Tuesday, 28 October 2014

Statoil takes on offshore operatorship in Australia - 28/10/2014

Statoil takes on offshore operatorship in Australia

Statoil continues to expand in Australia, with the award of 100% equity share in a large exploration permit located in the prolific Northern Carnarvon Basin on the Northwest shelf of Australia.

This is Statoil’s third asset in Australia, adding to the onshore operatorship in the Northern Territory’s South Georgina basin and four BP-operated offshore permits in the Great Australian Bight.
Erling Vågnes, Statoil’s senior vice president for exploration in the Eastern hemisphere.
(Photo: Ole Jørgen Bratland)
The permit WA-506-P covers an area of more than 13,000 square kilometres, situated 300 kilometres off Western Australia in water depths of 1,500-2,000 metres. The permit has been awarded to Statoil by the National Offshore Petroleum Titles Administrator (NOPTA) through the 2013 Offshore Petroleum Exploration Acreage Release.

“This award adds another large acreage position with high-impact potential to our global portfolio, in line with our exploration strategy. This is an untested part of a prolific basin, offering significant upside potential,” says Erling Vågnes, Statoil’s senior vice president for exploration in the Eastern hemisphere.

Statoil has committed to collect 2,000 line kilometres of 2D seismic and 3,500 square kilometres of 3D seismic data within three years. Based on analysis of this information, Statoil will decide on further steps.

“This work programme offers the necessary flexibility for such a frontier area, and is supported by Australia’s stable regulatory framework and attractive fiscal terms,” says Vågnes.

Other parts of the Northern Carnarvon Basin have already proved large volumes of gas. It has multiple fields in production and established infrastructure.

Statoil has been present in Australia since 2012 with an office located in Adelaide.

New investor relations senior vice president appointed - 28/10/2014

New investor relations senior vice president appointed for Statoil

Statoil has announced that Peter Hutton has been appointed senior vice president CFO investor relations and will report to chief financial officer Torgrim Reitan.

Peter Hutton
Hutton is currently director of oil and gas research in RBC Capital Markets London, and has broad international experience from the oil and gas industry. He has spent 12 years in the oil and gas industry and 16 years within the financial industry.
Hutton holds a master of arts degree in modern history from the University of Oxford, UK and a diploma in international politics and the Middle East from Birkbeck College, UK. He will take on the role from 1 January 2015.
"Peter has extensive insight into the oil and gas industry and the financial markets. He has consistently been ranked as one of the best equity analysts and has a broad network across companies and institutions. I look forward to his contribution to Statoil and to have him as a part of my team," says Reitan.

MagneGas Acquires Independent Fuel Distribution Company - 28/10/2014

MagneGas Acquires Independent Fuel Distribution Company

Company Acquires Equipment Sales and Service, Inc. of Florida

TAMPA, Fla., Oct. 27, 2014 /PRNewswire/ -- MagneGas Corporation ("MagneGas" or the "Company") (NASDAQ: MNGA), a technology company that counts among its inventions a patented process that converts liquid waste into a hydrogen-based fuel, announced today that it has completed the acquisition of Equipment Sales and Service, Inc. ("ESSI") of Clearwater, Florida.  ESSI is an established industrial gas distribution company with estimated 2014 gross revenues of almost $2 million earned through the sales of industrial gases and related products.
MagneGas has purchased this established local industrial gas distributor to provide a platform to further MagneGas® fuel sales and expand its customer product availability.  The Company believes that the purchase of ESSI will allow more rapid market penetration to grow recurring sales of MagneGas® fuel while offering a wider range of services to industrial, metalworking, and fabrication customers. Established more than 20 years ago, this distributor is one of the largest independently owned gas distribution companies in the area offering a broad range of welding gas products and services.  MagneGas purchased 100% of the outstanding stock of ESSI in exchange for $3 million in cash paid at the closing.  The acquisition is expected to bring the overall MagneGas fuel division to a breakeven level in 2015.
"Having founded ESSI over 20 years ago based on customer service, I am pleased to see that it will stay independent with a Company such as MagneGas that is focused on customer satisfaction and innovation.  I am excited to have found an independent Company that is growing and cares about its customers as much as I do," stated Robert Ficocelli, Founder and CEO, Equipment Sales and Service, Inc.
"After acquiring this local well-established gas distributor, we are now entering the next phase of our expansion into the industrial, metal working, and fabrication markets. This purchase will provide a springboard to introduce and sell Magnegas2® fuel to a wider audience of customers around the Tampa Bay area," stated Ermanno Santilli, CEO of MagneGas Corporation. "Separately, we have purchased a nearby industrial building which will allow for the expansion of MagneGas headquarters as we continue to attract customers and partners from around the world." 

