Energy Resources and to become operator of three licenses in the Polish Baltic Basin, a highly prospective Shale gas play.

The acreage is located in the northeast of Poland and consists of 1,967 square kilometers. Drilling operations are expected to start in 2011, with a total exploration commitment of six wells.

Eni will operate the licenses leveraging the extensive knowledge and expertise acquired through its JV in the Barnett Shale in Texas, the first Shale gas basin in the world to be developed on a large-scale.

Through this agreement Eni makes its entrance into European Unconventional Gas, in line with the company's strategy of expanding its position in unconventional resources.

Poland, which is currently importing almost 70% of its gas requirements, represents the ideal environment for Eni to start its operations in this emerging play which is of great interest to the oil & gas industry as a whole.

Marathon enters Eagle Ford Shale Play

Marathon Oil Corporation announced that it has completed an agreement with Denali Oil & Gas for entry into the Eagle Ford Shale formation in Wilson and Atascosa counties, Texas. Under the terms of the agreement, Marathon will pay Denali $10 million as well as drill and complete four wells to earn approximately 17,000 net acres. Marathon also has the option to purchase Denali's remaining 58,000 net acres in the Eagle Ford Shale in these two counties. If Marathon executes this option, the full 75,000 net acres, including the initial payment, carried well interest and lease extensions, will cost approximately $2,800 per acre or a total of approximately $209 million. Marathon has until Oct. 31, 2011, to exercise this option.

In the event Marathon does not exercise its purchase option, Denali has the option to sell the remaining 58,000 acres to Marathon. The total cost under this option, including the initial payment, carried well interest and lease extensions, would be $92 million or approximately $1,225 per acre. Denali has until the later of Nov. 15, 2011, or 15 days after the completion of the final well, to exercise this option. This agreement covers all of Denali's acreage in Wilson and Atascosa counties but excludes Denali's 25,000 acres in Gonzales and Fayette counties.

"Since acquiring our first Shale assets in the onshore U.S. market in 2006, Marathon has developed substantial expertise that we can apply to emerging plays like the Eagle Ford and create more opportunities for mid- and long-term profitable production growth," said Dave Roberts, the Company's executive vice president, Upstream. "This new entry reinforces a key element of our Upstream strategy of targeting unconventional, primarily liquids-rich resource plays providing low-risk, scalable growth."

Oman’s Farha South-5 well tests in excess of 1,500 bopd

The 2010 drilling programme onshore the Sultane of Oman has continued with the successful testing of the Farha South-5 well ("FS-5") on Block 3. FS-5 tested in excess of 1,500 BOPD from a 160 metres long horizontal section in the Barik formation using an electric submersible pump (ESP). The well has been completed as a producer and is being produced into the Farha South Early Production System for a long term production test.

"We are very pleased with the results from the FS-5 well. Oil was encountered both in the Barik and the Lower Al Bashir layers. The results emphasize the importance of the Farha area and underscores the potential also of the Barik Reservoir along the Farha trend," says Magnus Nordin, Managing Director of Tethys Oil AB.

The FS-5 well spudded in early October, and was drilled as a stepout exploration well 6.8 kilometres northeast of the discovery well FS-3. The pilot hole was drilled to a depth of 2,370 metres. Both the Barik formation and the Lower Al Bashir formation were penetrated with oil shows. Electrical logs were run. Subsequently, a horizontal sidetrack was drilled 160 metres within the Barik formation, which lies at 1,240 metres below ground level. A pump was installed and the well was placed on production. The average daily production rate is in excess of 1,500 BOPD of 44 API gravity.

The drilling rig has been moved to the Saiwan East-4 well, in Block 4, to carry out production tests. SE-4 showed oil in several formations when drilled in the summer of 2010, but was not tested at the time.

Tethys has a 30% interest in Blocks 3 and 4. Partners are Mitsui E&P Middle East B.V. with 20% and the operator CC Energy Development S.A.L. (Oman branch) holding the remaining 50%.

Ecopetrol confirms hydrocarbons in the Cano Sur Block

The presence of hydrocarbons announced in the Mago-1 well is confirmed. -- Ecopetrol is the operator and has an interest of 50%. -- This discovery brings the total number of wells with presence of hydrocarbons to seven in 2010 (including exploratory and stratigraphic) .

Ecopetrol reports that it proved the presence of hydrocarbons in the second stratigraphic well drilled under the Cano Sur Exploration and Production contract, located in the province of Meta.

Preliminary results of the Draco-1 well, which reached a depth of 3,284 feet (close to one kilometer) confirm the presence of hydrocarbons which was previously announced on November 2 of 2010 in the Mago-1 well.

The interests under the Cano Sur contract are split equally between Ecopetrol, which is the operator, and Shell Exploration and Production Cano Sur GMBH.
The preliminary technical evaluation indicates the presence of crude petroleum in the Carbonera formation, in a net Reservoir thickness of close to 9 feet, with average porosities of 30%.

The findings registered in this new stratigraphic well, together with those registered in Mago-1, confirm the hydrocarbons potential of the eastern region of the province of Meta, where the Rubiales and Quifa fields also are located.

