http://www.euro-petrole.comLes dernières nouvelles du site EuropétrolefrEuropétrole5964http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5964Thu, 02 Feb 2012 00:00:00 +0100
58 million euros, which is most of the investments in 2012, will be devoted to expanding and improving the CLH storage facilities. The most important part, 27 million euros, will be used in the expansion of storage capacity and operational improvements at several facilities, and a further 16 million euros will go to investments in environmental protection and safety.

The investments in this heading also include 15 million euros that are earmarked for completing construction of the new facilities in Castellanos de Moriscos (Salamanca) and Almodóvar del Campo (Ciudad Real) that are currently under way.

Regarding expansion of the transport network, CLH will be investing over 24 million euros on extending its pipeline network. Of this amount, around 12 million euros will be spent on building the pipeline connection between the storage facility in Torrejón de Ardoz and Madrid-Barajas airport.

On the other hand, CLH will devote 16 million euros to expanding and improving the CLH Aviación facilities, in order to improve its ability to complete and maintain the leadership of the CLH Group in this activity.]]>5965http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5965Thu, 02 Feb 2012 00:00:00 +0100
<strong>Key highlights:</strong>

- Global economy and energy markets likely to see continued high volatility. Shell remains focused on through-cycle investment for sustainable growth.
- Delivery of underlying strategic drivers for 2012 targets established, underpinned by 14 project start-ups 2009-11, and Shell’s continuous improvement programmes.
- Shell declared ~$10.5 billion of dividends in 2011 and expects to grow the dividend in 2012, reflecting an improving financial position.
- Net capital investment in 2012 of $30 billion – 80% in Upstream - as Shell invests for a new tranche of growth.
- Measured increase in spending and payout underpinned by a new outlook for cashflow from operations for the period 2012-15 some 30-50% higher than the 2008-11 total.
- Growth outlook driven by over 60 new projects and options, maturing ~20 billion boe of new resources potential, including major projects in liquefied natural gas (LNG), deep water, tight gas, liquids-rich shales and traditional plays.

Economic development in non-OECD countries is driving sustained and long term demand growth for all forms of energy. Regulatory and political uncertainties, combined with challenges in debt markets, are adding to price and cost volatility in this long term trend. Shell is investing for sustainable growth through what is likely to remain a highly volatile period in the economy and energy markets. The company’s activities provide affordable, safe and reliable energy supplies for our customers, world-wide.

<strong>Delivering on targets to 2012</strong>

Shell’s three-year strategic plan, first outlined in early 2010, was designed to build the foundations for profitable growth for shareholders, by improving near-term competitive performance, and delivering growth to 2012. The main strategic drivers of this plan have now been achieved:

- Performance focus. A substantial corporate reorganization, launched in 2009, simplified the company, reduced costs, and created a platform for faster delivery of our strategy. In addition, we are driving the Downstream portfolio to improve returns and growth potential.
- Cashflow from operations excluding working capital movements was $43 billion in 2011 – reaching the headline target we had set for 2012 - rebalancing the company to surplus cashflow.
- Continuous improvement and capital efficiency are embedded in Shell. Disposals of $17 billion from 2009-11, and $15 billion of acquisitions are repositioning the company for new growth.
- Growth delivery. Shell has started up 14 new projects in 2009-11 – including the world class Pearl gas-to-liquids project in Qatar.
- Shell’s oil and gas resources base on stream has increased by 33%, or 3 billion boe, to 12 billion boe between 2009 and 2011. Maintaining a strong project flow, the company is maturing a further 20 billion boe of new resources for future growth.

Our headline proved Reserves Replacement Ratio for the year on an SEC basis is expected to be around 100%. Our Organic Reserves Replacement Ratio, which excludes the impact of oil price movements in the year, acquisitions and divestments, is expected to be around 120%.

Shell’s CEO Peter Voser commented: “Shell’s strategy is innovative and competitive. Our improving financial position creates an opportunity to increase both our dividends and investment levels. With ramp up now well in hand for near-term growth, I want to move our agenda forward today, with new targets for the company.”

“We are delivering our growth plans. Today’s update sets a new and sustainable growth agenda for the company. We declared over $10 billion of dividends in 2011 and we are expecting to return to dividend growth for 2012. This reflects our confidence that there is more to come from Shell. ”

<strong>Setting out new priorities</strong>

Voser commented: “We have worked hard to generate a strong pipeline of investment opportunities for Shell, and we put the emphasis firmly on a competitive financial performance. Shell’s investment programmes create cashflow growth, which in turn funds our dividends. All of this is supported by efficiency gains from our continuous improvement programmes, where the opportunity set runs to billions of dollars for Shell.”

- Net capital investment will be some $30 billion in 2012, with over ~80% Upstream, of which 60% will be in North America and Australia. We continue to mature further development opportunities, with Final Investment Decision on 17 new projects in 2010-11. In 2011, the company has built new positions including Iraq gas, Asia Pacific LNG, liquids-rich shales, and new exploration acreage in 10 countries. This portfolio growth supports our increased investment program and updated growth outlook.
- Our cashflow from operations for 2008-11 was $136 billion, excluding working capital movements. Cashflow from operations should be some 30-50% higher for 2012-15 (A) .
- Capital efficiency is a key part of Shell’s strategy. Divestments are expected to be $2-3 billion in 2012, with $17 billion of asset sales completed in 2009-11.
- In Upstream, the company expects some 250,000 boe/d of asset sales and licence expiries over the 2012-17 timeframe. Assuming these impacts play out, oil &amp; gas production should average some 4 million boe/d in 2017-18, an increase of some 25% from 2011 levels of 3.2 million boe/d.

(A) Outlook assumes $80-100 Brent, improved North America gas and Downstream environment from 2011, and excludes working capital movments.

<strong>Growth investment</strong>

The key investment themes that underpin this profitable growth include over 60 new projects and options, which should unlock oil &amp; gas resources potential of over 20 billion boe.

- Exploration. We continue to balance exploration drilling in established basins, with selective expansion into frontier acreage, and new plays such as liquids-rich shales. Our exploration spending increased by some 30% to $3.6 billion in 2011, excluding acreage purchases, and should increase a further 35% in 2012 to some $5 billion.
- Traditional developments in Shell’s heartlands will see $6 billion of 2012 investment. This includes extending the life of Shell’s mature heartland positions such as the UK North Sea and South East Asia. Around $3 billion of investment in this category will be in countries with large undeveloped resources positions - Nigeria, Kazakhstan and Iraq.
- Integrated gas. Shell has ~8 mtpa of LNG capacity under construction – all in Australia – an increase of ~40% over today’s position, with at least $5 billion of capital investment planned for 2012. In addition, Shell has some 15 mtpa of new LNG capacity under study.
- Deep water oil and gas spending in 2012 of some $4 billion, with 250,000 boe/d under construction, in 7 projects spanning the Gulf of Mexico, Brazil and Malaysia.
- Tight gas and liquids-rich shales. Shell continues to build a world-wide portfolio in these new plays, with 50,000 square kilometers in total, including an increase of 12,000 square kilometers in 2011 in liquids-rich plays. We allocate capital to these plays on a short term basis with a high degree of flexibility, driven by economics and affordability. Some $4 billion of world-wide development investment is planned for 2012, focusing on production from the lowest cost gas positions, and growing our liquids production. Production from liquids-rich shales has the potential to reach some 250,000 boe/d in 2017.
- In heavy oil world-wide, we are planning for $2 billion of 2012 spending, covering EOR, mining and upgrading activities. In Canada, Shell is investing in a series of debottlenecking projects in oil sands mining, which will add ~50,000 b/d by 2020. We expect to take final investment decision on a 1.1 mtpa carbon capture and storage project – Quest – in 2012.
- We continue to focus on operational excellence and selective growth in Downstream, with $6 billion investment planned for 2012. Commissioning is underway at the 325,000 b/d Port Arthur refinery expansion project, creating one of the largest refineries in the United States, at some 600,000 b/d. Shell is also looking at new manufacturing capacity options in North America, in Qatar and in China, as well as selective growth in marketing activities, and continued momentum in Brazil biofuels.]]>5966http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5966Thu, 02 Feb 2012 00:00:00 +0100
Installation of the Turret and Mooring system in the field is anticipated in mid 2015.

The Ichthys LNG Project's FPSO, a new build 335 meter-long vessel, will be moored in water depths of 250 metres and located in the Browse Basin off the north-west coast of Western Australia 820 kilometres south-west of Darwin.

Approximate dimensions of the Turret: diameter 20 meters; height 65 metres and weight 7,000 tons.

The Turret can accommodate up to 15 risers and will be designed for 40 years of operation without being disconnected.

The Ichthys LNG Project is a joint venture between INPEX (76%, the operator) and Total (24%). Gas from the Ichthys Field, in the Browse Basin approximately 200 kilometres offshore of Western Australia, will undergo preliminary processing offshore to remove water and extract condensate. The gas will then be exported to onshore processing facilities in Darwin via an 889 kilometre subsea pipeline. The Ichthys Project is expected to produce 8.4 million tonnes of LNG and 1.6 million tonnes of LPG per annum, along with approximately 80,000 barrels of condensate per day at peak.]]>5967http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5967Thu, 02 Feb 2012 00:00:00 +0100
EWC is an Australian company based in Hong Kong working to provide energy to Asian countries by developing standard modular LNG production trains and by investing in LNG receiving terminals and Gas fired power generation.

This LNG Hub Terminal will be used to facilitate the distribution of natural gas to three main markets:

- To serve as an anchor buyer of the LNG;

- To distribute the LNG to other power producers in the region;

- To distribute the LNG &amp; CNG for use as vehicle fuels.

For this project, GTT is in charge of the detailed design of the storage tank containment system and will provide technical assistance on site for the construction.

This is the second LNG storage tank ordered by EWC from GTT, illustrating the four year trusting relationship between the two companies.
]]>5968http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5968Thu, 02 Feb 2012 00:00:00 +0100
Domestic gas consumption grew as well. Among the gas consumption leaders were the following sectors: agrochemistry – 1.9 billion cubic meter growth (almost 9 per cent) to 22.8 billion cubic meters, and cement industry – 0.6 billion cubic meter growth (almost 8 per cent) to 8.3 billion cubic meters. Power generating companies increased their gas purchases by 4.8 billion cubic meters to 168.1 billion cubic meters, with a 3.4 billion cubic meter increase from Gazprom’s gas transmission system that gave a total of 154.1 billion cubic meters.