Cargo number 500 leaves Snøhvit - 28/10/2014

Cargo number 500 leaves Snøhvit

Snøhvit cargo number 500 was loaded at Melkøya on Monday 27 October. Since start-up in 2007 more than NOK 80 billion worth of LNG has been dispatched from Melkøya.

The special vessel Arctic Voyager at the Snøhvit plant in Hammerfest.
The special vessel Arctic Voyager is the 500th to visit Melkøya and Hammerfest to carry product from the Snøhvit plant. The vessel will freight a cargo of LNG from Melkøya, Norway to Aliaga, Turkey.

With this cargo, the Snøhvit plant has produced and delivered LNG worth NOK 82 billion since start-up in 2007.
Bilde Knut Gjertsen, vice president for operations on Snøhvit.

In addition, considerable value has been added through the export of LPG and condensate from the field.

“This is a special day for the Snøhvit organisation and for Statoil. A lot of hard work has gone into all these 500 cargoes,” says vice president for operations on Snøhvit Knut Gjertsen.

He believes Snøhvit is a unique plant with its pioneering, new technology that has enabled the production and export of LNG from Hammerfest, the world’s northernmost town.

Snøhvit is currently the most energy-efficient LNG plant in the world, with the lowest carbon emissions per unit produced.

“Snøhvit has also been a challenge. We’ve worked long and systematically on the plant, and with the organisation, in order to stabilise operations. We are now beginning to see the results. During the past 15 months we’ve delivered our best results for safe and regular production. We work hard and systematically every single day to continue delivering good results,” says Gjertsen.
Geir Heitmann, Statoil vice president for LNG trading.
Statoil sells LNG to Europe, Asia, and North and South America. The gas is transported in liquid form in special vessels that can sail across the Atlantic, through the Suez Canal, and even through the North-East Passage to get to gas markets.

An LNG vessel carries a cargo of substantial value and flexibility of destination means that there can be great value in optimising a portfolio to exploit the different market prices prevailing in various regions.

“A single cargo may have a market value of around NOK 250 million, which means that even small price differentiation between markets can result in substantial added value for Statoil. That makes LNG trading an important way of maximising the value of the Snøhvit gas,” says Statoil vice president for LNG trading Geir Heitmann.

LNG currently accounts for approximately 10% of the global gas market. In the years ahead, new LNG export projects will be completed in Australia, the USA and elsewhere.

That means that LNG will be an increasingly important factor in balancing the global market and will have a considerable impact on the price of gas in different regions.
Kai-Otto Nilsen, Petter Fagerheim, Cato Osenbroch and Torfinn Isaksen with the special vessel Arctic Voyager in the background.

World’s first subsea wet gas compressor one step closer to Gullfaks - 28/10/2014

World’s first subsea wet gas compressor one step closer to Gullfaks 

The world’s first subsea wet gas compressor station is now ready for the final testing at Horsøy outside Bergen before being prepared for installation and hook-up to Gullfaks C in 2015.

The compressor has been mechanically completed and trial fitted by Radøy Gruppen on Radøy, and is now ready for final system integration tests at One Subsea Horsøy. (Photo: Statoil)

By adding 22 million extra barrels of oil equivalent from the Gullfaks South Brent reservoir the compressor will help extend the field’s productive life.

Local technology cooperationStarting back in 2008 the efforts to develop and qualify the compressor in line with Statoil’s requirements represent a good example of Statoil’s cooperation with the Norwegian supply industry to develop robust improved oil recovery solutions. 
“The compressor in principle builds on Framo Engineering’s multi-phase pumps, which have been used by Statoil for several decades, including on the Gullfaks field,” says Bjørn Birkeland, project manager for the Gullfaks subsea project.  
The compressor is developed in cooperation with One Subsea (formerly Framo Engineering), and large parts of the compressor station have been built by suppliers and sub-suppliers in western Norway and in the Bergen region. The delivery from One Subsea consists of a 420-tonne protective structure, a compressor station with two compressors totalling 650 tonnes, and all necessary topsides equipment for power supply and control of the plant.
This type of subsea installation attracts a great deal of interest, and the first period after start-up will be important with a view to gaining operating experience to be drawn on by other fields that may consider using this type of technology. 
The world’s first subsea wet gas compressor.
The compressor station has been mechanically commissioned and test-assembled at Radøygruppen’s yard at Radøy, and is now ready for the final system integration tests implemented by One Subsea at Horsøy. The last test phase will verify that all units of the new subsea compressor station work as expected. 
“There is currently a strong focus in the offshore industry on cost-efficient solutions, and it is therefore particularly nice to note that this new technology has been locally developed, qualified and is being implemented by means of local subsea suppliers,” says operations west asset manager Steinar Konradsen.