This discovery brings the total number of wells (in which Ecopetrol has a participation) where the presence of hydrocarbons has been proved in 2010 to seven (including exploratory and stratigraphic). Four of these wells are located in the Eastern Llanos Region of Colombia.

During 2011 exploration activities are expected to continue in the Cano Sur block, with the goal of evaluating the potential of the Reservoir and the eventual conditions for production.

ION begins multi-client seismic survey in Marcellus Shale

ION Geophysical Corporation has announced the commencement of a new 3D multi-client seismic survey in the Marcellus shale play in central Pennsylvania. ION will manage and execute the entire program, providing a proven mix of survey design, planning and permitting, data acquisition using advanced technologies, data processing, and Reservoir analysis from ION's GX Technology (GXT) imaging solutions subsidiary.

ION has commenced mobilization for the 200-square-mile initial phase of the program.

The Marcellus Shale is one of the hottest Unconventional Gas plays in North America. In April 2009, the United States Department of Energy estimated the Marcellus to contain 262 trillion cubic feet (TCF) of recoverable gas, about 44 billion barrels of oil equivalent (BOE). Economic viability in Shale plays has traditionally been achieved primarily through two engineering technologies, Horizontal Drilling and hydraulic fracture stimulation. Lower gas prices, however, are creating an increased interest in the use of seismic data to not only help the drilling engineer "stay in zone" and avoid geo-hazards, but also to help operators prioritize acreage positions and drilling locations, optimize their drainage strategies and well spacing, and better design their stimulation programs.

Bob Peebler, Chief Executive Officer of ION, commented, "Since 2003, we've been collaborating with E&P companies to push the limits of seismic data in unconventional Reservoirs to help them maximize their return on investment. We've recently conducted several pilot studies in the Marcellus and other North American shales that have demonstrated how we can help our clients determine reservoir rock properties, such as brittleness and natural fracture networks, and help predict the geometry of hydraulically induced fractures, both of which are critical to well planning, stimulation and completion. The Marcellus program is further validation of the growing value leading E&P companies are capturing from the use of seismic to create a sustainable business at scale in the Shale resource plays. We believe there is tremendous upside potential to expand our programs in unconventional Reservoirs in North America and abroad."

ION is working with Tesla-Conquest to provide acquisition services utilizing land seismic technologies from INOVA, the newly formed joint venture between BGP (51%) and ION (49%). INOVA technologies to be deployed on this survey include the FireFly(R) cableless acquisition system and the VectorSeis(R) digital, full-wave sensor.

Steve Bate, President and Chief Executive Officer of INOVA, added, "We are extremely pleased to work with ION and Tesla-Conquest to acquire full-azimuth, multicomponent data to meet our clients' geologic and interpretation objectives. Pennsylvania is both an environmentally sensitive and logistically challenging area, and FireFly and VectorSeis are uniquely capable of enabling a safe, efficient and low impact winter acquisition campaign while delivering state-of-the-art multicomponent measurements."

Eni, Oxy, KOGAS achieve 10% production increase at Iraq’s Zubair Field

Eni, Occidental Petroleum Corporation (NYSE:OXY) and Korea Gas Corporation (KOGAS) announced that they have achieved and sustained a 10-percent increase in oil production at the Zubair field, near Basra in southern Iraq.

Production from the Zubair field has grown to more than 200,000 barrels of oil per day from the approximately 183,000 barrels of oil a day produced when the consortium started field operations in the first quarter of 2010.

The consortium, led by Eni (32.81%) with partners Oxy (23.44%), KOGAS (18.75%) and the Missan Oil Company (25%), signed a technical service contract in late January to redevelop the Zubair field with Iraq's state-owned South Oil Company (SOC) and Missan Oil Company as State Partner.

With the successful 10-percent increase in initial production, the consortium’s contract cost recovery mechanism commences, with the group additionally earning $2 per barrel on the incremental oil production.
The consortium plans to increase production from the Zubair field to 1.2 million barrels of oil a day, representing an increase of about 1 million barrels of oil per day. Target production is expected to be reached progressively within the next six years and maintained for seven years thereafter.

“Oxy’s success in Iraq is a direct result of an outstanding partnership with the Iraqi government and our consortium partners in developing one of the world’s great oilfields,” said Dr. Ray R. Irani, Chairman and Chief Executive Officer of Occidental Petroleum. “We are proud of our initial results in Iraq as well as our continued success in numerous other projects across the Middle East.”

The redevelopment of the Zubair field, one of the largest discovered fields in the world, will support Iraq in becoming a major player in global oil markets. It also will foster social and economic development at a regional and national level, by providing training and development opportunities for the thousands of Iraqi workers of Zubair and by promoting much-needed economic stimulus.

The Zubair Field Operating Division manages the rehabilitation and expansion project, which is staffed mainly by employees from South Oil Company with expert support from the consortium.

Sun River Energy completes Permian Basin well

Sun River Energy, Inc. announced that it has turned the Stansberry # 1 well to production on November 30, 2010.

The Stansberry # 1 well (API # 42-451-32661) is drilled to a total depth of 5,507 feet in Tom Green County, Texas. The well is completed in the Harkey Sand geological formation at 4,780' to 4,784'. The well initially shut-in at 1,650 PSI tubing pressure while awaiting a pipeline connection. Presently, the well is producing both natural gas and crude.

