Saipem has won a new offshore Engineering & Construction contract in Azerbaijan, for a total amount of approximately $1.8 billion.

BP, on behalf of the Shah Deniz consortium, has awarded to the Saipem, Bos Shelf and Star Gulf consortium, a Transportation and Installation contract for the Stage 2 development of the Shah Deniz field.

The field is located 90 kilometers offshore Azerbaijan, in water depths from 75 meters to 550 meters. The scope of work of the contract includes the transportation and installation of jackets, topsides and subsea production systems and subsea structures, the laying of over 360 km pipelines, diving support services and the upgrade of the Pipelay Barge Israfil Huseinov (PLBH), Dive Support Vessel Tofiq Ismailov (DSV) and Derrick Barge Azerbaijan (DBA) installation vessels. The project will be completed by the end of 2017.

Commenting on the award, Umberto Vergine, Saipem CEO, said: "The Caspian is a strategic area for the oil and gas industry and we have been working in the region since 1996. We have built a solid and unique presence in the area thanks to our capabilities and expertise in large and complex offshore projects. I'm very pleased that Saipem will be involved in the development of Shah Deniz Stage 2, which will ultimately deliver gas to Europe".

 Saipem has also been contracted by South Stream Transport B.V. to provide supporting works relating to the construction of the second line of the South Stream Offshore Pipeline for a total value of approximately €400 million.

The entire offshore South Stream project consists of four parallel gas pipelines, across the Black Sea from Russia to Bulgaria, each 931 kilometers long, to be laid at depths of up to 2,200 meters.

According to this contract Saipem will perform additional supporting works, including engineering, coordination of storage yards, cable crossing preparation, and connecting the offshore pipeline to the landfall sections through so called "tie ins".

The works relating to the construction of the second line will end by the end of 2016.

This contract is an addendum to the major contract for the first line of the South Stream Offshore Pipeline project signed on the 14 March 2014.

South Stream Transport B.V. is an international joint venture between Gazprom (50%), Eni (20%), EDF (15%) and Wintershall (15%).

Shell today announced an exploration discovery offshore Malaysia. The successful ‘Rosmari-1’ well is located 135 kilometers offshore in Block SK318, and was drilled to a total depth of 2,123 meters.


The well encountered more than 450 meters of gas column. With further exploration planned, the finding is a positive indicator of the gas potential in an area of strategic interest for Shell.

“Rosmari-1 is a testament to our ability to successfully drill and build understanding of new geology within our existing exploration heartlands, adding value to our existing assets in Malaysia,” said Andy Brown, Director Shell Upstream International. “We are expanding and rejuvenating heartlands across our exploration portfolio, including in Brunei, Australia and the Gulf of Mexico.”

“This adds to Shell’s sequence of recent exploration successes in Malaysia, with these discoveries expanding the company’s heartlands positions,” said Iain Lo, Chairman Shell Malaysia.  

Block SK318 is Shell operated with an 85% interest, with the remaining 15% held by PETRONAS Carigali Sdn Bhd.

T.D. Williamson, Inc. (TDW), a leading supplier of pipeline services and equipment, announced that as a result of a complex subsea pipeline pressure intervention carried out in record time offshore Indonesia, it helped to prevent a major gas supply interruption for millions of residents and businesses in Jakarta.

The operation made company history as the largest subsea pipeline pressure intervention that TDW has ever executed. The challenging hot tap and STOPPLE® plugging operation was carried out for main contractor Timas Suplindo in cooperation with Offshore Construction Specialists on behalf of Pertamina EP, on sections of the pipeline network attached to the Lima Flow Station in the North West Java Sea. Work was carried out as part of the Lima Subsidence Remediation Project. The initiative aims to raise the Lima Flow Station that has been slowly subsiding into the seabed since 1997. The flow station consists of compression, service and process platforms, as well as a platform bridge, flare bridge and tower.

Subsidence remediation works threaten gas supply to Jakarta
Stabilizing the L-PRO platform on the seabed by lifting and consolidating it made it necessary to shut down several lines connected to it. A complete shutdown would have severely disrupted the flow of natural gas from the Lima field. "Nine million live in Jakarta; half of whom rely upon natural gas supplied from Lima field, so the stakes were extraordinarily high," said Edward Sinaga, Execution Lead for Pertamina EP. "Without gas from Lima field, much of the city would have been thrown into chaos, without power and in some cases, electricity, which was utterly unacceptable. It was critical that supply to the city remain steady while jacking operations took place."