The possibility of tying in several of the subsea templates connected to Gullfaks C to the compressor station will also be considered. This will further increase the profitability of the project.

Important for subsea factory future “Together with the technology developed through Åsgard subsea compression the technology in Gullfaks represents important pieces of the jigsaw puzzle of designing the subsea factories of the future,” says Roald Sirevaag, Statoil vice president subsea technology and operations.
“We now have control of the main pieces, so in the future the challenge is to reuse these, putting them together in ways that suit the individual reservoir. Close and good cooperation between operations, project and technology communities will be key to the successful achievement of this,” says Sirevaag.
Why subsea compression? Compression on the seabed gives a better effect than a conventional topside compressor. In addition, there is an advantage that the platform avoids the increase in weight and space a topside compression module requires. The advantage of a wet gas compression facility is that it does not require any treatment of the wellstream before compression. This makes for smaller modules and a simpler construction on the seabed.

Kværner ASA: Third quarter results 2014 - 28/10/2014

Kværner ASA: Third quarter results 2014

Increased activity. Kvaerner's third quarter results reflect an increased activity level. Kvaerner is in a market segment where there are key upcoming projects, and the company is about to complete the processes to improve its competitive position in time for new bids. Operating revenues for the third quarter amounted to NOK 4 004 million, compared with NOK 3 080 million for third quarter 2013. Earnings before Interest, Taxes, Depreciation and Amortisation (EBITDA) for the quarter were NOK 194 million, compared with NOK 180 million in the same period last year.

Kvaerner reported operating revenues of NOK 10 354 million for the first nine months of 2014, compared with NOK 9 021 million for the same period in 2013. With an EBITDA result for the last quarter of NOK 194 million versus NOK 180 million one year before, the EBITDA margin for third quarter 2014 was 4.8 percent, down from 5.9 percent in corresponding period in 2013. EBITDA for the first nine months of 2014 was NOK 653 million, compared with NOK 456 million for the same period in 2013.

- Throughout 2014, we have systematically implemented measures to increase efficiency. The aim for this process is to enable competitive prices for new projects in parallel with gradual margin improvements. As a first step, we expect to complete the announced 15 percent cost reductions over the next months. However, as we communicated in second quarter, it is challenging to capture the full effect of improvements in on-going projects. The negative cost developments we experienced last quarter have not improved in third quarter, putting pressure on margins says Jan Arve Haugan, President & CEO of Kvaerner.
Order intake in third quarter totalled NOK 2 801 million, including scope of work of jointly controlled entities, compared to NOK 1 594 million in the same quarter last year. As of 30 September 2014, the order backlog, including scope of work of jointly controlled entities, amounted to NOK 19 353 million. Estimated scheduling for the order backlog is approximately 20 percent for execution in 2014, approximately 40 percent for execution in 2015 and remaining 40 percent for execution in 2016 and later.

Kvaerner has enjoyed a high activity level through the past 12 months, and expects this situation to continue into 2015. During third quarter, Kvaerner successfully completed the work on the Transocean Barents drilling rig ahead of schedule. The Hebron GBS was successfully towed out to the deep water site where the remaining construction activities will continue. The Edvard Grieg topside has progressed as planned, and the living quarter and other key sections have now been assembled at Stord and in Egersund. Work on the Nyhamna expansion continues with civil work on site and construction of modules has started in six different fabrication yards. Kvaerner is also a key contractor for the offshore commissioning and project completion for the Eldfisk 2/7 S topside, which was delivered from Kvaerner earlier this year.

Wednesday, 22 October 2014

New oil resources proved in the Grane area - 22/10/2014

New oil resources proved in the Grane area 

Operator Statoil has together with PL169 partners proved new oil resources in the D-structure in the vicinity of the Grane field in the North Sea.Bilde
Well 25/8-18 S, drilled by the rig Transocean Leader, proved an oil column of 25 metres in the Heimdal Formation. The estimated volume of the discovery is in the range of 30-80 million barrels of recoverable oil.
"We are pleased with having proved new oil resources in the Grane area," says May-Liss Hauknes, Statoil vice president for exploration in the North Sea. "Near-field exploration is an important part of Statoil’s exploration portfolio on the Norwegian continental shelf. It provides high-value barrels that are important for extending the production life of existing installations.”
The D-structure is located on the Utsira High, just seven kilometres north of the Grane field and in the immediate proximity of the Grane F oil discovery made by Statoil in 2013. The D-structure was originally penetrated in 1992 by well 25/8-4, which encountered just one metre of oil corresponding to about six million barrels.
“Well 25/8-18 S appraised the D-structure and proved substantial additional oil volumes in an excellent sandstone reservoir. This is a result of a recent re-evaluation of the area done by the partnership. New seismic and improved subsurface mapping have given us new confidence in the D-structure and allowed to mature it towards a drilling decision,” says Hauknes.
“Tie in to the nearby Grane field is one of the development solutions that will be evaluated for the discovery,” according to Gro Aksnes, Statoil vice president for area development in Operations West.
Exploration well 25/8-18 S is located in PL169 in the North Sea. Statoil is operator with an interest of 57%. The partners are Petoro AS (30%) and ExxonMobil Exploration & Production Norway AS (13%).