Sun River Operating, Inc. operates the well. Sun River Energy, Inc. owns a 39% working interest in the well.

Statoil awarded licenses offshore Canada

Statoil has been awarded interests in four new licenses offshore Canada. The new acreage underlines the company's ambitions in the area.

The licenses include a Significant Discovery License (SDL) and three Exploration Licences (ELs) off the coast of Newfoundland, awarded through a land sale issue by the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB).

"We are very pleased to learn that we have been successful in acquiring new licences Offshore Newfoundland," says Tim Dodson, senior vice president of Statoil’s global exploration entity.

"Securing these new licences provides further growth opportunities near our Mizzen discovery in the Flemish Pass Basin and near existing infrastructure in the Jeanne d’Arc Basin, as well as more frontier opportunities in a promising basin. We are looking forward to exploring these new opportunities together with our partners and in close cooperation with the authorities."

Statoil has been successful in acquiring the following licenses:
• One SDL, which is an extension of Statoil’s current Mizzen licence. Statoil is operator with a 65% interest and with Husky Oil Operation Limited as partner.
• Two ELs located in the Flemish Pass Basin/Central Ridge region, approximately 500 kilometres Offshore Newfoundland. For the licence located in the vicinity of the Mizzen SDL, Statoil is operator with a 65% interest and Husky Oil as partner. For the licence situated in the northern part of the Flemish Pass Basin, Statoil is operator with a 75% interest and with Repsol as partner.
• One EL located in the Jeanne d’Arc Basin, approximately 250 kilometres offshore Newfoundland. Statoil Canada has a 50% interest and Husky Oil Operation Limited is the operating partner.

Statoil is partner in the ongoing drilling of the Suncor Energy operated Ballicatters well in the Jeanne d’Arc Basin. As operator Statoil is planning to drill a well on its Mizzen discovery located in the Flemish Pass Basin and another on its Fiddlehead licence in the Jeanne d’Arc Basin in 2011/ 2012.

Statoil is also partner in two producing Offshore fields, Terra Nova and Hibernia, and in the field developments of Hibernia Southern Extension and Hebron.

BG Group discovers gas in second Tanzanian well

BG Group announced that its second Tanzanian exploration well, Chewa-1, has also discovered gas. The well, located in Block 4 approximately 80 kilometres Offshore southern Tanzania in a water depth of around 1 300 metres, is some eight kilometres north-west of BG Group's Pweza-1 gas discovery announced in October.

Chewa-1, operated by Ophir Energy plc (40%), is the second of a three-well initial work programme planned for Blocks 1, 3 and 4 Offshore southern Tanzania. The initial work programme also includes the acquisition of 4,000 square kilometres of 3D seismic data. BG Group (60%) has the option to assume operatorship of all three Blocks upon completion of the initial work programme.

BG Group Chief Executive Frank Chapman said: "This is an encouraging start to our campaign in Tanzania. We have a large acreage position to explore and an extensive exploration programme will be needed to assess the full potential of this new play."

Black Dragon begins new drilling program

Black Dragon will commence a new drilling program which will include the drilling of 2-3 new wells.

Black Dragon is also in talks to complete a joint venture on its Spider Field. The company is in the process of sending its land man and geologist to the field to pick the most prolific 12 locations to drill and intends to begin the permit process shortly after.

According to Tom Neely, President, "Management is committed to reaching its year end production goals. The addition of these new wells will increase production rates for the company and lead to increased cash flow. Black Dragon is committed to enhancing shareholder value by exploiting the full potential of its properties expeditiously."

Pertamina, Exxon to develop Natuna gas block Offshore Indonesia

Pertamina and US oil giant Exxon Mobil have signed an agreement to develop Offshore natural gas block Natuna D-Alpha, located off Indonesia in the South China Sea.

Considered the largest gas reserve in Asia, Natuna D-Alpha is estimated to hold 46 million Tcf of natural gas. Production is expected to begin around 2018.

Exxon initially had development rights to the field, however, after a dispute with the Indondesian government about revenue-sharing, rights to Natuna D-Alpha were given to Pertamina in 2008.

Iran to begin drilling for gas in Arash Field

According to Iran's Mehr News agency, Iran will begin gas well drilling operations Offshore at its Arash gas field in the Persian Gulf, Iranian Offshore Oil Company’s managing director Mahmoud Zirakchianzadeh said.

Zirakchianzadeh also added that Iran currently has plans to drill four wells at the field, which contains an extimated 20 Tcf of natural gas between Iran, Kuwait and Saudi Arabia.

Currently, a drilling jacket has been constructed, installed and came on stream at the Arash gas field.

Petrobras confirms oil discovery in the Amazon

Petrobras announced that the first data obtained from the Extended Well Test (EWT), which got underway in September at exploratory well 1-ICB-1-AM (Igarapé Chibata No. 1), confirms the discovery of a new accumulation of light oil (46º API) and natural gas in the city of Tefé (state of Amazonas), 630 km away from the city of Manaus and 32 km from the Urucu oil province. The Company already has three fields producing oil and natural gas in the city of Coari.