More gas was supplied beyond the FSU. In 2011 supplies reached 150 billion cubic meters and surpassed the same figure of 2010 (138.6 billion cubic meters) by 11.4 billion cubic meters (8.2 per cent).

Gas supplies within the FSU grew by 3.08 billion cubic meters and totaled 71.1 billion cubic meters.

By the 2011–2012 heating season startup Gazprom raised the productivity of its underground gas storage (UGS) facilities to record heights. The maximum daily deliverability stood at 647.7 million cubic meters of gas by the start of the withdrawal season. Between December and February gas consumers may receive an average daily amount of up to 522.1 million cubic meters of gas. The operating gas reserve in the amount of 65.2 billion cubic meters (1.2 billion cubic meters up as compared to the previous year) was formed. This is a record high amount over the entire history of the domestic gas industry.

According to preliminary data, in 2011 Gazprom Group produced 32.28 million tons of oil (0.27 million tons more versus 2010) and 12.07 million tons of condensate (0.78 million tons or 6.9 per cent more versus 2010).

The Company’s forecasts say that Gazprom Group’s financial results – proceeds from sales, currency receipts, EBITDA and net profit – will be record high in 2011 over the entire corporate history.

Gazprom Group’s proceeds from sales are forecast to rise by USD 32 billion (or by 27 per cent) to USD 150 billion (USD 118 billion in 2010). At the same time, the currency receipts will grow by some USD 28 billion (or by some 40 per cent) – from USD 70 billion in 2010 to about USD 98 billion in 2011. The EBITDA will surpass the 2010 amount (USD 45 billion) by almost USD 15 billion (or by approximately 33 per cent) and will rise to about USD 60 billion. The net profit will grow by almost USD 40 billion that is almost 25 per cent more as compared to the 2010 figure (USD 32 billion).]]>5969http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5969Thu, 02 Feb 2012 00:00:00 +0100
The contract scope includes the project management, engineering, procurement, fabrication and installation of a 6km 22” oil export pipeline and a 14km 6” gas export pipeline connected to the new production facilities and existing Clair Phase 1 export systems. The pipeline systems will allow product to be transported from Clair Ridge to Sullom Voe Terminal (SVT) via a dedicated gas export pipeline spur tied into the Clair Phase 1 pipeline, and the associated gas will again be tied into West of Shetland Pipeline System via the gas export pipeline.

The 22” oil export pipeline bundle will be fabricated at Subsea 7’s Wester site facility in Wick, Scotland and will be installed using the Controlled Depth Tow Method. The 6” gas export pipeline will be fabricated at Subsea 7’s Vigra spoolbase. The scope also includes tie-ins of integrated subsea towhead structures, field testing and pre-commissioning activities.

Engineering and project management will commence from our Aberdeen office in early 2012, with offshore operations due to commence in 2013.

Steph McNeill, Subsea 7's Vice President, UK said: “We are pleased to be awarded this major pipeline project by BP, which builds upon our unique bundle technology. Fabrication will take place at our Wick facility in Scotland, which has a proven track record of successful bundle design, fabrication and installation, securing work for approximately 100 people. We look forward to helping bring on-stream the Clair Ridge Project in an efficient, timely and safe manner."]]>5960http://www.euro-petrole.com/ne_02_actualite_f_details.php?idNews=5960Wed, 01 Feb 2012 00:00:00 +0100
Ce livret a été présenté le 1er février 2012, à l’occasion de la conférence de presse annuelle de son président, Jean-Louis Schilansky.

Dans les décennies à venir, la demande mondiale en énergie sera croissante, entraînée par le développement des nouvelles puissances économiques. Toutes les énergies devront être mobilisées pour répondre à cette croissance de la consommation. Au coté des autres énergies et des efforts d’efficacité énergétique et de maîtrise de la consommation, le pétrole jouera un rôle clé.

Si la France se révèle disposer de ressources en hydrocarbures sur son territoire en métropole ou outre-mer, l’UFIP recommande que le pays se donne tous les moyens de les mettre en valeur pour contribuer à réduire sa dépendance énergétique, pour améliorer sa balance commerciale et assurer des retombées économiques locales significatives.
L’industrie du raffinage a un rôle stratégique dans la chaîne de valeur pétrolière et contribue fortement à la sécurité d’approvisionnement de la France. Elle connaît une crise sans précédent en Europe et en France. Pour conserver un outil performant et compétitif, l’UFIP souligne que la France doit éviter à tout prix de pénaliser son industrie par rapport à ses concurrentes en Europe et dans le monde.

La logistique pétrolière, ports maritimes, dépôts et oléoducs, est un élément clé de la sécurité d’approvisionnement du pays. Elle a été soumise à rude épreuve durant la crise de l’automne 2010 et a montré alors sa capacité d’adaptation mais aussi des vulnérabilités. Pour l’UFIP, la mise en place d’un service minimum dans les grands ports maritimes renforcerait la fiabilité de la logistique pétrolière au bénéfice des consommateurs français.

La distribution de carburants en France est un secteur où la concurrence est très vive entre les réseaux pétroliers, les indépendants et la grande distribution. Le consommateur en bénéficie, mais elle a pour conséquence directe la disparition progressive des stations-service de proximité. Pour continuer d’assurer au consommateur, un service de proximité au meilleur prix, l’UFIP propose qu’une attention particulière soit portée au maintien d’un réseau de distribution diversifié.
Avec près de 200 000 emplois directs et indirects en France, l’industrie pétrolière contribue de manière importante à l’économie, à l’emploi du pays et au service des consommateurs.

A l’occasion de cette publication, Jean-Louis Schilansky a déclaré : « Il est crucial que notre pays dispose d’une industrie pétrolière dynamique qui assure la sécurité de son approvisionnement en pétrole, et apporte sa contribution à l’emploi et à l’économie de manière forte et durable. »

Le dossier de la conférence de presse du 1er février et le livret « L’industrie pétrolière en France - Contribution au débat sur l’énergie » sont téléchargeables sur le site www.ufip.fr ]]>5961http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5961Wed, 01 Feb 2012 00:00:00 +0100
BP has acknowledged its role in the accident and has paid more than $7.8 billion in claims, advances and other payments to individuals, businesses and governments, regardless of whether third parties ultimately would be responsible for any of that sum or additional liabilities. Our charges and provisions never assumed any recovery from Transocean or Halliburton for pollution-related damages. These two decisions should put an end to the attempts by Transocean and Halliburton to avoid their obligations.]]>5962http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5962Wed, 01 Feb 2012 00:00:00 +0100
The transaction closing is expected to take place during the second quarter of 2012.
ERG will continue to be represented on the Board of Directors of ISAB and on the management committees, while the Operating Processing Agreement has been temporary amended to be consistent with the new role of ERG in ISAB.
ERG and LUKOIL have also modified the agreements signed in 2008 (see Press Release dated 24 June 2008), with particular reference to ERG's lock-up period for the exercise of its put option on the remaining 20% stake in ISAB, which is extended until 1 October 2013.

A provision has also been included to the effect that, if ERG should exercise its put option on the remaining 20% stake between 1 and 31 October 2013, the parties undertake to finalise the transaction during the period between 15 and 31 December 2013. All other terms and conditions remain unchanged.

Alessandro Garrone, ERG's Chief Executive Officer, commented: “This transaction allows ERG to downsize its presence in the refining business against a background of continuing crisis and to further consolidate the Group's financial structure with a view to supporting its future development projects during a difficult financial period. ERG continues to maintain a significant industrial presence at the Priolo site, where it has important business relations with ISAB as regards its ERG Power and ISAB Energy thermoelectric plants.”

<a href="http://www.euro-petrole.com/raffinerie-de-priolo-gargallo-isab-nord-l-176" target="blank" class="lien">To see the Priolo Gargallo ISAB NORD refinery</a>

<a href="http://www.euro-petrole.com/raffinerie-de-priolo-gargallo-isab-sud-l-175" target="blank" class="lien">To see the Priolo Gargallo ISAB SUD refinery</a>]]>5963http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5963Wed, 01 Feb 2012 00:00:00 +0100
With advanced features such as wireless system status and data harvesting, UNITE offers UOS an unprecedented level of flexibility and quality control in the most challenging onshore environments, including urban areas. This purchase follows an extremely successful pilot operation with UNITE using an airplane to QC the spread.

The order for 6,000 UNITE channels as well as Sercel SG-10 geophone strings marks the first purchase of geophysical equipment by UOS since it joined the industry. UOS have also purchased five Sercel NOMAD 65 vibrators equipped with VE464 controllers and plan to deploy their first vibrator fleet in February 2012.

Stanis&amp;#322;aw Zo&amp;#324;, Country Manager, United Oilfield Services, said: “We chose UNITE because it is the most advanced system capable of combining its ease-of-use when operating in autonomous mode with the advanced features of remote data harvesting. We are confident that this system will aid us in our quest to become the market-leading oilfield service company in Poland.”

Pascal Rouiller, CEO, Sercel, said: “We are delighted that Sercel’s state-of-the-art equipment has been selected by United Oilfield Services to equip its first seismic crew. UNITE’s flexibility of layout, improved quality control and operational follow-up capabilities will ensure UOS achieves seismic survey success even in city centers.”

About Sercel

Sercel is the world’s leading designer and manufacturer of innovative seismic equipment and reservoir monitoring instruments. Sercel provides oil field service companies and geophysical contractors the widest range of leading-edge technologies for exploration in land, marine, ocean bottom, transition zone and reservoir environments. Employing more than 2000 people worldwide, main Sercel sales offices are located in Houston (USA) and Nantes (France). More information about Sercel is available at www.sercel.com. ]]>5956http://www.euro-petrole.com/ne_02_actualite_f_details.php?idNews=5956Tue, 31 Jan 2012 00:00:00 +0100
" La signature de ce contrat concrétise la pérennité d'une longue relation entre Shell et ORTEC. L'augmentation de la demande mondiale d'énergie accélère le rythme des changements dans le secteur du pétrole et du gaz. Prendre les bonnes décisions de manière rapide et précise devient essentiel pour conserver une position dominante dans cette industrie. Nous sommes extrêmement fiers de soutenir Shell dans ce processus grâce à nos prestations de conseils s'appuyant sur notre approche " fact-based consulting " et la modélisation ", affirme Lambert van der Bruggen, PDG d'ORTEC Consulting Group.