The Grane platform in the North Sea. (Photo: Harald Pettersen)
The Transocean Leader drilling rig. (Photo: Harald Pettersen)

Gazprom getting ready to provide reliable gas supplies to consumers in Russia and abroad during cold winter - 22/10/2014

Gazprom getting ready to provide reliable gas supplies to consumers in Russia and abroad during cold winter

Gazprom getting ready to provide reliable gas supplies to consumers in Russia and abroad during cold winter
Enlarged photo (JPG, 243 KB)
The Gazprom Management Committee examined the Unified Gas Supply System(UGSS) availability for peak loads in autumn/winter 2014–2015 and addressed steps to be taken over the long term for securing continuous gas supply to consumers during the winter period.
Zapolyarnoye field
The meeting pointed out that Gazprom's comprehensive efforts aimed at the preparations for the coming autumn/winter period, which the Hydrometcenter forecasts to be colder than usual, would provide reliable gas supplies to the Russian regions and fulfill contract obligations to European consumers.
In the course of preparations for winter 2014–2015, all 17 scheduled maintenance and repair operations were carried out at the UGSS facilities. 1,264.47 kilometers of gas pipelines and 262 gas distribution stations were overhauled; 18.75 thousand kilometers of gas pipelines underwent in-line inspection during the nine months of the current year. 61 and 863 submerged crossings were repaired and inspected accordingly; 544 gas compressor units and 32 kilometers of compressor stations piping were subjected to renovation and repair respectively.
As a result of the active expansion of the underground gas storage (UGS) network, the potential output of domestic Gazprom's UGS facilities hit a record high: the maximum daily output by the withdrawal season increased to 770.4, i.e. 42.6 million cubic meters more versus last year. The increment of the average daily output is commensurate with the average daily gas consumption during the winter period in some Russian constituent entities, for example, in the Krasnodar Territory or the Orenburg Region.
Energetic efforts are being made for replenishing the UGS facilities with gas that was withdrawn during the last autumn/winter period as well as accumulating 71.133 billion cubic meters as the operating gas reserves of Russian UGS facilities, up 2.116 billion cubic meters versus 2013. This will be a record high amount in the history of the Russian gas industry.
Taking into account the UGS facilities located in Belarus, Gazprom's operating gas reserves will amount to 72.168 billion cubic meters, with the potential maximum daily output of UGS facilities by the withdrawal season start reaching 801.4 million cubic meters of gas. In addition, in early 2014 Gazprom acquired Gazprom Armenia, the owner of the Abovyan UGS facility featuring the following performances: operating gas reserve – 122 million cubic meters, potential maximum daily output by the withdrawal season – 9 million cubic meters.
Gazprom goes on with regular activities for injecting gas into the European UGS facilities, thus giving an additional guarantee to comfortably come through the peak load periods. The Company has already injected over 3.8 billion cubic meters of its gas into the European UGS facilities, versus 5 billion cubic meters scheduled. In addition, another 1.8 billion cubic meters of the Company's gas was injected into the Incukalns UGS facility (Latvia), versus 2 billion cubic meters scheduled.
In the 2014–2015 autumn/winter period the maximum gas output may reach 1.690 billion cubic meters a day. In order to provide for the failsafe operation of gas production companies, 95 comprehensive gas treatment and gas pretreatment units were subjected to full-scope repairs. As of October 1, 2014, 375 field wells were overhauled. In addition, this year the gas site (GP-1) with the annual output of 30 billion cubic meters of gas as well as a booster compressor station are to be commissioned in the Bovanenkovskoye field; booster compressor stations – in the Urengoyskoye field and the Vyngaiakhinskoye gas production facility; 113 wells – in the Bovanenkovskoye, Yamburgskoye, Urengoyskoye, Astrakhanskoye and Kirinskoye fields.
At the same time, successful operation during peak loads will largely depend on maintaining backup fuel (fuel oil, coal, etc.) reserves by consumers as well as on the regional gas consumption discipline. Therefore, the Management Committee meeting stressed that Gazprom would pay close attention to industrial companies observing the gas payment discipline within the specified limits.
All the planned maintenance and repair activities were completed within the schedule at the key export gas routes, directly connecting Gazprom with consumers – the Yamal – Europe, the Blue Stream and the Nord Stream gas pipelines.
Gazprom's relevant units, heads of subsidiaries and organizations were tasked to commission in due time the major gas production, transmission and underground storage facilities influencing the UGSS operation in the 2014–2015 autumn/winter period, complete timely preparation of the UGSS facilities for operation and ensure reliable and sustained functioning of process facilities.