The 3,485-meter well was drilled in the Solimões Basin, in Block SOL-T-171, for which Petrobras owns the exploration and production rights. Thus far, the EWT data indicate that the well is capable of producing 2,500 barrels of oil per day, an excellent result when dealing with this type of basin in Brazil.

In addition to the EWT, expected to last a year, the Evaluation Plan, approved by the National Petroleum Agency (ANP), provides for the acquisition of new seismic data and the drilling of delimitation wells. This work aims to determine the extent of the accumulation, to quantify the reserves, and to prove the cost-effectiveness of the accumulation.

This exploratory success is the outcome of the resumption of the exploratory investments, made from 2005, in the onshore basins in the Amazon, as foreseen under the Company's Strategic Plan, which directs efforts to new frontiers where Petrobras' knowledge, technology, and operating experience afford it a competitive advantage.

BP awarded exploration block in Indonesia

Following an announcement last week by the Government of Indonesia last week, BP confirmed that it has been awarded a 100% interest in the North Arafura oil and gas production sharing contract (PSC) in onshore Papua Province. The PSC was signed in Jakarta by representatives of the Government and BP.

The North Arafura PSC is located on the coast of the Arafura Sea, 480 kilometres southeast of the BP-operated Tangguh plant, covering an area of just over 5,000 square kilometers. BP expects to commence seismic operations on the block in the near future.

"This award is further evidence of BP's commitment to a long-term presence in Indonesia, working in partnership with the Government of Indonesia both centrally and regionally. BP is very pleased to expand our position in Papua, an area with huge potential in its people, culture and natural resources," said William Lin, BP's President for Asia Pacific Exploration & Production.

BP makes deep gas discovery in Egypt's West Nile Delta

BP Egypt announced that it has made a significant gas discovery in the Deepwater West Nile Delta area.

The Hodoa discovery is located in the West Mediterranean Deepwater, Nile Delta concession, some 80 km northwest of Alexandria. The WMDW-7 well was drilled to a depth of 6350 metres and is the first Oligocene Deep Water discovery in the West Nile Delta area. Further appraisal is underway.

BP operates and holds 80% of the West Mediterranean Deepwater concession with RWE Dea holding the remaining 20%. Hodoa was drilled by the Pride North America Semi-Sub rig, in a water depth of 1077 metres.

Mike Daly, BP's Executive Vice President of Exploration said: "The Hodoa discovery further demonstrates the great potential of the deep reservoirs in the Nile Delta."

Hesham Mekawi, President and General Manager of BP Egypt, commented: "Hodoa is an important discovery which builds upon BP's previous successes in the West Nile Delta. This discovery further reinforces the leadership role played by BP in Egypt and its ongoing commitment towards the development of Egypt's future gas business."

Statoil and partners awarded new licenses Offshore Greenland

Statoil and its consortium partners – Shell and GDF Suez – have been awarded two large exploration blocks in the Baffin Bay bid round in West Greenland. Shell will be the operator of both blocks.
Blocks 5 and 8, where Greenland’s national oil company Nunaoil will have a carried interest during the exploration phase, are 9,991 and 10,618 square kilometres, respectively. Each block is equivalent to approximately 15 Norwegian blocks.

“We are looking forward to exploring these new frontier opportunities in the Baffin Bay together with our partners in the bid consortium and in close cooperation with the Greenland authorities,” says Tim Dodson, Statoil’s senior vice president for global exploration.

“These awards increase the optionality of our exploration portfolio. While early access to such frontier opportunities entails more uncertainties related to probability of discovery, the potential reward of one or more sizeable discoveries may be high. Together with our partners, we will use all of our experience and competence from more than 30 years of oil and gas operations in harsh environments on the Norwegian continental shelf,” Dodson continues.

This is not the first time Statoil has carried out activities in Greenland. In the 1990s, Statoil drilled an exploration well in the Fylla area west of Greenland – but the company relinquished this exploration license in 2002. Statoil is also part of the Kanumas group in East Greenland.

Statoil already holds important Offshore positions in sub-Arctic conditions in Norway, Russia and Canada.

Anadarko makes third major gas discovery offshore Mozambique

Anadarko announced its third major natural gas discovery this year in the Offshore Area 1 of Mozambique's Rovuma Basin at the Lagosta prospect. The discovery well encountered a total of more than 550 net feet of natural gas pay in multiple high-quality Oligocene and Eocene sands.

"The Lagosta discovery, located approximately 16 miles to the south of the previously announced Barquentine discovery and 14 miles to the southeast of the Windjammer discovery, significantly expands this emerging world-class natural gas province," Anadarko Sr. Vice President, Worldwide Exploration Bob Daniels said. "The Lagosta discovery continues to validate our geophysical models, and we expect to keep the Belford Dolphin drillship in the basin for the foreseeable future to continue a very active exploration and appraisal program, including at least one planned drillstem test in 2011.

"Although additional appraisal drilling will be required, we believe the three discoveries announced to date already exceed the resource size threshold necessary to support an LNG (liquefied natural gas) development, and we have assigned an integrated project team to begin advancing commercialization options. Given the global LNG trade and its indexing to the global crude market, this resource can provide tremendous economic value for the people of Mozambique, the government and the partnership," added Daniels.