Paulus Steenkamp, Vice-président de la fabrication, de la production et de l'ingénierie logicielle chez Shell Global Solutions International B.V., ajoute : " Shell s'efforce d'œuvrer pour une énergie responsable et durable et ORTEC, via le développement de ses logiciels de haute qualité et ses prestations de conseils, nous aide à réaliser les objectifs stratégiques de Shell visant à fournir des solutions technologiques de pointe. Cet accord garantit la poursuite de notre relation sur le long terme. "


A propos d'ORTEC
ORTEC est l'un des principaux fournisseurs de solutions logicielles avancées et de services de conseil pour la planification et l'optimisation. Les solutions ORTEC permettent d'optimiser les tournées et le transport, le chargement des véhicules et des palettes, la planification des équipes, et les réseaux logistiques. ORTEC propose des solutions de premier ordre, personnalisées et intégrables dans SAP®, qui s'appuient sur des partenariats stratégiques. Dans le domaine de la planification avancée, ORTEC compte plus de 1550 clients à travers le monde, plus de 550 employés et plusieurs bureaux en Europe, en Amérique du Nord, en Asie et dans la Région Pacifique.

A propos d'ORTEC Consulting Group
ORTEC Consulting Group, membre du groupe ORTEC, aide les sociétés à prendre des décisions éclairées et fondées sur les faits, en s'appuyant sur des analyses approfondies. Ces conseils permettent aux sociétés de prendre des décisions en toute confiance lors de l'optimisation des processus de l'entreprise. En analysant les données historiques et les prévisions, les conseillers experts d'ORTEC Consulting Group peuvent calculer des scénarios qui fournissent une vision claire des faits et des chiffres. Ces informations sont essentielles pour prendre des décisions équilibrées et optimiser les processus de l'entreprise. Pour en savoir plus, consulter le site http://www.ortec-consulting.com.

À propos de Royal Dutch Shell plc
Royal Dutch Shell plc est enregistrée en Angleterre et au Pays de Galle. Son siège social se trouve à La Haye et elle est cotée aux bourses de Londres, Amsterdam et New York. Les sociétés Shell exploitent dans plus de 100 pays et territoires des activités portant sur l'exploration et la production de pétrole et de gaz, la production et la commercialisation de gaz naturel liquéfié et de carburants GTL (transformation du gaz en liquide), la fabrication, la commercialisation et l'expédition de produits pétroliers et chimiques et les projets d'énergies renouvelables. Pour tout complément d'information, rendez-vous à l'adresse : http://www.shell.com

Les sociétés dans lesquelles Royal Dutch Shell plc détient directement et indirectement des investissements sont des entités séparées. Dans le présent communiqué, les termes et expressions " Shell ", " groupe Shell " et " Royal Dutch Shell " sont parfois utilisés par commodité pour faire référence à Royal Dutch Shell plc et à ses filiales en général. De même, les termes " nous ", " notre " et " nos " sont également employés lorsqu'il est question de filiales en général ou des personnes travaillant pour ces filiales. Ces termes et expressions sont aussi utilisés lorsqu'il n'y a pas lieu de désigner une ou plusieurs sociétés en particulier.]]>5957http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5957Tue, 31 Jan 2012 00:00:00 +0100
The Foster Wheeler contract value was not disclosed and will be included in the company’s fourth-quarter 2011 bookings.

ARMO intends to modernize the existing refineries at Ballsh and Fier to restore production to the original design capacity and produce transportation fuels in line with current European Union regulations. The study is expected to be completed by mid-2012.

ARMO, a former state-owned company privatized since 2008, owns these two refineries which serve both the domestic and the Balkans’ regional markets.

<a href="http://www.euro-petrole.com/raffinerie-de-ballshi-l-237" target="blank" class="lien">To see the Ballsh refinery site</a>
<a href="http://www.euro-petrole.com/raffinerie-de-fieri-l-238" target="blank" class="lien">To see the Fier refinery site</a>]]>5958http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5958Tue, 31 Jan 2012 00:00:00 +0100
Wärtsilä's acquisition of the British-headquartered, global engineering company Hamworthy plc has today become effective. This acquisition is a major step in Wärtsilä's strategy to strengthen its position as a total solutions provider, and to be the most valued partner for its customers with a complete range of products, integrated solutions, and services to the marine and offshore industries.

Wärtsilä announced the recommended cash offer for Hamworthy in November last year.Wärtsilä already has an exceptionally broad offering that covers the complete lifecycle of a vessel, from initial ship design to daily operating requirements, and which is backed by the most extensive global service network in the industry.

Hamworthy's portfolio of high technology products and systems represents a valuable complementary addition to this range. With the marine and offshore industries undergoing challenging times as a result of economic and environmental restrictions, the combining of the two companies' strengths will speed up and ease the means for customers to reduce operating costs and achieve compliance with environmental legislation. It also further facilitates 'one-stop' procurement procedures for shipyards to reduce risks arising from having multiple suppliers.

"This move is fully in line with our strategy," says Jaakko Eskola, Group Vice President, Wärtsilä Ship Power. "Both companies are excited by the challenges and opportunities in the rapidly evolving offshore, marine gas applications, as well as environmental solutions markets. We have the broadest range of solutions and services in the industry, and by adding Hamworthy's strengths to our own, we can serve our customers even better.""We are delighted to be joining Wärtsilä, an acknowledged leader in providing technologically advanced solutions for customers around the world.

The Hamworthy strengths will be gradually and systematically integrated with those of Wärtsilä, with the end result that the customer's route to greater profitability and easier compliance will be shortened," says Joe Oatley, CEO, Hamworthy Hamworthy has been highly successful in providing a wide assortment of specialist equipment and systems to the shipping industry, and systems that improve process efficiency and environmental compliance in the oil &amp; gas industry.

The joining of these two industry leaders will thus create an exciting platform for long-term growth. In particular, the ability to address and prepare for future legislation and operating requirements will be enhanced, to the benefit of customers and stakeholders around the world. Hamworthy employs approximately 1000 people worldwide, and has offices in Europe, the USA, Asia, the Middle East and India. Wärtsilä currently employs some 18,000 people working from 170 locations in 70 different countries.]]>5959http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5959Tue, 31 Jan 2012 00:00:00 +0100
Domestically, the gas production capacity in 2012 will remain at a level similar to that recorded in 2011, but there will be more options regarding potential uses of developed reserves, which will become available from July 2012, once extension of the Ko&amp;#347;cian node has been completed and the Ko&amp;#347;cian-Szczyglice gas pipeline has been placed in service. The expanded infrastructure will make it possible to sell additional volumes of gas, both to direct customers, and to the distribution system.

PGNiG SA also intends to double its crude oil production to 1.24 million tonnes in 2013, compared with 660 thousand tonnes in 2012.

Production in Poland will increase to 750 thousand tonnes in 2013, from 480 thousand tonnes in 2012, while abroad (in Norway) it will increase in 2013 to 490 thousand tonnes, from 180 thousand tonnes in 2012.

The change in the domestic oil production forecast for 2012 relative to previously published forecasts (500 thousand tonnes) has come as a consequence of adoption of revised data concerning production rates as well as geological and reservoir characteristics of the Company's assets.

The forecast regarding oil and gas production from the Norwegian Continental Shelf in 2012 remains unchanged.]]>5950http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5950Mon, 30 Jan 2012 00:00:00 +0100
The corporation anticipates the restructuring will be seamless for ExxonMobil Japan Group customers, dealers and business partners and expects existing agreements to remain unchanged. Current management will remain in place until closing, which will occur in mid-2012.

At closing, ExxonMobil will remain TonenGeneral Sekiyu’s largest shareholder and anticipates continued participation on its Board of Directors, subject to shareholder approval of its nominees. TonenGeneral Sekiyu will have exclusive, long-term use of ExxonMobil’s existing brands for the sale of ExxonMobil products in Japan. ExxonMobil will provide ongoing technology support, including technical assistance from ExxonMobil Research and Engineering. ExxonMobil will also provide international crude, feedstock and fuels supply services, including international marine coverage services.
Beyond its retained shareholding in TonenGeneral Sekiyu, ExxonMobil will maintain its presence in Japan through businesses and partnerships excluded from the restructuring, including:
- ExxonMobil’s butyl, specialty elastomers, polyolefin, synthetics and catalyst businesses, including its ownership in Japan Butyl Company;
- International Marine lubricants;
- LNG marketing and sales, including LNG market development activities; and
- Collaborations and partnerships with Japanese companies in the upstream sector.

ExxonMobil has conducted business in Japan for more than a century. To strengthen its competitive position in the Japanese market, the company has continuously innovated and adapted its business model to meet the needs of Japanese society and its changing business environment.]]>5951http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5951Mon, 30 Jan 2012 00:00:00 +0100
The adjustment corresponds to an increase of 125 million barrels of oil equivalents in relation to the resource estimate that was prepared in the plan for development and operation (PDO), and is equal to about half of a Luva or Skrugard discovery.

“I think it is very encouraging that, through work on the field, we can increase the resource estimate for Snøhvit. The increase is important for the potential development of our activity in the Barents Sea,” says Øivind Nilsen, production vice president for Hammerfest LNG.

“We will continue the work with reserve development and hope that we can further increase the recoverable reserves in the field through measures for improved recovery (IOR) in the future.”

When the PDO was submitted, the recoverable resources were estimated at 190 billion cubic metres of natural gas and 18 million cubic metres of condensate.

The Snøhvit owners have started assessing whether and potentially how the total gas export from the Barents Sea can be increased. Such expansion will either take place through increased LNG production capacity or through an export pipeline.

A decision regarding the concept for such an increase is planned for the second quarter of 2012. An investment decision for potential LNG capacity expansion is thus expected in 2013.

The fields that deliver gas to Melkøya are Snøhvit and Albatross, and the Askeladd field will also be developed for gas production. The first gas discovery here was made in 1981. The fields have been operational since August 2007 and produce about 13,000 tonnes of LNG daily from nine wells.

The partners in Snøhvit are Statoil (operator - 36.79%), Petoro (30%), Total E&amp;P Norge (18.40%), GDF SUEZ E&amp;P Norge (12%), and RWE Dea Norge (2.81%).

Snøhvit is the first gas development in the Barents Sea. With no installations on the sea surface, large volumes of natural gas are transported onshore and cooled at Hammerfest LNG on Melkøya, the world’s northernmost and Europe’s first LNG export facility.]]>5952http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5952Mon, 30 Jan 2012 00:00:00 +0100
The fields, which are located across both the Norwegian and UK sectors of the Northern North Sea, produce gas for the UK market. The acquisition further strengthens Centrica’s integrated business model and provides another secure source of gas for our UK customers.