Alexey Miller extends condolences upon tragic death of Christophe de Margerie - 22/10/2014

Alexey Miller extends condolences upon tragic death of Christophe de Margerie

Alexey Miller sent a telegram of condolences on Christophe de Margerie’s tragic death to the Total Moscow office:
On behalf of the Gazprom Management Committee and on my own behalf I would like to extend my heartfelt condolences upon your grievous loss – the life of Christophe de Margerie, Chairman and Chief Executive Officer of Total tragically ended.
A gifted leader, an influential politician, a man respected by everyone who knew him passed away. We deeply feel for the friends and family, for all who had the great honor to know Christophe de Margerie and work with him.
Alexey Miller, Chairman of the Gazprom Management Committee
Christophe de Margerie. Photo by RIA Novosti
Christophe de Margerie. Photo by RIA Novosti

Monday, 20 October 2014

Construction permit for South Stream’s top-priority section in Serbia may be obtained soon - 20/10/2014

Construction permit for South Stream’s top-priority section in Serbia may be obtained soon

Belgrade hosted today a working meeting between Alexey Miller, Chairman of the Gazprom Management Committee and Dusan Bajatovic, Director General of state-owned Srbijagas.
The meeting addressed the issue of current and winter gas supplies to Serbia.
The meeting participants discussed the progress with the South Stream project. The pipeline route is being designed in Serbia within the project. In the near future the construction permit will be obtained for the South Stream's top-priority section in Serbia.
Construction permit for South Stream’s top-priority section in Serbia may be obtained soon
Layout of South Stream’s Serbian section and existing gas pipelines in Serbia



Following the recent announcement on 21 July concerning the transaction to divest of an interest in the Greater Bualuang Area, Salamander today announces that it has submitted a draft shareholder circular to the Financial Conduct Authority.
Salamander previously announced on 21 July 2014 the signing of an agreement under which Sona Petroleum Berhard (“SONA”) would acquire an effective 40% working interest in the B8/38 concession (containing the Bualuang oil field) and the surrounding G4/50 concession, both located in the Gulf of Thailand (together the “Transaction”).
Salamander understands that SONA is expecting to receive clearance from the Malaysian Securities Commission (“MSC”) in the coming weeks. Once the MSC clearance has been received then both parties intend to seek their respective shareholder approvals in accordance with their contractual obligations under the SPA. Completion of the Transaction is conditional on, amongst other things, obtaining these approvals and is expected to occur before the end of 2014, in keeping with the timetable previously outlined.

Tangiers Petroleum Limited General Meeting Results - 20/10/2014


In accordance with Listing Rule 3.13.2 and Section 251AA of the Corporations Act, the 
following information is provided to ASX in relation to the resolutions passed by the 
members of Tangiers Petroleum Limited (ASX: TPT; AIM: TPET, “Tangiers”, 
“Company”) at its General Meeting held on 20 October 2014. 
The instructions given to validly appointed proxies in respect of each resolution were as 

Resolution 1: Placement of Shares 


The motion was carried as an ordinary resolution on a show of hands.

Resolution 2: Authority for David Wall to participate in the Placement 


The motion was carried as an ordinary resolution on a show of hands.

Resolution 3: Authority for Michael Evans to participate in the Placement 


The motion was carried as an ordinary resolution on a show of hands.

Resolution 4: Authority for Stephen Staley to participate in the Placement 


The motion was carried as an ordinary resolution on a show of hands.

Thursday, 16 October 2014

Drilling permit for well 7227/10-1 in production licence 230 - 16/10/2014

Drilling permit for well 7227/10-1 in production licence 230

The Norwegian Petroleum Directorate has granted Statoil Petroleum AS a drilling permit for well 7227/10-1, cf. Section 8 of the Resource Management Regulations.
Well 7227/10-1 will be drilled from the Transocean Spitsbergen drilling facility at position 72°09’ 48.72" north and 70° 14´ 18.14" east.
The drilling programme for well 7227/10-1 relates to the drilling of a wildcat well in production licence 230. Statoil Petroleum AS is the operator with a 35 per cent ownership interest and the licensees are Spike Exploration Holding AS with 30 per cent, Explora Petroleum AS with 20 per cent and GDF SUEZ E&P Norge AS with 15 per cent. 
The production licence consists of parts of blocks 7227/8, 7227/9 and 7227/10. The licence was awarded in the Barents Sea project in 1997.
Wildcat well 7227/10-1 will be the first exploration well in production licence 230.
The permit is contingent upon the operator securing all other permits and consents required by other authorities prior to commencing the drilling activity. 