To ensure that production and supply would continue uninterrupted during remediation works, several lines were to be installed to bypass the 14-inch and 20-inch MGL pipelines that extend from the TLA and TLD platforms to the L-PRO platform and the 24-inch MGL pipeline that extends between the L-PRO and Cilamaya, where the pipelines make landfall. Pertamina EP engaged TDW to isolate the affected lines so that temporary bypass lines could be installed through which gas would flow, ensuring uninterrupted supply to Jakarta.

Precise planning + speedy execution produce results
The Lima intervention would prove to be TDW's largest, most demanding subsea hot tap and STOPPLE® plugging operation. The operator afforded TDW only five months to plan, gather resources, and execute this subsea project. Each phase – preparation, engineering assessment, fabrication, simulation, mobilization and execution – had to be carried out to perfection in order to meet the demanding deadline.

To maintain flow and facilitate the installation of the bypass lines, TDW developed a solution that required an intricate series of subsea activities: nine hot taps followed by simultaneously executing STOPPLE® plugging operations in six different locations. Because Pertamina EP required that all intervention work be completed within three months, TDW quickly mobilized equipment from North America, Europe and Asia Pacific, accompanied by a team of experienced technicians, to the hot tap and STOPPLE® plugging operation site.

Following the installation and commissioning of the temporary bypass lines upon the successful completion of nine hot taps, the TDW team could commence with setting the STOPPLE® plugs in six different locations. Working from the dive support vessels (DSVs) at depths up to 131 ft. (40 meters), the five-member team used a full complement of specialist machines to hot tap the pipelines, and STOPPLE® plugging systems with Lock-O-Ring® Plus fittings to plug them for final completion. Once the line has been safely isolated, cold-cutting of the isolated pipeline for the installation of sub-sea in-line ball valve commenced. In just 25 days, all of the lines were hot tapped, STOPPLE plugs set and successfully isolated, making it the fastest such operation in TDW history.

For 22 days, the lines remained safely isolated at a pipeline pressure of 13.78 bar (200 psig). The entire operation was completed in just 63 days, from late July through September 2013. Natural gas flowed continuously through the temporary bypass lines to Jakarta, allowing the city to function without missing a beat.

"The sheer scale and complexity of this subsea operation posed many challenges for Pertamina EP, so we are very pleased that it was completed so quickly and effectively," said Edmund Ang, Operations Manager – Asia Pacific for TDW. "The fact that we were able to simultaneously carry out six STOPPLE® plugging operations at different subsea locations meant that every step of the process had to be precisely orchestrated. But our efforts paid off. By completing them in a matter of days instead of weeks, the lines were properly isolated in time for Pertamina EP to divert flow through the temporary bypass lines to Jakarta."

"The success of this operation on Lima field underscores the trust that Pertamina EP places in TDW to deliver critical pipeline intervention services, reliably and professionally," said Sinaga.

On March 28, InterOil began drilling at the Raptor-1 site, as part of its US$300 million oil and gas exploration campaign in Papua New Guinea. This will be InterOil's third exploration well started in PNG since the beginning of March.

Raptor is about 20km south-west of Wabo in the Gulf Province. The other two exploration wells begun this month are Bobcat-1, about 20km north of Raptor-1, and Wahoo-1, which is near the coast about 180km south-east of Raptor-1.

InterOil expects to drill up to five additional exploration and appraisal wells in PNG in the coming 12-15 months, across almost 4 million acres in the south of the country.

The well will be drilled to a total depth of 4500 meters (2.8 miles). InterOil will announce results when the well is completed.

Subsea 7 S.A. (Oslo Børs: SUBC) today announced the award of a three-year US$160 million contract extension by BP Exploration & Production Inc. for
light subsea construction, inspection, repair and maintenance services in the US Gulf of
Mexico.

The contract will run from the second quarter 2014 to the third quarter 2017. The scope covers the provision of two vessels, including a dedicated vessel on a full-time basis, associated project management and engineering support, ROV-based inspection and intervention, and light construction work.

One of the vessels to be utilised in the contract is a new-build offshore subsea construction vessel while the other is a light construction vessel. Both vessels will be chartered on a long- term basis.

John Evans, Subsea 7's Chief Operating Officer, said: "We are very pleased to have been awarded this important contract extension and to be able to continue growing our valued relationship with BP. This award highlights our proven track record for safely delivering successful Life-of-Field operations."