The deal will see Centrica acquire a further 15.17% interest in the field which, combined with its existing equity interest, will increase its overall stake in this core asset to 34.30%. It will also see the company increase its interest in the Statfjord satellites (Statfjord Nord, Statfjord Øst and Sygna), all of which are producing fields tied back to Statfjord. The gas produced from these fields is either uncontracted or already contracted to Centrica and is directly linked to the UK market.

The acquisition adds material long-term production to Centrica’s portfolio, providing additional reserves of 36 million barrels of oil equivalent (mmboe), an increase of about 9% split approximately 60% liquids and 40% gas. The resulting net increase in production will be over 11,000 boe per day, with production weighted towards liquids in the early years. Field development costs of approximately £200 million relating to the acquired interests will be required to maximise the long-term recoverable reserves from these fields and the acquisition is expected to generate strong immediate earnings and cashflow.

Mark Hanafin, Managing Director of Centrica Energy, said:

“Increasing our stake in Statfjord marks the latest stage in our drive to secure high quality sources of gas for our customers, adding both earnings and long-term value to Centrica. The acquisition, which follows our announcement last year of a new 10 year gas supply deal with Norway and acquisition of assets from Statoil, underlines our commitment to invest in North Sea production and secure future energy supplies for the UK.”]]>5953http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5953Mon, 30 Jan 2012 00:00:00 +0100
The Ichthys LNG Project is a joint venture between INPEX (76 percent, the operator) and Total (24 percent). Gas from the Ichthys Field, in the Browse Basin approximately 200 km offshore of Western Australia, will undergo preliminary processing offshore to remove water and extract condensate. The gas will then be exported to onshore processing facilities in Darwin via an 889-km subsea pipeline. The Ichthys LNG Project is expected to produce 8.4 million tons of LNG and 1.6 million tons of LPG per annum, along with approximately 100,000 barrels of condensate per day at peak.

GE will provide rotating equipment, including gas turbines and compressors, for a new Ichthys LNG plant at Blaydin Point, near Darwin in Australia’s Northern Territory, and associated floating production storage and offloading and a central processing facility (CPF) located in the Browse Basin offshore Western Australia. In addition, GE will supply subsea production systems for the offshore portion of the project as well as subsea connectors for an 889-kilometer (km) pipeline that will carry the gas produced from a CPF to the new LNG plant in Darwin. GE announced the award of the contract at the 2012 GE Oil &amp; Gas Annual Meeting being held Jan. 30-31 in Florence, Italy.

The scope of GE’s supply includes four Frame 7EA Gas Turbines and eight MR/PR Compressors for the LNG plant; 10 PGT25+G4 gas turbines and 10 compressors for upstream facilities; and 22 subsea production trees, five off-subsea manifolds, an integrated subsea control system and a 42-inch trunk line connection system. The equipment will be shipped by 2014 and INPEX expects to start producing LNG by the end of 2016.

“We have been able to confirm our strong heritage in the LNG sector, leveraging our gas turbine, compressor and subsea production technologies for many of the world’s leading LNG projects, including the Ichthys subsea development,” said Dan Heintzelman, CEO of GE Oil &amp; Gas. “Our growing commitment to the LNG industry in Australia was another key factor in winning this significant award.”

Among GE’s recent investments in Australia is the recently opened Jandakot facility in Perth, a $100 million state-of-the-art technology and learning center that will support the training of the next generation of skilled workers in the oil and gas, energy, mining, transportation and water industries. In addition, GE Oil &amp; Gas has established a strong position in Australia’s LNG sector, providing equipment for most of the country’s LNG projects including Gorgon, Wheatstone, Prelude FLNG and Queensland CSM LNG projects. According to the Australian government’s Department of Resources, Energy &amp; Tourism, the Australian LNG industry has the potential to attract up to A$60 billion in new project investment over the next 10 years.]]>5954http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5954Mon, 30 Jan 2012 00:00:00 +0100
Among the new projects announced:

- Under contracts totaling nearly $1 billion, GE will supply a wide range of equipment and services for the Ichthys LNG project in Western Australia, being developed by INPEX Corporation and Total.
- GE subsea production equipment, control systems and services have been selected for the Nexen Golden Eagle Area Development project in the United Kingdom’s central North Sea.
- GE Oil &amp; Gas will supply associated gas utilization technology for TNK-BP’s Verkhnechonsk oil and gas field in Eastern Siberia. The project calls for gas re-injection into an underground storage area for further reuse, rather than flaring, or wasting, that gas.
- GE has been selected to provide key equipment for a floating oil production, storage and offloading platform being built to develop the Guará Norte section of the Tupi oilfield in Brazil’s Santos oil basin.

Additional announcements included:

- GE has launched a Micro LNG plant that meets the smaller-scale LNG requirements of powering remote industrial and residential locations and fueling motor vehicles.
- GE has signed a global frame agreement with Shell Global Solutions to supply compressors and associated services for Shell’s projects worldwide over the next six years.
- GE has recently completed the first cycle of gas turbines modular replacement project at the Qatargas LNG plant in Ras Laffan Industrial City.
- GE has successfully completed tests on the first of three LNG compressor trains being supplied for the development of Gorgon, one of the world’s largest untapped natural gas fields, off the coast of Australia.
- PII Pipeline Solutions introduces PVI Lite Modules as a new member of the PipeView™ Integrity Software Line

“After more than a decade, the GE Oil &amp; Gas Annual Meeting has become an industry tradition. It provides an opportunity to see how far technology has advanced in the past 12 months and to discuss where it can go in the future,” said Dan Heintzelman, CEO of GE Oil &amp; Gas. This year’s meeting theme, Leading Progress Together, reflects GE’s recognition that tackling the complex challenges facing the oil and gas industry requires leadership and increased teamwork. The meeting will focus on the collaborative effort that goes into every step forward. With an outstanding roster of speakers, panelists and technical presenters, this promises to be an exciting and thought-provoking event.”

During the annual meeting, panel discussions will cover such topics as working together to develop solutions for unconventional energy production, the value of partnerships, and the future of the global energy industry. In addition, global experts from across the oil and gas industry will lead technology forums that will address a wide range of topics including subsea exploration and production, enhanced oil recovery, LNG production, pipeline inspection techniques and technical advances in gas turbines and compressors.

“The competitive and environmental challenges of today’s oil and gas industry are driving the need for increased efficiency, reliability and environmental protection. How technology innovation can help our customers achieve those objectives will be a common theme winding through all of the presentations,” noted Heintzelman.

Along with the technology and general discussion sessions, the annual meeting also offers customers the choice of touring one of two GE facilities: the Florence plant, where compressors, steam and gas turbines and turboexpanders are manufactured and tested; and the Massa plant, which houses heavy wall reactors, large compressor machining and assembly, turbocompressor packaging and full load string testing.

In addition to GE, representatives from many of the world’s leading oil and gas companies will participate in the two-day event. Last year’s meeting drew 850 representatives from more than 70 countries and 200 companies, including leading experts and key decision makers across the industry.]]>5955http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5955Mon, 30 Jan 2012 00:00:00 +0100
The Luva field, which is a deep-water pioneer in the Norwegian Sea, may be the first to have a Spar platform on the Norwegian continental shelf (NCS). The field is located outside of existing infrastructure and has a water depth of 1300 metres.

"This development may represent the start of deep-water production in the Norwegian Sea, and it will enable the tie-in of other discoveries in the same area", says Ivar Aasheim, senior vice president for NCS field development in Statoil.

<strong>Luva concept</strong>

The Luva field is planned for development with a Spar platform, which consists of a large-diameter, single vertical cylinder supporting a conventional deck with processing facility, accommodation quarters, etc. The installation is fixed to the seabed.

The choice of concept is in line with the study presented in March 2011. It will be the first Spar on the NCS, and one of the largest of its kind worldwide.

The concept includes two subsea templates with four wells on each and one satellite template with one well.

The platform will house accommodation quarters for a permanent crew, a storage unit for condensate and a gas processing facility with a capacity of 23 million standard cubic metres per day.

<strong>NSGI concept</strong>

Meanwhile, the Norwegian Sea Gas Infrastructure (NSGI) project has chosen a gas transport concept that includes a 480km long, 30-36 inch pipeline from the Luva field to the onshore processing facility at Nyhamna.

The pipeline will also be connected ion to the Linnorm field and tied-in to the Zidane field. In addition, connection to Åsgard Transport via the Kristin platform will be possible and there are plans for tying in other fields and discoveries.

The concept includes the expansion of the Ormen Lange field's Nyhamna gas plant with the intention of converting it into a gas terminal.

"NSGI would not only provide gas export solutions for Luva, Linnorm and Zidane, it would contribute in opening up a new gas region on the NCS, making it possible to develop existing and potential future discoveries in the area," says Statoil's project director Håkon Ivarjord..

"NSGI will also take care of gas exports from the Haltenbanken area that exceed the available capacity in Åsgard Transport, thus improving the resource management of the existing fields there. In this respect NSGI may play an important role in securing the NCS's position as a long-term, reliable gas province."

<strong>Industrial development</strong>

The substantial investments being made on Luva will drive the development of deep-water production in the Norwegian Sea. The biggest and most long-term spin-off effects will arise during the operational phase, even given the magnitude of the investments during the construction period.

Collaboration with Petro Arctic has been established, as Luva will have a considerable impact on industrial development in the north of Norway.

<strong>Facts about Luva</strong>

- Gas discovery at water depth of 1300 metres in the Vøring area, 300km offshore.
- Expected recoverable volume is 40 – 60 billion standard cubic metres of gas
- Lean gas with low carbon content
- 140km to the nearest installation (Norne) and 480km to the Nyhamna gas plant
- The discovery made in 1997, Statoil has been operator since 2006
- Expected to come on stream in 2016
- Partners are Statoil (75%), ExxonMobil (15%) and ConocoPhillips (10%)

<strong>Facts about NSGI</strong>

- Statoil has assumed the responsibility for the NSGI development from Gassco and has been assigned operator for the construction phase, while Shell has been assigned responsibility for the modifications at Nyhamna.
- Gassco is responsible for the commercial process between the NSGI partners and other infrastructure facility owners as well as for all pre-operational activities.
- Gassco will take over as operator when NSGI is incorporated into Gassled at start-up, which is expected to take place during 2016.
- The NSGI partners are Centrica, ConocoPhillips, Edison, E.ON Ruhrgas, ExxonMobil, GDF SUEZ, Maersk, OMW, Petoro, RWE Dea, Shell, Statoil and TOTAL.]]>5940http://www.euro-petrole.com/ne_02_actualite_f_details.php?idNews=5940Fri, 27 Jan 2012 00:00:00 +0100
Sur l’ensemble de l’année 2011, la consommation française de carburants a été stable (+0,08 %) par rapport à l’année 2010. Durant cette période, la consommation de supercarburants a baissé de 5 % tandis que celle de gazole a augmenté de 1,5 %.
]]>5941http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5941Fri, 27 Jan 2012 00:00:00 +0100
In October 2011, BG Group announced it had signed a fully-termed sale and purchase agreement (SPA) with Sabine Liquefaction for the purchase of 3.5 mtpa of LNG over a 20-year period. The additional volumes associated with today’s announcement have been incorporated into the SPA.