Gazprom and YPF discuss possible gas developments in Argentina - 16/10/2014

Gazprom and YPF discuss possible gas developments in Argentina

The Gazprom headquarters hosted today a working meeting between Alexey Miller, Chairman of the Company's Management Committee and Miguel Galuccio, Chief Executive Officer of Argentine National Petroleum Company YPF.
The parties addressed the prospects for expanding the bilateral cooperation in the gas sector. In particular, they looked at the possibility of undertaking joint projects in such areas as exploration & development in Argentina.
In addition, the meeting participants discussed the arrangement of LNG supply from Gazprom Group's portfolio to the Republic as well as expressed their views on the joint development of the Argentine NGV market.
The meeting also paid attention to the sci-tech cooperation between the two companies, experience sharing and personnel training.
Gazprom and YPF discuss possible gas developments in Argentina
Photo provided by YPF

Tuesday, 14 October 2014

New head of the Harstad office - 14/10/2014

New head of the Harstad office

Stig-Morten Knutsen (49) has been appointed as head of the NPD’s Harstad office.
His duties will include responsibility for the annual Awards in Pre-defined Areas (APA). He will be part of the management team under exploration director Sissel Eriksen.
Knutsen has broad experience from various aspects of the petroleum activities. He is a geologist, and also holds a BSc in psychology.
Stig-Morten Knutsen has nearly 25 years of work experience from Hydro, and completed both an MSc and PhD during this time.
After a few years as a consultant, he was hired as exploration manager in Greenland’s national oil company Nunaoil.
Eight exploration wells were drilled during his three-to-four-year tenure here. Grønland has a very large shelf, and 14 exploration wells have so far been drilled here. No commercial discoveries have been made, but vast areas have yet to be surveyed.
Before he started working for the NPD, he held management positions at the research institutions Roald Amundsen Petroleum Research and ARCEx in Tromsø.

Significant oil and gas discovery northwest of the Snøhvit field in the Barents Sea - 7220/11-1 - 14/10/2014

Significant oil and gas discovery northwest of the Snøhvit field in the Barents Sea - 7220/11-1

Lundin Norway AS, operator of production licence 609, is in the process of concluding the drilling of wildcat well 7220/11-1, which proved both oil and gas.
The well was drilled about 20 kilometres northeast of oil and gas discovery 7120/1-3 and about 190 kilometres northwest of Hammerfest.
The well’s primary exploration target was to prove petroleum in sandstone rocks from the Middle Triassic period (Kobbe formation in the Sassendalen group) and in chalk rocks from the Permian period (Ørn formation in the Gipsdalen group). The secondary exploration target was to prove petroleum in reservoir rocks from the Carboniferous period (Falk formation in the Gipsdalen group).
The well encountered a 45-metre total oil column with an overlying 10-metre gas column in carbonate rocks in the Gipsdalen group, with good reservoir properties.
Preliminary estimates of the size of the discovery are between 14 and 50 million standard cubic metres (Sm3) of recoverable oil, and between 5 and 17 billion standard cubic metres of recoverable gas. Further delineation of the discovery is planned for 2015.
Extensive data collection and sampling have been performed. Two successful formation tests have been carried out in the oil zone, both of which indicated good flow properties. The maximum production rate was 518 Sm3 of oil and 48 700 Sm3 of associated gas per flow day through a 36/64-inch nozzle. The gas/oil ratio is 94 Sm3/Sm3.
This well is the first exploration well in production licence 609, which was awarded in the 21st licencing round in 2011.
The well was drilled to a vertical depth of 2221 metres below the sea surface, and was terminated in the Ugle formation from the Late Carboniferous period. The water depth is 388 metres. The well will now be permanently plugged and abandoned.
Well 7220/11-1 was drilled by the Island Innovator drilling facility, which will now move to production licence 625 in the North Sea to drill wildcat well 25/10-12 S, where Lundin Norway AS is the operator.

Statoil makes seventh discovery offshore Tanzania - 14/10/2014

Statoil makes seventh discovery offshore Tanzania 

Statoil and co-venturer Exxon Mobil today announced that the Giligiliani-1 exploration well has resulted in a new natural gas discovery offshore Tanzania.