The Lagosta exploration well has been drilled to a current depth of approximately 13,850 feet in water depths of approximately 5,080 feet. The partnership plans to drill to a total depth of approximately 15,900 feet to evaluate a deeper zone. Once operations are complete at Lagosta, the partnership expects to mobilize the rig 17.5 miles to the southwest to drill the Tubarao exploration well, which also is located in the 2.6-million-acre Offshore Area 1.

Anadarko is the operator of Offshore Area 1 with a 36.5% working interest. Co-owners in the area are Mitsui E&P Mozambique Area 1, Limited (20%), BPRL Ventures Mozambique B.V. (10%), Videocon Mozambique Rovuma 1 Limited (10%) and Cove Energy Mozambique Rovuma Offshore, Ltd. (8.5%). Empresa Nacional de Hidrocarbonetos, ep's 15% interest is carried through the exploration phase.

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.

Cairn suspends drilling offshore Greenland

Cairn Energy has concluded all operations offshore Greenland with the end of the drilling season as agreed with the Greenland Bureau of Minerals and Petroleum (BMP), and the drillship Stena Forth and semisubmersible drilling rig Stena Don have been released off contract.

Cairn said it has suspended its Alpha-1S1 exploration well in the Sigguk Block approximately 175 km offshore Disko Island, west Greenland, to allow possible re-entry to sidetrack or deepen the well at a later date, and that the T8-1 and T4-1 exploration wells have been plugged and abandoned. It said the Alpha-1S1 well encountered oil shows in the volcanic section. In accordance with the BMP regulations, however, drilling operations ceased as of 30 September with the well still in volcanics and the prognosed Mesozoic section had not been reached.

The T4-1 well, which was targeting a Tertiary objective at a different stratigraphic level to T8-1, failed to encounter any significant hydrocarbons and found only thin reservoir sands, although geochemical analyses continue on selective samples. The T8-1 well, which encountered gas in thin sands has also been plugged and abandoned. Neither well resulted in commercial discoveries and their costs, some US$185 million, will be written off.

Cairn said since the primary objectives of the Alpha prospect were not reached, the well was suspended and any future re-entry work will depend on further evaluation.

Geophysical operations in Greenland are still active with a 2,500-km 2D seismic survey currently ongoing on the Eqqua Block, with some data to also be acquired in the Sigguk Block (less than 215 km) for well-tie purposes. A 7,400-km 2D survey was completed during the summer across the offshore south Greenland blocks.

Cairn said it has now drilled one third of all exploration wells ever drilled offshore Greenland and the first wells in the Greenland Arctic for almost 35 years, and that its campaign has demonstrated that drilling operations can be successfully and safely carried out in this area.

Mike Watts, Cairn's deputy CEO, said, "Exploration in Greenland is at a very early stage and consequently to have encountered both gas and oil in two of the first frontier exploration wells in the previously undrilled Baffin Bay geological basin is extremely encouraging. Cairn continues to evaluate all the data acquired this summer. Plans for the forward exploration program in 2011 are already underway and will be announced in the first quarter of 2011."

Cairn is the operator of the Sigguk Block and the three wells with 77.5% interest in partnership with Greenland's national oil company, Nunaoil, and Petronas Carigali, which holds 10% interest. Nunaoil is carried through the exploration phase but has a 12.5% stake in any development.

Rodinia, Ensign Australia partner for six-well drilling program

Rodinia Oil Corp. has announced that its Australian subsidiary, Officer Basin Energy Pty. Ltd., has executed an agreement with Ensign Australia Pty. Limited (“Ensign”) to carry out its initial six well drilling program. Rodinia’s drilling program will initially test six separate large structural targets using Ensign’s Rig 16 in the Officer Basin in South Australia, with drilling to begin in February 2011.

Rodinia is an international oil and gas company engaged in the exploration, acquisition and development of world-class onshore petroleum and natural gas assets in Australia’s Officer Basin. According to independent reserve evaluation firm, Ryder Scott, the estimated fair market value of Rodinia’s land holdings total $77 million and contain a potential 26.2 billion barrels of oil.

Petrobras drills ninth well in Tupi Field

Petroleo Brasileiro has concluded the drilling of the ninth well located in the Tupi area of Brazil's ultra deep Santos Basin Block BM-S-11, confirming the estimated volumes of recoverable light oil and natural gas to be in the range of between 5 and 8 billion boe in the pre-salt reservoirs of the Tupi area.

The well (known as Tupi SW) proved that the oil accumulation, not only is extended until the south extreme of Tupi's Evaluation Plan Area, but also proved that the thickness of the oil reservoir reaches around 128 m, thus reducing the uncertainty of the hydrocarbons volume estimate for Tupi's area.

The result of the drilling of this well is of significance because once it has defined, among other variables, the level of oil/water contact in the prospect, indicates the higher thickness of the oil rock.

Besides the high recoverable estimated volume, the oil in Tupi has a density of 28° API, which corresponds to an excellent commercial value. The declaration of commerciality is expected before December 31. Before then, two delimitation wells will be drilled.