BG Group Chief Executive Sir Frank Chapman said: “The purchase of additional volumes from the Sabine Pass facility builds on the ground-breaking agreement we entered into last year, in which BG Group secured LNG export volumes from the US Gulf Coast.

“The agreement adds further volume to our diversified global LNG supply portfolio and is underpinned by the recent material increases in US gas reserves as well as a favourable long-term outlook for global LNG demand.”

Construction of the liquefaction facilities at Sabine Pass is scheduled to begin in 2012, with an initial phase of two LNG trains. Construction of the second phase, an additional two trains, is expected to commence in 2013, with exports from the initial phase to start as early as 2015 and for the second phase from as early as 2017.

At the same time, BG Group is pursuing an expansion of the Lake Charles LNG terminal, in Louisiana, USA, to provide natural gas liquefaction services. The US Department of Energy (DoE) has authorised the terminal to export up to 730 Bcf of natural gas per year (approximately 15 mtpa) to countries that have a free trade agreement in place with the USA.

The DOE is reviewing an application to export natural gas from the Lake Charles LNG terminal to countries that do not have a free trade agreement with the USA.

<a href="xxxxxx" target="blank" class="lien">To see the Sabine Pass LNG Terminal site</a>]]>5942http://www.euro-petrole.com/ne_02_actualite_f_details.php?idNews=5942Fri, 27 Jan 2012 00:00:00 +0100
Un projet d’investissement majeur, d’un montant global d’environ 1,8 milliard de dollars, va permettre à la plateforme pétrochimique de Daesan d’être dotée d’une deuxième unité aromatique (1) et d’une unité EVA (Ethylene-vinyl acetate copolymer) (2).

La nouvelle unité aromatique, dont la construction sera achevée d’ici à septembre 2014, aura une capacité annuelle de production d’environ un million de tonnes de paraxylène et de 420 000 tonnes de benzène. Le paraxylène sert à la fabrication du polyester tandis que le benzène est en particulier utilisé pour produire du styrène (3).

D’ici à 2014, la capacité annuelle de production de paraxylène du site sera ainsi portée à 1,76 million de tonnes grâce à la nouvelle unité aromatique et à la modernisation en 2012 de l’unité de paraxylène existante.

La nouvelle unité EVA permettra quant à elle de produire chaque année 240 000 tonnes de copolymères d’éthylène et d’acétate de vinyle. De la famille des résines, ceux-ci sont utilisés dans les câbles électriques, les adhésifs ou encore les panneaux solaires. Etant donné leurs qualités environnementales et la variété d’usages auxquels ils se prêtent, ils devraient continuer de bénéficier d’une demande particulièrement soutenue.

Comme le souligne Patrick Pouyanné, directeur général de la branche Raffinage Chimie de Total, « à travers cette opération d’investissement en partenariat avec Samsung, qui s’inscrit dans la stratégie de développement du Groupe sur les marchés en croissance, nous nous donnons résolument les moyens de nous maintenir au rang des grands fournisseurs de produits à valeur ajoutée pour satisfaire la demande asiatique, notamment chinoise, en concentrant en priorité nos investissements sur les plateformes intégrées les plus performantes comme l’est celle de Daesan. »

La plateforme pétrochimique de Daesan représente un outil de production de taille mondiale qui fabrique principalement quatre produits &amp;#8722; polypropylène, polyéthylène, styrène monomère et paraxylène &amp;#8722;, dont 50 % sont destinés à l’export, essentiellement vers la Chine.

<strong>Samsung Total Petrochemicals</strong>
Constituée en 2003, Samsung Total Petrochemicals est une JV à parts égales qui associe les activités pétrochimiques de Total et celles de Samsung. Elle combine l’expertise technologique et les capacités industrielles de Total à l’excellence opérationnelle de Samsung et son accès au marché local. Elle fournit une large gamme de produits, des grands intermédiaires de la chimie de base aux polymères utilisés dans la vie quotidienne.

<strong>Total en Corée du Sud</strong>
Outre Samsung Total Petrochemicals, Total est présent en Corée du Sud dans les secteurs des lubrifiants, du GNL et des énergies nouvelles, des adhésifs (Bostik), des équipements antivibratoires (Hutchinson) ou encore de la métallisation (Atotech).

(1) Unité de production de benzène et de paraxylène, produits de chimie de base dérivés du pétrole qui entrent dans la fabrication des polymères dont sont issues les matières plastiques.
(2) Unité de production de copolymères d’éthylène et d’acétate de vinyle.
(3) Le styrène est l’un des grands intermédiaires de la chimie de base. Il intervient dans la production de très nombreux plastiques.]]>5943http://www.euro-petrole.com/ne_02_actualite_f_details.php?idNews=5943Fri, 27 Jan 2012 00:00:00 +0100
Les clients américains et européens ont bénéficié de l’introduction de Mobil SHC Pegasus pour une gamme de moteurs développés par les plus grands constructeurs (OEM) : notamment Jenbacher, Caterpillar et Waukesha. En France, Dalkia, leader européen des services auprès des collectivités locales et des entreprises dans le secteur de l’énergie, a mesuré le niveau de performances de Mobil SHC Pegasus 30, en termes de gain d’efficacité de production électrique obtenu, sur un moteur Caterpillar G3516. Les mesures ont mis en évidence un gain de l’ordre de 1,5 % avec Mobil SHC Pegasus 30 sur une période de deux mois, comparé à une huile standard pour moteurs fonctionnant au gaz naturel.

“Depuis le lancement de Mobil SHC Pegasus, les équipes de Mobil Lubrifiants Industriels travaillent en étroite collaboration avec leurs clients ainsi qu’avec les principaux constructeurs européens et américains dans le but d’évaluer sur le terrain le niveau de performances de Mobil SHC Pegasus,” nous confie Kathleen Tellier, qui travaille dans l’organisation « Products Research and Technology, ExxonMobil Research and Engineering », une division d’ExxonMobil Corporation. “Les résultats à ce jour sont exceptionnels et nous procédons actuellement à des essais complémentaires, en laboratoire et sur le terrain, dans le but de mettre à jour de nouveaux atouts économiques tels qu’une extension de la durée de vie des filtres. Cela permettrait aux exploitants d’augmenter les périodicités d’entretien et de franchir ainsi un palier supplémentaire dans l’exploitation des moteurs.”

Enogex, l’une des plus importantes compagnies de transport de gaz naturel, ainsi que des sociétés de service américaines, ont étudié la possibilité d’augmenter les périodicités de vidange en se basant sur la durée de vie de Mobil SHC Pegasus. Ainsi, Enogex a démonté un moteur Caterpillar G3516 après l’avoir fait tourner pendant plus de 16 000 heures sans vidange avec Mobil SHC Pegasus 30. Les différents composants (pistons, chemises, paliers,…) ont été trouvés en excellent état de propreté, ainsi qu’avec un niveau d’usure très faible. Une amélioration d’efficacité de l’ordre de 1,5 % a aussi été mise en évidence.
Ces résultats montrent que l’huile Mobil SHC Pegasus permet d’augmenter les intervalles de vidange de quatre à huit fois comparées aux huiles standard pour moteurs à gaz, et permet des économies de carburant de l’ordre de 1,5 %*.

D’autres clients en Allemagne, aux Pays-Bas et aux Etats-Unis ont aussi remarqué qu’utiliser Mobil SHC Pegasus permettait d’augmenter le rendement énergétique et d’accroître les périodicités de vidange sur des moteurs Jenbacher J412 et Waukesha P9390GL. Ces avantages, en plus des économies réalisées sur le traitement des huiles usées et sur l’augmentation de la durée de vie des organes lubrifiés, permettent aussi de contribuer à améliorer durablement la compétitivité des entreprises exploitant des moteurs qui fonctionnent au gaz naturel.]]>5944http://www.euro-petrole.com/ne_02_actualite_f_details.php?idNews=5944Fri, 27 Jan 2012 00:00:00 +0100
Les actions non détenues par Technip à l'issue de l'offre ne représentent pas plus de 5 % du capital ou des droits de vote de Cybernétix. Ainsi, comme annoncé précédemment, Technip sollicitera auprès de l'AMF la mise en œuvre d'un retrait obligatoire des actions résiduelles dans les dix jours de négociation à compter de la publication de l'avis de résultat de l'offre, pour un prix correspondant au prix de l'offre publique d'achat, soit 19 euros par action Cybernétix.

Le calendrier et la procédure du retrait obligatoire seront publiés par l'AMF et NYSE Euronext. A la suite de la réalisation du retrait obligatoire, les actions Cybernétix seront radiées d'Euronext Paris.

Thierry Pilenko, Président-Directeur Général de Technip, a déclaré : « je me réjouis du succès de cette opération qui va désormais nous permettre d’intégrer définitivement les équipes de Cybernétix. L'expertise technologique et le savoir-faire que cette compagnie a su développer depuis de nombreuses années, en particulier dans la conception, la fabrication et le déploiement de systèmes robotisés en milieu hostile, sont autant d'atouts pour Technip à l'heure de défier les nouvelles frontière de l'énergie. »]]>5945http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5945Fri, 27 Jan 2012 00:00:00 +0100
Petroplus also announced that its subsidiaries in Switzerland, Petroplus Tankstorage AG and Petroplus Refining Cressier S.A., which owns the Cressier refinery, have filed for composition proceedings (“Nachlassstundung”).