The discovery of an additional 1.2 trillion cubic feet (tcf*) of natural gas in place in the Giligiliani-1 well brings the total of in-place volumes up to approximately 21 tcf in block 2.
The Giligiliani-1 discovery is located along the western side of block 2 at a 2,500-metre water depth. The new gas discovery was made in Upper Cretaceous sandstones.
Nick Maden, senior vice president for Statoil's exploration activities in the Western Hemisphere. (Photo: Ole Jørgen Bratland)
“This discovery has proven the gas play extends into the western part of block 2, which opens additional prospects. Our success rate in Tanzania has been high and opening up a new area will be key to continuing our successful multi-well programme,” said Nick Maden, senior vice president for Statoil's exploration activities in the Western Hemisphere.
The rig Discoverer Americas will now drill the Kungamanga prospect located in the central part of block 2.
The Giligiliani-1 discovery is the venture’s seventh discovery in block 2. It is preceded by the five high-impact gas discoveries Zafarani-1, Lavani-1, Tangawizi-1, Mronge-1 and Piri-1, and a discovery in Lavani-2.
Statoil operates the licence on block 2 on behalf of Tanzania Petroleum Development Corporation (TPDC) and has a 65% working interest. ExxonMobil Exploration and Production Tanzania Limited holds the remaining 35%. Statoil has been in Tanzania since 2007, when it was awarded the operatorship for block 2.
(*1 Tcf =180 million barrels of oil equivalent)

Monday, 13 October 2014

MagneGas Hires Vice President of Engineering to Oversee Growing Development Initiatives - 13/10/2014

MagneGas Hires Vice President of Engineering to Oversee Growing Development Initiatives

Richard Conz Brings Experience Managing Multi-Billion Dollar Projects at Multinational Companies

MagneGas® Corporation ("MagneGas" or the "Company") (NASDAQ: MNGA), a technology company that includes among its inventions a patented process that converts liquid waste into a hydrogen-based fuel, announced today the addition of Richard Conz, Vice President of Engineering.
Mr. Conz joins MagneGas as part of the Company's push to upgrade its engineering and project management capabilities. Mr. Conz's experience working in multinationals, such as Raytheon, and running multi-billion dollar projects makes him a great asset to the team. His experience will be critical to the joint ventures, product launches and testing programs the Company is pursuing.
Mr. Conz holds a bachelor's degree in Electrical and Electronics Engineering from Wayne State University. He is also Six Sigma Certified and was honored with the Commander's Award for Public Service for Operation Desert Shield/Desert Storm by the U.S. Army.
"Rick brings significant program management and engineering experience to the team to take us to the next level. The addition of Rick will immediately improve MagneGas's abilities to manage product launches and R&D projects," commented Jack Armstrong, Senior Vice President at MagneGas.
"As MagneGas continues its transition to a more process-centric organization, Rick brings critical skills to further improve our Engineering and Program Management skill set," commented Ermanno Santilli, CEO of MagneGas.  "With more product launches, certification projects and joint ventures in development than at any time in Company history, he is an integral and valuable addition to the team."
The MagneGas IR App is now available for free in Apple's App Store for the iPhone or iPad http://bit.ly/AfLYww and at Google Play http://bit.ly/Km2iyk for Android mobile devices.
To be added to the MagneGas investor email list, please email pcarlson@kcsa.com with MNGA in the subject line.