The new well, is located in Tupi's Evaluation Plan Area, in a water depth of 2,152 m, around 290 km off the coast of Rio de Janeiro state and 11 km southwest of the Tupi Sul well, where the extended well test is being performed in the pre-salt reservoirs of Santos Basin. After confirming the expected productivity, the contractor group for BM-S-11 will study the allocation in the south of Tupi, of one of the standardized floating platforms that are being projected to operate in the pre-salt of Santos Basin. All activities and investments are being carried out in accordance with the evaluation plan already approved by Agencia Nacional do Petroleo (ANP).

Petrobras is the operator of Block BM-S-11 with 65% interest in partnership with BG Group, holding 25%, and Galp Energia, with the remaining 10% interest.

Tanzania's first deepwater well hits gas pay

Ophir announced that the Pweza-1 exploration well in the Mafia Basin offshore Tanzania has encountered a thick section of gas-bearing sands. The Pweza-1 well was drilled by Odfjell's semisub Deepsea Stavanger. Results from the Pweza-1 well, which has the potential to de-risk other prospects and leads in the basin, are currently being evaluated.

The Pweza-1 well is located in Block 4 which is operated by one of Ophir's wholly owned subsidiaries on behalf of a joint venture which consists of itself (40%) and BG International ("BG") (60%). The well is located approximately 85km from the coastline in a water depth of 1,400 meters. The Ophir/BG group joint venture has interests in Blocks 1, 3 and 4 offshore Tanzania which cover more than 27,000sq km of the Mafia Offshore Basin and northern portion of the Ruvuma Basin, in water depths ranging from approximately 100m to greater than 3,000m.

Pweza-1 is the first of a three-well initial work program planned for Blocks 1, 3 and 4. The program also includes the acquisition of 4 000 square kilometers of 3D seismic data. BG Group has the option to assume operatorship of all three Blocks upon completion of the initial work program.

The Ophir/BG joint venture now proposes to drill a further two wells as part of this first ever deepwater drilling campaign in Tanzania.

Ophir's Managing Director, Dr Alan Stein, commented, "The success of the Pweza-1 well is an excellent result for both the joint venture partners and for the Government of Tanzania on whose behalf we are exploring the area. This is the first deepwater well drilled in Tanzania. It has the potential to de-risk additional prospects and leads within the basin, providing a solid platform for further investment. A further two wells will now be drilled before the end of the year and we look forward to acquiring more 3D seismic data early next year. The joint venture has already negotiated a comprehensive series of agreements with the Government which provide a mechanism for the commercialization of offshore gas reserves."

Chevron sanctions first lower tertiary deepwater project in Gulf of Mexico

Chevron has sanctioned development of the Jack/St. Malo project, its first operated project located in the Lower Tertiary trend in the deepwater U.S. Gulf of Mexico.

"Jack/St. Malo is the latest example of Chevron advancing its industry-leading queue of major capital projects," said George Kirkland, vice chairman, Chevron Corporation. "The Lower Tertiary is recognized as a huge resource with the potential for long life projects of up to 30 to 40 years and the opportunity to enhance recoveries through technology."

The Jack and St. Malo fields are located within 25 miles (40 km) of each other approximately 280 miles (450 km) south of New Orleans, Louisiana, in water depths of 7,000 feet (2,100 m). The initial development of the project will require an investment of approximately $7.5 billion. It will be comprised of three subsea centers tied back to a hub production facility with a capacity of 170,000 barrels of oil and 42.5 million cubic feet of natural gas per day. Startup is anticipated in 2014.

The Jack and St. Malo fields are estimated to contain combined total recoverable resources in excess of 500 million oil-equivalent barrels. Seven exploration and appraisal wells have been successfully and safely drilled at these fields since 2003. Chevron, through its subsidiary Chevron U.S.A. Inc., has working interests of 50 percent in the Jack field, 51 percent in the St. Malo field, and 50.67 percent in the host facility.

Chevron is one of the top leaseholders in the Gulf of Mexico, averaging net daily production of 149,000 barrels of crude oil, 484 million cubic feet of natural gas and 14,000 barrels of natural gas liquids during 2009.

Success Story: Logging service - Canada | BakerHughes.com

Success Story: Logging service - Canada | BakerHughes.com

Total makes gas discovery in North Sea David prospect

Total E&P Norge AS made a gas/condensate discovery in well 25/5-7 on the David prospect, located about 12 miles (20 kilometers) northeast of the Heimdal field in the Norwegian sector of the North Sea. A gas column of about 230 feet (70 meters) was encountered in the Brent group (primary target) with better reservoir rocks and reservoir quality than expected.

The Statfjord formation, the secondary target, has good reservoir properties, but with aquifers. Preliminary estimates of the size of the discovery range between 2.4 and 3.2 million cubic meters of recoverable oil equivalents. Drilled by the Ocean Vanguard semisub, the well was not formation tested, but data was gathered. The partners in the license are considering connecting the discovery to the Heimdal field.

Total, serving as operator of the license, holds a 40% interest; Petoro holds 30%; Centrica Resources holds 20%; and Det norske holds the remaining 10%.

Total E&P Norge AS, operator of production license 102 C, is in the process of completing the drilling of wildcat well 25/5-7. The well is located about 20 kilometers northeast of the Heimdal field in the North Sea.

The primary exploration target for the well was to prove petroleum in the Middle Jurassic reservoir rocks (the Brent group). The secondary target was to prove petroleum in the lower Jurassic reservoir rocks (the Statfjord formation).