Petroplus further announced that its subsidiary in Belgium, the Belgian Refining Corporation N.V., which owns the Antwerp refinery, has filed for judicial reorganization proceedings (“gerechtelijke reorganisatie”).]]>5946http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5946Fri, 27 Jan 2012 00:00:00 +0100
The two licenses awarded to RWE Dea as operator, each with a 40% share are situated next to the company’s operated license PL330 in the northern part of the Norwegian Sea. These awards are valuable additions and fit well with RWE Dea’s plan to build a strong portfolio in this area. The two new licenses increase the company’s number of operated licenses from four to six.

The five licenses awarded as partner are valuable contributions to building a stronger presence in areas where RWE Dea is already actively exploring.

Managing Director of RWE Dea Norge, Hans-Joachim Polk says: “RWE Dea is pleased to have been offered seven new licenses, which we see as a vote of confidence from the Norwegian Government. They will strengthen our existing strong and long-time presence on the Norwegian shelf, and signal our commitment to continue to make a valuable contribution in the years to come.”

APA 2011 is the most extensive licensing round to date on the Norwegian Continental Shelf, in terms of the number of licenses awarded and the number of companies applying. According to the Norwegian Minister for Petroleum and Energy Ola Borten Moe, the Government extended this year’s round by 23,500 km2 in 2011.

Of the seven licenses awarded to RWE Dea, three are situated in the North Sea, three in the Norwegian Sea and one in the Barents Sea.]]>5947http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5947Fri, 27 Jan 2012 00:00:00 +0100
The Luno field is an oil field located in the Norwegian sector of the North Sea which incorporates both the Luno and Tellus discoveries. First production from the Luno field in PL338 is expected in late 2015 with a forecast gross peak production of approximately 90,000 barrels of oil per day (bopd).

Lundin (operator) has a 50 percent working interest in the Luno field. Wintershall and RWE Dea hold a 30 percent and a 20 percent interest, respectively.

The Luno PDO comprises 15 wells drilled from a jack-up rig, a processing platform on a jacket structure and export pipelines tied back to existing infrastructure. Luno contains 186 million barrels of oil equivalents (MMboe) of gross proved and probable reserves. The oil will be processed and transported through a new pipeline to the Grane area and further via the Grane oil pipeline to the Sture terminal for sale. The facilities on the Luno platform will be prepared for power from shore when capacity and technical solutions are available in order to contribute to the development of a long term electrification of the area.

Lundin has awarded the jacket construction to Kværner Verdal shortly after the submittal of the PDO. “We are pleased that Luno – one of the most important recent oil discoveries on the Norwegian Continental shelf – goes further ahead”, says Hans-Joachim Polk, Managing Director of RWE Dea Norge.
]]>5949http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5949Fri, 27 Jan 2012 00:00:00 +0100
Dr. Auli stated in a Reuters-Interview that he was convinced that the decision by Shah Deniz II whom to provide with the gas will be taken very soon. “The best offer does not mean just the price, but rather how secure the whole thing is. You build a pipeline for 50 years or more and it has to work. You have to cross countries, you need stability. Imagine if they have the field ready and the pipeline is not there”.

Steve Garlick, Marketing Manager of BP Shah Deniz II Development presented an optimistic view and stated during the conference “We are moving towards hopefully forming a recommendation, certainly by the end of the first quarter of 2012.”

Mr. Christian Dolezal, Head of Corporate Communication at the Nabucco headquarter in Vienna presented the current status of the Nabucco project. ]]>5936http://www.euro-petrole.com/ne_02_actualite_f_details.php?idNews=5936Thu, 26 Jan 2012 00:00:00 +0100
Le contrat comprend l’ingénierie de détail, la fourniture des équipements et du matériel, la construction, la pré-mise en service et la mise en service d’un hydrocraqueur sous vide de résidus de 2,5 millions de tonnes par an, qui utilisera le procédé H-Oil d’Axens, ainsi que d’unités d’amine, d’adoucissement d’eau et de production d’hydrogène, et la modernisation des utilités et offsites.

Nello Uccelletti, Senior Vice President Onshore de Technip a déclaré : « nous sommes fiers d’avoir été choisis par le Groupe Lukoil pour ce projet majeur. Ce contrat est une reconnaissance du savoir-faire et de l’expertise de nos équipes. Il confirme également le leadership de Technip dans le domaine du raffinage, après des projets comme Dung Quat au Vietnam, Jubail en Arabie Saoudite et Raffinerie d’Alger en Algérie ».

Le centre opérationnel de Technip à Rome (Italie) réalisera le contrat, qui devrait être achevé d’ici janvier 2015.

Le contrat fait suite à la réalisation par Technip au premier trimestre 2010 des études d’avant-projet détaillé et à l’obtention début 2011 du contrat d’ingénierie détaillée et de services de fourniture des équipements.

<a href="http://www.euro-petrole.com/raffinerie-de-burgas-l-234" target="blank" class="lien">Voir le site de la raffinerie de Burgas</a>]]>5937http://www.euro-petrole.com/ne_02_actualite_f_details.php?idNews=5937Thu, 26 Jan 2012 00:00:00 +0100
La partie amont (offshore) du projet porte sur les champs de gaz WA-17-R et WA-253-P situés sur le plateau continental au nord-ouest de l’Australie occidentale par une profondeur d’eau allant de 70 à 200 mètres. La production sera transportée jusqu’à la plate-forme de traitement où le gaz à condensats sera traité puis comprimé et exporté, à travers un pipeline de 200 kilomètres de long, vers l’usine de gaz située à Ashburton North, à 12 kilomètres d’Onslow (Australie).

Ce contrat fait suite à la réalisation par TPO de l’ingénierie d’avant-projet détaillé du projet, attribué par Chevron en 2009. Ce nouveau contrat représente une étape importante pour TPO, qui dirigera les opérations avec un contenu local australien de plus de 40 %. Frans Roozendaal, Managing Director de TPO, a déclaré : « la plate-forme Wheatstone sera une des plus grandes jamais construites, et je suis fier que nous la concevions pour DSME depuis notre centre australien. Nous avons dû nous développer localement pour pouvoir réaliser le contrat, avec plus de 200 personnes travaillant à Perth sur le projet. »

Le Chef de Projet chez DSME, KH Lee, a ajouté : « pouvoir faire appel au bureau australien de Technip pour conduire ce projet a été un atout indéniable. La continuité avec l’ingénierie d’avant-projet détaillé qu’il a réalisé, sa connaissance des spécificités du marché australien et sa proximité avec Chevron nous confèrent un avantage important. »

Les centres opérationnels de Technip à Perth (Australie) et Kuala Lumpur (Malaisie) réaliseront le contrat, qui devrait être achevé au second semestre 2012.]]>5938http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5938Thu, 26 Jan 2012 00:00:00 +0100
This project includes engineering, procurement, construction, installation (“EPCI”) and pre-commissioning of production flowline systems, a MEG injection system, plus start-up condensate transfer and fuel gas transfer flowline systems, control systems as well as other associated SURF elements in water depths up to 275 meters. McDermott will also install mooring systems for the Floating Production, Storage and Offtake vessel and Central Processing Facility as well as installation engineering for future flowlines, risers and umbilicals.

McDermott has already begun engineering and procurement work and is expected to start fabrication of more than 16,000 tonnes of subsea equipment, including a subsea Riser Support Structure and installation aids, at its Batam Island, Indonesia fabrication facility beginning in 2013. The complex offshore installation campaign will see McDermott undertake the installation of subsea hardware, moorings, risers, umbilicals and flowlines utilizing its specialty subsea vessels Emerald Sea and North Ocean 102. McDermott is working with Heerema Marine Contractors (“Heerema”) for transportation and installation of a portion of the offshore scope, utilizing the heavy lift, J-Lay and Reel-Lay capability of Heerema’s new-build vessel Aegir.

Stephen M. Johnson, Chairman of the Board, President and Chief Executive Officer, McDermott said, “McDermott has a long track record working on EPCI projects offshore Australia. This major SURF award firmly endorses McDermott’s core EPCI competencies and our competitive subsea construction vessels, combined with Heerema’s installation strength and the team’s alignment with INPEX. This is a large scale and complex development, and we are firmly behind promoting the success of this LNG project.”

The Ichthys LNG Project is a Joint Venture between INPEX (76%, the Operator) and Total (24%). Gas from the Ichthys Field, in the Browse Basin approximately 200 kilometers offshore Western Australia, will undergo preliminary processing offshore to remove water and extract condensate. The gas will then be exported to onshore processing facilities in Darwin via an 889-kilometer subsea pipeline. The Ichthys LNG Project is expected to produce 8.4 million tonnes of LNG and 1.6 million tonnes of LPG per annum, along with approximately 100,000 barrels of condensate per day at peak.]]>5939http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5939Thu, 26 Jan 2012 00:00:00 +0100 subsidiary in Switzerland, Petroplus Marketing AG, filed for composition proceedings (“Nachlassstundung”).

Petroplus also announced that its subsidiaries in Germany, Marimpex Mineralöl-Handelsgesellschaft mbH, Petroplus Deutschland GmbH, Petroplus Bayern GmbH, Petroplus Tankstorage Holding Deutschland GmbH and Petroplus Raffinerie Ingolstadt GmbH, which owns the Ingolstadt refinery, filed for insolvency proceedings. The Court today appointed Jaffé Rechtsanwälte Insolvenzverwalter as administrator for the assets of the above companies.

Petroplus further announced that its subsidiaries in France, Petroplus Holdings France SAS, Petroplus Marketing France SAS, Petroplus Raffinage Reichstett SAS and Petroplus Raffinage Petit-Couronne SAS, which owns the Petit Couronne refinery, filed for rehabilitation proceedings (“redressement judiciaire”).

The Court today appointed FHB Administrateurs Judiciaires as administrator for the assets of some of the above companies.]]>5934http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5934Wed, 25 Jan 2012 00:00:00 +0100
<a href="http://www.euro-petrole.com/raffinerie-de-coryton-essex-l-135" target="blank" class="lien">To see the Coryton refinery site</a>]]>5935http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5935Wed, 25 Jan 2012 00:00:00 +0100
The project will be implemented by the Italian branch of Technip. Implementation of the project will allow to increase the output of Euro-5 diesel fuel by 1.2 million tons per year and also to close down the production of high-sulfur fuel oil. The key element of the new complex is a tar hydro cracker with an annual capacity of 2.5 million tons.

Commissioning of the new complex is expected in January 2015.

“The commissioning of the complex will put the LUKOIL refinery in Bulgaria among the more technically sophisticated ones, both in Europe and worldwide,” said Vagit Alekperov, President of OAO LUKOIL.