Virtus Oil and Gas Announces Results of 2D Seismic Interpretation - 13/10/2014

Virtus Oil and Gas Announces Results of 2D Seismic Interpretation

Virtus Oil and Gas Corporation (OTCBB: VOIL) ("Virtus" or the "Company") today announced that the seismic reprocessing and interpretation efforts of its recently purchased 47 miles of 2D seismic data in the Parowan Project now reaches completion today.
Key Findings
Virtus recently purchased the 2D data to complement its existing seismic library in order to better understand the geology and delineate its acreage footprint within the Parowan project. Seismic data will be the dominant data source used to choose the location of Virtus' exploratory well.
Dr. Robert (Bob) Benson, Exploration Director at Virtus Oil and Gas summarized the key findings from his reprocessing and interpretation efforts below:
  • Key Finding #1: The improved interpretation confirmed the presence of a complex structural closure associated with multiple thrust faults caused by compressional tectonic events. Dr. Benson believes the structure has the potential to trap Oil and Natural Gas, which is one of many necessary components for a reservoir to produce Oil and Gas. 
  • Key Finding #2: The three new lines of seismic data confirm that none of the existing wells in the area have intersected the targeted reservoirs. 
  • Key Finding #3: The two reservoir zones most prospective on the acreage are the Jurassic age Navajo Sandstone and the Permian age Kaibab Limestone.  Additional secondary targets with intervals both shallower and deeper showed potential for future exploration. The primary prospect is a large anticline that is created by the thrust fault system in the area. 
    • Figure 1 is a map showing the time structure map of the prospect indicating approximately 80 milliseconds of closure, which calculates to be over 500 feet. The structure persists from the Navajo level through the Kaibab and deeper horizons.  The structural apex of the deeper prospects shift slightly from the shallower Navajo structure.   View Figure 1.
    • Figures 2 and 3 are seismic lines crossing the potential reservoirs from the northwest to the southeast, which is perpendicular to the axis of the structure that strikes northeast to the southwest. The apex of the structure is interpreted to the west of the reservoirs truncation into a possible back thrust and the Quaternary valley fill sedimentary sequence. The seismic data also indicates the potential for an additional structure to the northwest and down dip of the primary structure. View Figures 2 and 3.
Next Steps
Moving forward, Virtus will now determine what additional seismic data the Company will need to acquire on a proprietary basis in order to provide the additional control necessary for drilling its first well in the Parowan area. Planning is already underway to begin the acquisition of this seismic data.
In the meantime, Virtus' Chief Operations Officer Brett Murray has already commenced the first steps to establish Federal Units on the Parowan acreage. (In Utah, Federal exploratory units are mandatory and are formed in order to explore for conventional and/or unconventional resources).
Management Comments:
Dr. Benson says, "I am very excited about how the Parowan prospects are developing.  This recently purchased seismic data is some of the best quality data acquired to date. It confirms the interpreted structures and provides the needed encouragement to move forward in developing these potentially large reservoirs."

MagneGas Joint Venture Partner Files Comprehensive Co-Combustion Patent - 13/10/2014

MagneGas Joint Venture Partner Files Comprehensive Co-Combustion Patent

MagneGas Partner FuturEnergy of Australia Files Patent Utilizing MagneGas® Fuel in Co-Combustion
MagneGas Corporation, www.magnegas.com ("MagneGas" or the "Company") (NASDAQ: MNGA), a leading technology company that counts among its inventions a technology that converts liquid waste into a hydrogen-based fuel, today announced that its partner, FuturEnergy Pty Ltd of Australia, submitted a pioneer patent on combusting coal emissions containing CO2 in a secondary post combustion chamber with MagneGas® fuel. The patent, 'Utilising synergistic mixture of fuel to produce energy and reduce emissions in boilers,' was filed with the Australian patent office based on a previously filed provisional patent. 
As previously announced, MagneGas Corporation and FuturEnergy Pty Ltd have formed a Joint Venture for the purpose of developing, licensing and commercializing new intellectual property for co-combustion of MagneGas fuels with hydrocarbon fuels to reduce emissions and increase energy. This agreement includes other current and future developments such as the combustion of MagneGas® with diesel, heavy oil, aviation fuels, and liquid petroleum gas.  The Joint Venture has licensed the use of its patent to a confidential partner in Michigan for the purpose of commercializing the technology for Coal Co-Combustion in the United States and Canada.  The data in the attached FuturEnergy press release was obtained through internal testing using MagneGas partners. The Company is in the process of independently verifying the data through a third-party research laboratory associated with a major utility.
A link to the FuturEnergy press release can be found here:
The MagneGas IR App is now available for free in Apple's App Store for the iPhone or iPad http://bit.ly/AfLYww and at Google Play http://bit.ly/Km2iyk for Android mobile devices.

Dejour Updates Kokopelli Drilling Status Spuds 1st Production Well of the 2014 Program - 13/10/2014

Dejour Updates Kokopelli Drilling Status Spuds 1st Production Well of the 2014 Program 

Dejour Energy Inc. (NYSE MKT: DEJ / TSX: DEJ) (“Dejour” or the “Company”), an independent oil and natural gas exploration and production companyoperating in North America's Piceance Basin and Peace River Arch regions, updates current development progress underway at the Kokopelli Project (“Kokopelli”).

The Frontier-28 rig has completed drilling and casing the water disposal well on Pad 21A, vital to the economics of the ongoing Kokopelli production programs. The rig has now been moved to Pad 21B, less than 500 yards away, where it has successfully spud the Federal 14-15-1-21 well (a Williams Fork test with a projected depth of ~8500’), the first of eight new production wells to be drilled, logged and cased sequentially prior to fracking, completion and tie-in operations to our contracted gathering facilities.

Dejour owns a 25% working interest in the Kokopelli Project and is carried for 25% of the first US$16 million in expenditures. To date the program is on time and on budget. Additional information will be provided as available.

“We remain focused on building a significant, liquids-rich producing resource that highlights our Colorado-based holdings. Upon successful fracture stimulation of the wells, we anticipate entering 2015 with an attractive U.S. production profile and a plan for an aggressive ongoing development program, particularly if the Mancos tests successfully,” stated Robert Hodgkinson, CEO.