As part of President Obama's all-of-the-above energy strategy to continue to expand safe and responsible domestic energy production, Bureau of Ocean Energy Management (BOEM) Director Tommy P. Beaudreau has announced that the bureau will offer more than 21 million acres offshore Texas for oil and gas exploration and development in a lease sale that will include all available unleased areas in the Western Gulf of Mexico Planning Area.

Proposed Western Gulf of Mexico Lease Sale 238, scheduled to take place in New Orleans, Louisiana, in August of 2014, will be the sixth offshore sale under the Administration's Outer Continental Shelf Oil and Gas Leasing Program for 2012-2017 (Five Year Program). This sale builds on the first five sales in the current Five Year Program, which have offered more than 60 million acres and netted nearly $2.3 billion for American taxpayers.

"The nation's economy and our national security depend heavily on adequate and reliable domestic sources of energy and the Gulf of Mexico continues to be a critical component of the Nation's energy portfolio," said Beaudreau. "This proposed lease sale underscores our commitment to make millions of acres of Federal waters available for safe and responsible exploration and development."

Sale 238 will include approximately 3,992 blocks, covering roughly 21.4 million acres, located from nine to 250 miles offshore, in water depths ranging from 16 to more than 10,975 feet (5 to 3,346 meters). BOEM plans to offer blocks located, or partially located, within the three statute mile U.S. - Mexico Boundary Area subject to the terms of the U.S. - Mexico Transboundary Hydrocarbon Agreement. BOEM estimates the proposed lease sale could result in the production of 116 to 200 million barrels of oil and 538 to 938 billion cubic feet of natural gas.

"As one of the most productive basins in the world, this lease sale is another important step to promoting responsible domestic energy production through the safe, environmentally sound development of the Nation's offshore energy resources," said Beaudreau. "The decision to move forward with this lease sale follows extensive environmental analysis, public input and consideration of the best scientific information available."

The proposed terms of this sale include conditions to ensure both orderly resource development and protection of the human, marine and coastal environments. These include stipulations to protect biologically sensitive resources, mitigate potential adverse effects on protected species and avoid potential conflicts associated with oil and gas development in the region.

BOEM's proposed economic terms include the same range of incentives to encourage diligent development and ensure a fair return to taxpayers as used in previous sales.

The terms and conditions outlined for Sale 238 in the Proposed Notice of Sale are not final. Different terms and conditions may be employed in the Final Notice of Sale which will be published at least 30 days before the sale. All terms and conditions for Western Sale 238 are detailed in the Proposed Notice of Sale information package, which is available at: http://www.boem.gov/Sale-238/. CD's and copies of the maps may be requested from the Gulf of Mexico Region's Public Information Unit at 1201 Elmwood Park Boulevard, New Orleans, LA 70123, or at 800-200-GULF (4853).

The Notice of Availability of the Proposed Notice of Sale is available today for inspection in the Federal Register at: http://www.archives.gov/federal-register/public-inspection/index.html.

Statoil has signed an agreement to farm down a 15% interest to WRG Angola Block 39 Limited ("WRG") in the Statoil-operated block 39 offshore Angola in the Kwanza pre-salt basin.
WRG is a 50/50 joint venture comprising White Rose Energy Ventures and Genel Energy plc.

"This is part of Statoil's active portfolio management. The farm-down reflects the attractiveness of Statoil's acreage in Angola and having WRG onboard allows us to share exploration risk, while retaining a significant working interest. WRG brings technical experience to a challenging geological setting, and we look forward to a productive relationship with them in Angola," says Gareth Burns, senior vice president for exploration strategy and business development in Statoil.

Statoil operates block 39 and retains a 40% interest after the farm down. The remaining 30% interest is held by Sonangol P&P, 15% interest by Total and 15% interest by WRG.
WRG has also acquired from China Sonangol International Holdings Limited its 15% interest in the Statoil-operated block 38. Following the acquisition Statoil's 55% interest remains unchanged. The remaining 30% interest is held by Sonangol P&P and 15% interest by WRG.

The deals are subject to approval by Sonangol E&P, the Angolan minister of petroleum and the licence partners.

In addition to the Statoil-operated blocks 38 and 39, Statoil is partner in blocks 22, 25 and 40 in the Kwanza basin. The blocks were awarded by Sonangol in December 2011.