<a href="http://www.euro-petrole.com/raffinerie-de-burgas-l-234" target="blank" class="lien">To see the Burgas refinery site</a>]]>5927http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5927Tue, 24 Jan 2012 00:00:00 +0100
The negotiations with the lenders under the Revolving Credit Facility have not been successful (despite the Company having reached an agreement for crude oil supply) and they have served notices of acceleration, commenced enforcement actions and appointed a receiver in respect of Petroplus Marketing AG’s assets in the UK. Such acceleration constitutes an event of default under the $1.75 billion aggregate principal amount of outstanding senior notes and convertible bonds of Petroplus Finance Limited. The primary goal of Petroplus’ Board of Directors is to ensure that operations are safely shut down and to preserve value for all stakeholders. The Board of Directors has resolved to prepare for a filing for insolvency or composition proceedings (“Nachlassstundung”) in Switzerland and will make the necessary filings as soon as possible. Similar steps are being taken by Petroplus subsidiaries in various jurisdictions.

The filing of insolvency proceedings by any entity that is a guarantor of the senior notes, including Petroplus Holdings AG, Petroplus Refining and Marketing Ltd. and Petroplus Holdings France SAS, will result in an automatic acceleration of the senior notes.

Jean-Paul Vettier, Petroplus’ Chief Executive Officer, said, “It is unfortunate to have reached the point where the Executive Committee and Board of Directors have to inform our employees, shareholders, bondholders and other stakeholders about these circumstances. We have worked hard to avoid this outcome, but were ultimately not able to come to an agreement with our lenders to resolve these issues given the very tight and difficult European credit and refining markets. We are fully aware of the impact that this will have on our workforce, their families and the communities where we have operated our businesses.”Further information will be communicated in due course.]]>5928http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5928Tue, 24 Jan 2012 00:00:00 +0100
Pursuant to the addendum, the annual amount of gas purchase from Azerbaijan will rise from 1.5 to 3 billion cubic meters in 2012 and will surpass 3 billion cubic meters starting from 2013.

Alexey Miller and Rovnag Abdullayev appreciated the rapid development of the companies' interaction in the gas sector and stressed that stronger ties between Gazprom and SOCAR met strategic interests of both countries.

“We have been doubling the purchase of Azerbaijani gas for the second consecutive year. The Russian-Azerbaijani energy partnership is developing at a good pace and that demonstrates the mutual aspiration for further buildup of hydrocarbons supplies. The absence of upper limit for the gas purchase amount, geographic proximity, well-developed gas transmission infrastructure and no transiting zones make natural gas export to Russia most profitable for Azerbaijan,” said Alexey Miller.]]>5929http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5929Tue, 24 Jan 2012 00:00:00 +0100
Losses at the HOVENSA refinery have totaled $1.3 billion in the past three years alone and were projected to continue. These losses have been caused primarily by weakness in demand for refined petroleum products due to the global economic slowdown and the addition of new refining capacity in emerging markets. In the past three years, these factors have caused the closure of approximately 18 refineries in the United States and Europe with capacity totaling more than 2 million barrels of oil per day. In addition, the low price of natural gas in the United States has put HOVENSA, an oil-fueled refinery, at a competitive disadvantage.

“We deeply regret the closure of the HOVENSA refinery and the impact on our dedicated people,” said Brian K. Lever, President and Chief Operating Officer of HOVENSA. “We explored all available options to avoid this outcome, but severe financial losses left us with no other choice. We will provide significantly enhanced benefits for those union and salaried employees who are impacted and will work closely with the government of the U.S. Virgin Islands to ease the transition for the rest of the community.”

After formal shutdown of the refinery, which will occur by the middle of February, most of those employed at HOVENSA will continue working through a transition period. Thereafter, approximately 100 people will remain to work at the oil storage terminal.

<a href="http://www.euro-petrole.com/raffinerie-de-saint-croix-l-524" target="blank" class="lien">To see the St. Croix Refinery site</a>]]>5930http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5930Tue, 24 Jan 2012 00:00:00 +0100
Höegh LNG intends to use the second of the two new regasification vessels currently being built in Korea for the 10 year lease agreement which will commence in the second half of 2014. The lease is expected to give an EBITDA contribution of about USD 50 million per year.

Höegh LNG's President and Chief Executive Officer, Sveinung Støhle, said in a comment

"We are pleased to have been selected by Klaipedos Nafta as having the winning tender offer for a new floating LNG import terminal in Lithuania and look forward to working together with the company to develop the project. This award confirms the Höegh LNG's strong position in the FSRU market and this segment will remain our main focus for continued growth in the future."]]>5931http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5931Tue, 24 Jan 2012 00:00:00 +0100
The acquired assets consist of interests in six fields including the Itteville (79%), Vert Le Grand (90%), Vert Le Petit (100%), La Croix Blanche (100%) and Dommartin-Lettree (56%) fields in the Paris Basin and the Vic Bilh (73%) field in the Aquitaine Basin (the “Assets”). Vermilion previously held the remaining non-operated working interests in each of the Itteville, Vert Le Grand and Vic Bilh fields and now holds a 100% operated working interest in each of the acquired fields with the exception of the Dommartin-Lettree field in the Paris Basin in which the Company now holds a 56% non-operated interest.

Based on estimated 2012 average daily production levels the acquisition metrics reflect a cash cost of approximately C$52,000 per boepd and C$17.21 per boe of proved plus probable reserves as evaluated by GLJ and effective December 31, 2011.

Vermilion continues to maintain considerable financial flexibility after closing of the Acquisition with approximately C$640 million of remaining borrowing capacity.

The Acquisition is a natural addition to the Company’s current France asset base and is well aligned with its strategic objective to maintain and consolidate the Company’s core operating areas and own and operate 100% of its assets. The Acquisition further strengthens Vermilion’s position as the leading oil producer in France, and with a significant weighting toward high quality oil will provide robust netbacks in the current commodity price environment. Vermilion believes it has identified numerous areas where it can reduce the Asset's current cost struture and increase production through optimized production operations, waterflood management and exploitation of infill development opportunities.


(1) Estimated proved plus probable reserves attributable to the Assets as evaluated by GLJ Petroleum Consultants Ltd. (“GLJ”) in a report dated October 14, 2011 with an effective date of December 31, 2011]]>5932http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5932Tue, 24 Jan 2012 00:00:00 +0100
The contract for the power and positioning system was signed in November 2011 and calls for Wärtsilä to supply for each rig a total of six 12-cylinder Wärtsilä 32 engines in V-configuration with ancillaries, and six Wärtsilä FS3500 main steerable thrusters, as well as the integration of the entire system. Additionally, the engines and thrusters will be equipped with Wärtsilä’s unique condition monitoring system. Delivery will begin in 2012 and the first rig is scheduled to be operational during 2014. Wärtsilä has an option for two further rigs.

“The proven reliability and superior efficiency of the Wärtsilä propulsion solutions were the major factors in the award of this contract. Calculating the average load profile for deepwater drilling rigs, the efficiency is approximately three per cent better than those offered by competitors. The high efficiency enables fuel cost savings and has also clear benefits in terms of reducing carbon dioxide emissions (CO2). Furthermore, the local Wärtsilä service network in Norway will provide full support for the equipment,” says Magnus Miemois, Vice President at Wärtsilä Ship Power, Offshore.

The semi-submersible rigs are custom designed for efficient year-round drilling, completion, testing and intervention operations in harsh environments and arctic conditions. They will be operated on the Norwegian Continental Shelf by Statoil, the international energy company headquartered in Norway. The rigs meet the Det Norske Veritas CLEAN-DESIGN criteria, meaning that the Wärtsilä engines are IMO Tier 2 compliant.

Songa Offshore is an existing customer of Wärtsilä, having earlier in 2011 taken delivery of eight thrusters for the “Songa Eclipse” semi-submersible rig.]]>5933http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5933Tue, 24 Jan 2012 00:00:00 +0100
The two exploration blocks are located in the highly prospective West African Transform Margin, home to several recent major discoveries in Ghana (Jubilee, Odum) and Sierra Leone (Venus, Mercury). In addition, in 1979 Chevron drilled the Jammah-1 well on the basis of sparse 2D data in block A2. The well had gas shows, thereby establishing the presence of hydrocarbons in the area. More recently, extensive 3D seismic shot on the two Gambian blocks A1 and A4, immediately west of the blocks A2 and A5, has revealed a number of material prospects and leads according to the operator, African Petroleum Corporation Limited (NSX:AOQ). According to African Petroleum’s third party estimates, one of the prospects, the Alhamdulilah prospect, has potential mean unrisked resources of approximately 500 million barrels.

Chairman and CEO Dr. Kase Lawal commented, “We are extremely pleased to be awarded these two blocks. Gambia’s blocks A2 and A5 represent highly sought after assets in one of the world’s most exciting hydrocarbon provinces, the West African Transform Margin. Today’s announcement demonstrates additional progress in our frontier exploration strategy. It also reaffirms the Company’s reputation as a value added oil and gas partner to National Oil Companies in Africa.”]]>5923http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5923Mon, 23 Jan 2012 00:00:00 +0100
DeGolyer &amp; MacNaughton also audited Rosneft's hydrocarbon reserves under PRMS classification. Proven hydrocarbon reserves as of December 31, 2011 stood at 23,352 million BOE. Of this total, oil reserves stood at 18,351 million barrels (2,519 million tons) and gas reserves at 30,004 billion cubic feet (850 billion cubic metres). As of the end of 2011, Rosneft's reserve life was 25 years; 21 years for oil and 68 for gas.

Furthermore, DeGolyer &amp; MacNaughton audited Rosneft's resources. As of December 31, 2011, the mean estimate of the Company's prospective recoverable hydrocarbon resources was 134 billion BOE, which is three times as much as at the end of 2010. This was due to the acquisition of license blocks on the Kara and Black Sea shelves. Rosneft also obtained licenses for 5 promising blocks on the Sea of Okhotsk shelf at the end of 2011. Resources contained within these blocks were not included in the audit but are preliminarily estimated at over 20 billion BOE.

With these figures, Rosneft confirmed its status as one of the world's largest public oil companies by proven liquid hydrocarbon reserves. The Company has also sealed its position as the absolute leader in terms of hydrocarbon resources.]]>5924http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5924Mon, 23 Jan 2012 00:00:00 +0100
Cairn will continue as operator and retains a 56.875% working interest while partner Nunaoil will retain its carried (pre-development) interest of 12.5%.

The Pitu licence lies immediately adjacent to the two Shell-operated licences, Anu and Napu, where Statoil has a working interest of 20.125% and 14.875% respectively.