A gas column of 70 meters was encountered in the Brent group with better reservoir rocks and reservoir quality than expected. The Statfjord formation also has good reservoir properties, but with aquifers.

Preliminary estimates of the size of the discovery range between 2.4 and 3.2 million cubic meters of recoverable oil equivalents.

The well was not formation tested, but comprehensive data collection and sampling have been carried out. A gas-condensate reservoir of about 3000 Sm3/Sm3 is expected. The licensees in the production license will consider producing the discovery via the Heimdal field.

The well is the first wildcat well in production license 102 C. The well was drilled to a vertical depth of 3,045 meters below sea level, and was terminated in the Hegre group in the upper Triassic. Water depth at the site is 119 meters. The well will now be plugged and abandoned.

Well 25/5-7 was drilled by Ocean Vanguard. The drilling facility will now travel to production license 303, north of the Sleipner area in the North Sea, to drill delineation well 15/6-11 S, where Statoil ASA is the operator.

Reliance to complete Bay of Bengal exploration drilling

Reliance Industries has been instructed by India's Directorate General of Hydrocarbons (DGH) to complete its commitment exploration drilling offshore India's east coast in the Bay of Bengal Block KG-DWN-2001/1 (D-9 Block).

Sources at Reliance said today that the company anticipates bringing the exploration phase of its operations in the 2.8 million acre D-9 Block to a close before the end of the year. The company has already drilled the first two of the required three wells and is expected to commence the third well right away. The first well, KG-D9-A1 was drilled to a total depth of 4,800 meters (15,749 ft). The second well has been partially completed.

In addition to the three-well exploratory drilling requirement in Reliance's minimum work program for the D-9 Block, it was required to undertake a minimum 1,650 sq km 3D seismic survey, which has been concluded with more than twice that area, some 4,000 sq km, shot and processed.

Reliance is the operator of Block KG-DWN-2001/1 with 90% interest in partnership with Hardy Exploration and Production India, the local subsidiary of Hardy Oil & Gas, holding the remaining 10%.

ION expands ArcticSPAN seismic program to offshore Greenland

ION Geophysical has acquired 6,500 km of regional seismic data for sponsoring E&P clients in the Danmarkshavn Basin offshore northeastern Greenland, adding to the 5,300 km of data the company acquired there last season.

ION said that the Danmarkshavn Basin is one of the least explored, most prospective basins in the Arctic region, an area the United States Geological Survey (USGS) estimates could contain nearly 25% of the world's undiscovered oil and gas resources.

ION once again deployed its purpose-designed marine streamer technology to acquire data in the presence of ice. Together, ION's Intelligent Acquisition toolkit and Arctic program management expertise enabled the company to acquire data further north and in the presence of heavier ice than had been previously possible, at the same time mitigating HSE risk and reducing cycle time. As a result, the company is now confident that it has expanded the Arctic operational season to six months, dramatically longer than the industry's traditional acquisition season of one to two months.

Joe Gagliardi, ION's Arctic Solutions and Technology director, said, "This extension to our Greenland regional program was designed to provide a better understanding of high potential petroleum systems including the North Danmarkshavn Salt Basin, the Northeast Greenland Volcanic Province, and the Thetis Basin. The success of the 2010 expansion serves as further confirmation of the viability and value of our proprietary in-ice Arctic solution."

ION's ArcticSPAN program now includes more than 40,000 km of deeply imaged seismic data in the Arctic region covering the Beaufort-MacKenzie, Banks Island, Chukchi, East Greenland Rift, and Danmarkshavn Basins. Together, this data provide E&P companies with an understanding of the relationships among micro basins in the area, which they can use to more effectively assess the Arctic's hydrocarbon potential, identify new opportunities, and mitigate exploration risk.

Anadarko makes deepwater gas discovery off Mozambique

Anadarko announced that the Barquentine exploration well in the Offshore Area 1 of Mozambique's Rovuma Basin encountered a total of more than 416 net feet of natural gas pay in multiple high-quality sands.
The discovery well encountered more than 308 net feet of pay in two Oligocene sands that are separate and distinct geologic features, but age-equivalent to those encountered in Anadarko's previously announced Windjammer discovery. The well also found an additional 108 net feet of gas pay in the Paleocene sands, and the seismic data indicates this deeper pay section is contiguous and appears to be connected to the 75 net feet of pay encountered at the Windjammer discovery, located 2 miles to the southwest.

The Barquentine exploration well was drilled to a total depth of approximately 16,880 feet, in water depths of approximately 5,200 feet. Once operations are complete at Barquentine, the partnership plans to mobilize the Belford Dolphin drillship approximately 16 miles to the south to drill the Lagosta exploration well, also located in the Offshore Area 1 of the Rovuma Basin.

Anadarko currently holds more than 2.6 million acres in the basin where it has identified more than 50 prospects and leads.

Anadarko is the operator with a 36.5-percent working interest in the Offshore Area 1. Co-owners in the area are Mitsui E&P Mozambique Area 1, Limited (20 percent), BPRL Ventures Mozambique B.V. (10 percent), Videocon Mozambique Rovuma 1 Limited (10 percent) and Cove Energy Mozambique Rovuma Offshore, Ltd. (8.5 percent). Empresa Nacional de Hidrocarbonetos, ep's 15-percent interest is carried through the exploration phase.