“We are looking forward to exploring this new frontier opportunity in Baffin Bay together with our partners and in close cooperation with the Greenland authorities. The new licence increases the optionality in our arctic portfolio,” says Nicholas Alan Maden, senior vice president in Exploration international in Statoil.

The current work programme includes the interpretation of recently acquired seismic data. The first exploration period expires on 31 December 2014 and all initial work commitments have been fulfilled.

The partnership will evaluate the seismic data prior to making a decision on drilling an exploration well. Cairn will retain operatorship at this stage, while Statoil will operate any future development.

The agreement is subject to final partner and Greenlandic governmental approval.

In 1999, Statoil drilled an exploration well in the Fylla area west of Greenland. The company relinquished this exploration licence in 2002. Statoil is a member of the KANUMAS group in East Greenland.]]>5925http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5925Mon, 23 Jan 2012 00:00:00 +0100
Pursuant to the assignment by Vladimir Putin, Prime Minister of the Russian Federation, a decision was made to significantly speed up the project implementation launch. The meeting approved a detailed action plan that would make it possible to start the South stream gas pipeline construction in December 2012 instead of 2013 as had been previously planned.

“We have everything in place to significantly expedite the previously announced date of the South Stream construction launch. We have a regulatory basis, great interest of the project participants in Europe, the required funds and the unique track record of delivering large-scale gas transmission projects offshore. The project is in great demand, people are looking forward to it and we are ready to launch it,” said Alexey Miller at the meeting.

The South Stream construction schedule developed by Gazprom will be submitted to the Board of Directors of South Stream Transport in February.]]>5926http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5926Mon, 23 Jan 2012 00:00:00 +0100
In addition to estimated proved reserves of 71.5 million barrels of oil equivalent and current net production of 18,000 boe per day, Cordillera has assembled a leading acreage position with significant resource potential including 14,000 potential drilling locations in liquids-rich Anadarko Basin plays. The acquired acreage is characterized by high working interest and operatorship; approximately half is held by production.

"This is an important growth step for Apache — a unique bolt-on opportunity that more than doubles Apache's acreage in a highly liquids-rich fairway in the Anadarko Basin," said G. Steven Farris, chairman and chief executive officer. "Apache has been active in the Basin for more than 50 years; the experience we have gained drilling 500 wells in the Granite Wash play — including 79 horizontals drilled since 2009 — gives us an in-depth understanding of the geology and the operating environment and will enable us to hit the ground running.

"Multiple, stacked horizontal targets provide decades of potential drilling locations," Farris said. "Because 80 percent of revenue comes from liquid hydrocarbons production, this transaction provides compelling economics at current commodity prices."

The acquisition is expected to be accretive to Apache's earnings and cash flow beginning in 2012. The development drilling program is self-funding beginning in 2013.

The sellers, including EnCap Investments, other institutional investors and Cordillera management will receive approximately $600 million in Apache common stock subject to customary lock-up provisions. The balance of the consideration will be paid in cash to be funded with debt. The effective date of the transaction is Sept. 1, 2011, with closing anticipated in the second quarter, subject to regulatory approval and customary closing conditions.

"This transaction presents a tremendous opportunity for Apache to combine the Cordillera assets with its legacy western Anadarko Basin position, creating a platform for a multi-decade development program in some of the most economic, oil- and liquids-rich gas targets in the onshore United States," said George H. Solich, Cordillera's president and chief executive officer. "The combination is an excellent outcome for the Cordillera shareholders. We are taking a meaningful amount of the consideration in Apache shares, reflecting our confidence that the quality of the asset base will continue to yield economic growth in production and cash flow for years to come."

Cordillera will continue to acquire acreage in the area on Apache's behalf through closing.

A wash, including the Granite Wash, consists of a series of thick, multi-layer, liquids-rich sandstones and conglomerates. While it is considered "tight" by conventional standards, the Granite Wash possesses reservoir properties superior to typical shale resource plays, and responds well to horizontal drilling with multi-stage fracturing completions. A typical producing column in the acreage fairway is more than a mile thick with up to five liquids-rich Granite Wash targets and five additional oil-bearing tight sandstone targets. Approximately 50 percent of the hydrocarbon stream is liquid — condensate and natural gas liquids. Additional deep gas horizons include the Skinner, Atoka and Morrow. According to Oklahoma regulatory agencies, more than 60 separate formations currently produce oil and gas in the fairway.

As a result of Apache's shift to horizontal drilling with multi-stage completions, horizontal wells drilled in the last three years — all successful — now account for about half of Apache's Central Region production which totaled about 40,000 net barrels of oil equivalent per day at year-end 2011. "With this growth step, we expect to more than triple the pace of our operated activity in the multi-play fairway of combined Apache and Cordillera acreage during 2012," Farris said.

Apache's advisers on the transaction were Goldman, Sachs &amp; Co. and Tudor, Pickering, Holt &amp; Co.]]>5917http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5917Sun, 22 Jan 2012 00:00:00 +0100
The Company also provided the following update in regards to operations. The Cressier refinery has been safely shut down. Labor actions at the Petit Couronne and Antwerp refineries are restricting the lifting of products. The Company will provide further updates to the public as needed.

<a href="http://www.euro-petrole.com/raffinerie-de-petit-couronne-lf-8" target="blank" class="lien">To see the the Petit Couronne refinery site</a>]]>5918http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5918Fri, 20 Jan 2012 00:00:00 +0100
The Government of Jordan’s energy strategy aims to move the country towards 80 per cent of electrical power generation capacity being supplied by natural gas as a primary fuel by 2020. To support this the consortium will conduct a feasibility study for the MEMR covering all aspects relating to importing natural gas in the LNG form. The outcomes of the study will determine preparation for an RFP to attract potential partners to implement the project.

Martin Amison, partner and leading expert on project finance and energy at law firm Trowers &amp; Hamlins commented: “We are delighted to be involved in this project, which builds on our work advising the Government on the Jordan Gas Transmission Pipeline. Jordan is hungry for energy, and recent instability in the Middle East means that energy supply and security should be top of the agenda. It’s clear that the progress of the project will be watched keenly by other governments across the region.”

Alongside Amison, the consortium includes Richard Bass, Director of Navigant's energy practice, who has worked on a number of gas and LNG projects around the Middle East region; Alan Cairns, Managing Director of Mapstone is the consortium’s financial advisor and has worked extensively for both the private sector and the Government in Jordan; and David Layton of Tractebel Engineering’s Power and Gas Department, who has extensive experience of LNG import terminals worldwide.

The team’s immediate focus will be to assist the MEMR to consider the feasibility of Jordan's proposed LNG import project, and assess Jordan's supply and demand balance. The consortium will also assist the MEMR at later stages in the process of preparing and issuing the RFP documents, evaluating the bids, and negotiation of the contractual agreements with the preferred bidder for construction.]]>5919http://www.euro-petrole.com/ne_02_actualite_f_details.php?idNews=5919Fri, 20 Jan 2012 00:00:00 +0100
Située au sud-est de la Turquie, en façade Méditerranée, Ceyhan est positionnée au débouché des pipelines BTC - acheminant le pétrole brut de la mer Caspienne et KC - acheminant le pétrole brut de Kirkourk (Irak). Bénéficiant d'une localisation stratégique et d'avantages nautiques réels, cette zone de Méditerranée orientale promet de devenir le principal carrefour logistique régional de produits pétroliers : flux inter-Méditerranée, exportations vers l'Afrique et l'Asie, proximité de Suez et de la mer Noire.
Ce terminal de stockage de produits finis a aujourd'hui une capacité de 650 000 m3 commercialisés auprès d'une clientèle d'opérateurs pétroliers internationaux.

Le projet de Rubis, dans le cadre de cette alliance, consiste à construire une jetée de 2,4 km et porter la capacité totale du dépôt à 1 million de m3, lui donnant ainsi un avantage compétitif essentiel permettant de capturer une demande logistique régionale croissante et de le positionner parmi les plus actifs de la zone en élargissant sa gamme de clientèle, en diversifiant la gamme de produits stockés (pétrole brut et soutages) et en l'ouvrant au marché local turc dont les importations sont en forte croissance.

Le projet dans sa globalité (travaux d'extension inclus) représente pour Rubis un investissement de l'ordre de 160 millions de dollars US. Cet investissement devrait commencer à dégager sa pleine rentabilité dès la réception des travaux d'extension, lesquels démarrent dans les prochaines semaines pour une livraison prévue au premier trimestre 2014.

Fort, d'une position de leader en France, à travers ses 6 dépôts côtiers, de ses terminaux d'Anvers et Rotterdam dont les extensions se poursuivent, le Groupe franchit une étape décisive en s'implantant en Méditerranée orientale, une région promise à un fort développement, avec à terme plus de 3 millions de m3 de capacités.

<a href="http://www.euro-petrole.com/depot-petrolier-de-ceyhan-l-1257" target="blank" class="lien">Voir le site du dépôt de Ceyhan</a>]]>5920http://www.euro-petrole.com/ne_03_actualite_i_details.php?idNews=5920Fri, 20 Jan 2012 00:00:00 +0100 PGNiG Norway will acquire a 50% interest in the PL648S exploration and production licence, which it will operate, and a 20% interest in the PL646 exploration and production licence. In addition, PGNiG Norway was awarded a 30-percent interest in the small production license PL350B, an extension of existing production license PL350, with the same work program and equities as in PL350.

The award of the operatorship to PGNiG Norway in PL648S also constitutes a major milestone for the company. This is the first operatorship awarded to PGNiG Norway and is a natural development of the company in Norway. It is also the first offshore operatorship awarded to the PGNiG Group and underlines PGNiG Norway's role as an offshore competence center for the PGNiG Group. The partner in PL 648S licence is OMV Norge AS with a 50-percent interest.

Direct operatorship of the PL 646 license was awarded to Wintershall Norge ASA (40-percent interest). The other partners are Lundin Norway AS (20-percent interest) and Norwegian Energy Company ASA (20-percent interest).

The 350B licence is operated by EON (40% interest). The remaining 30% interest in the licence is held by Statoil.

Acquisition of the interests in the PL646 and PL648S licenses is an important element of PGNiG Norway's strategy on the Norwegian Continental Shelf. According to its strategy PGNiG Norway builds hubs like the Skarv field and grows around them. The license area of all three awarded licenses is located in the immediate vicinity of the Skarv field, in which PGNiG Norway holds a 11.9175% stake.]]>