FX Energy contracts Geofizyka Torun to shoot 2D seismic onshore Poland

FX Energy will begin a new 2D seismic acquisition program during the fourth quarter that is intended to identify drillsites in the company's 640,000-acre Warsaw South Concession (Lublin area) onshore Poland.

FX said today that it has contracted Geofizyka Torun to carry out the 273-km seismic survey, which will be processed and interpreted with plans to begin the tender for the first well in the Warsaw South Concession during January 2011. The first well is expected to begin drilling operations in March or April 2011.

FX Energy owns 100% interest and is the operator of the Warsaw South Concession, which is a virtually unexplored area at the terminus of the Permian Basin southeast of Warsaw. The primary exploration targets in the concession are Carboniferous, Zechstein Ca-1, and Rotliegend.

"We think there could be great potential in the Warsaw South Concession," said David Pierce, CEO at FX, "and we have wanted to explore the block for some time. Now, with our growing cashflow, we have the means to carry out a sustained exploration program in Warsaw South with the hope of opening up a new core area. Our primary focus remains our producing Fences Concession, but we are pleased now to be able to devote meaningful resources to exploration on our other acreage in Poland."

FX Energy also reported today that the Lisewo well in the company's Fences Block is currently drilling at a depth of approximately 1,500 meters. FX holds 49% interest in the Lisewo well, which is operated by the Polish Oil and Gas Company with 51%.

Kårstø gas facility celebrates 25 years in operation

It will be 25 years on 15 October since the first deliveries of dry gas from this facility north of Stavanger were made via the Statpipe and Norpipe lines to Emden in Germany.

Measured from 1 October 1985 to 1 October 2010, the plant has delivered natural and liquefied petroleum gases corresponding to 5 001 terawatt-hours by pipeline and ship respectively.

According to an overview from grid operator Statnett, Norway generated 2 984 TWh of electricity during the same period.

Now celebrating its 25th anniversary, Kårstø is one of Norway’s most important industrial facilities. Its capacity has increased more than fivefold since 1985, and it currently receives gas from 30 fields on the Norwegian continental shelf.

“The importance of Kårstø and the Draupner pipeline hub in the North Sea has not come by itself,” says Kjetil Ohm, head of processing and transport in Statoil’s Natural Gas business area.

“Many years of safe and efficient operation, with high regularity, has been the most important contribution. Each employee and our suppliers have also played a big part in helping to make Kårstø an attractive hub for new gas fields. The fact that we have attracted several thousand visitors from 98 countries in recent years also shows the interest for a plant of this kind in a global context.”

“Kårstø is a key link in the unique value chain which has allowed Norway to become the world’s second largest gas exporter,” says Brian Bjordal, chief executive of operator Gassco. “The history of this plant is nothing less than fantastic, and many people deserve great thanks for making such an industrial achievement possible. Mention must be made of the many thousands who have taken part in building up Kårstø, and of the pioneers who had the vision and drive to push through the decision to create Statpipe and this plant.”

The anniversary will be celebrated at a ceremony for owners, politicians and government authorities at Kårstø from 14.00 on 7 October. Celebrations for the workforce will be held in November and December.

Denbury to sell Haynesville, East Texas gas assets for $217 million

Denbury has entered into an agreement to sell its Haynesville and East Texas natural gas assets for approximately $217.5 million to a private oil and gas company. The sale is expected to close in 30 to 45 days and is subject to satisfactory completion of customary due diligence and closing conditions.

The agreement contemplates an effective date of September 1, 2010, and consequently operating net revenue after September 1, net of capital expenditures, along with other purchase price adjustments, will be accounted for as adjustments to the ultimate sales price.

Production attributable to the properties to be sold averaged approximately 34 MMcfe/d during the second quarter of 2010. The Company expects to utilize a Section 1031 like-kind-exchange with a portion of the proceeds expected from the sale of the Haynesville and East Texas assets and the previously announced Riley Ridge acquisition in order to reduce the estimated taxable gain on the sale.

The Company plans to use the balance of proceeds from the sale to repay most of its currently outstanding bank debt. RBC Richardson Barr acted as advisor to Denbury on the asset sale.

Total, DONG awarded Shetland contract by EMGS

Electromagnetic Geoservices ASA (EMGS) have signed a contract with Total E&P UK Ltd and DONG Energy to acquire 3D electromagnetic (EM) data in the West of Shetland area on the UK Continental Shelf. The value of the contract is estimated at worth approximately $1.5 million.

The 3D EM data acquired by EMGS will be used to de-risk a hydrocarbon prospect. The 3D EM survey has already started using EMGS's mobile acquisition set deployed from the vessel Siem Mollie, thereby extending the charter on this vessel from 1 to 21 October.

Roar Bekker, EMGS chief executive officer, commented: "We are delighted to continue our relationship with Total. The new direct contract award follows a successful 3D EM survey in 2009. The previous survey evaluated its mature North Sea Frigg field to facilitate decommissioning decisions. The two contracts demonstrate the value, which companies such as Total recognize, that EMGS can deliver across the exploration and production life cycle."