Statoil with Total and BP completed the world's largest 3D survey across the licenses covering blocks 24, 25, 40, 38 and 39 in January 2013. The survey covered 26,300 square kilometres.
The partnership in the Statoil-operated blocks 38 and 39 is now well advanced with the in-house processing of seismic data and the prospect evaluation for the future drilling programme.
Statoil will start drilling in its Kwanza-operated portfolio during the second quarter of 2014. Dilolo-1 is the first high-impact prospect to be drilled in block 39.

Following the drilling of Dilolo, Statoil will operate its second commitment well in Block 38 to the north of Block 39. In the next two to three years, Statoil will in total participate in eight commitment wells in the Kwanza basin.

Statoil is also partner and has shares in blocks 4/05, 15, 15/06, 17 and 31 in the Congo Basin offshore Angola.

"The Angolan continental shelf is the largest con­tributor to our oil production outside Norway and a key building block in our international strategy. Angola yielded approximately 200,000 barrels of oil equivalent per day in equity production in 2013, which is around 28% of our total international oil and gas output," says Steinar Pollen, Statoil's country manager in Angola.

Together with partner ConocoPhillips, Statoil has been awarded a deep-water exploration block in the Myanmar waters of Bay of Bengal.

Block AD-10 cover more than 9,000 km2, and is located 200 km from the coast in water depths of approximately 2,000 meters. The license has been awarded to Statoil and ConocoPhillips, each with a 50% equity share and with Statoil as the operator.

Erling Vågnes, senior vice president for Statoil's exploration in the Eastern hemisphere. (Photo: Ole Jørgen Bratland)

"This is a large and virtually unexplored area in a basin with a proven petroleum system and thick sedimentary deposits. With this award, we have accessed at scale in another frontier acreage with significant upside, in line with our exploration strategy," says Erling Vågnes, senior vice president for Statoil's exploration in the Eastern hemisphere.
The award represents a new country entry for Statoil, now operating in 34 countries.

"We have been following the development in Myanmar closely since 2011. Through several visits we have established a good relationship with the authorities in Myanmar, and we have had a continuous dialogue with Norwegian authorities and drawn upon experience from other Norwegian companies present in the country. We look forward to contributing to the further development of the energy sector in Myanmar with our competence and capacity," says Vågnes.

Statoil has committed to environmental and social impact studies and acquiring new 2D seismic during the first study period of 2,5 years. After this the partnership will decide whether or not to enter a three year exploration period.

"Our first steps will be to engage with the appropriate agencies and stakeholders and conduct the studies necessary for safe and secure acquisition of new seismic data. This is a long-term opportunity with high subsurface risk, but with high-impact potential," says Vågnes.

Petrobras work every day to become one of the world's five largest oil producers. Last year, the company reached the unprecedented mark of nine platforms delivered, which will add a million barrels per day to their production capacity.

Get to know these nine platforms completed in 2013:

1) P-58
An FPSO-type platform, P-58 became operational in March 2014. Installed at about 85 km off the coast of Espírito Santo, in water depths of 1400 meters, this platform has a daily processing capacity of 180,000 barrels of oil and 6 million cubic meters of natural gas from pre-salt and post-salt reservoirs.
Check out P-58's construction process.

2) P-55
A semi-submersible type platform, P-55 is the largest of its kind in Brazil. It went into production in late 2013, at the Roncador field (Campos Basin), anchored at a depth of about 1800 meters. It is capable of processing up to 180,000 barrels of oil and of compressing 4 million cubic meters of gas per day.
Learn how P-55 was assembled.

3) P-63
An FPSO-type platform, P-63 went on stream in November 2013. It is capable of processing 140,000 barrels of oil and 1 million cubic meters of gas, and of injecting 340,000 barrels of water per day. P-63 makes up the first production system at Papa-Terra (Campos Basin), which also includes P-61 and SS-88 TAD. Learn more about P-63.

4) FPSO Cidade de Paraty
FPSO Cidade de Paraty went into production in the Santos Basin pre-salt region (Lula Nordeste area) in June 2013, anchored at a depth of 2120 meters, some 300 km off the coast. It is capable of processing up to 120,000 barrels of oil and of compressing 5 million cubic meters of gas per day.

5) FPSO Cidade de Itajaí
FPSO Cidade de Itajaí went into production in February 2013, in the Santos Basin post-salt region (Baúna and Piracicaba Field), 210 km off the coast. It is capable of processing up to 80,000 barrels of light oil and 2 million cubic meters of gas per day.

6) FPSO Cidade de São Paulo
FPSO Cidade de São Paulo went into production in January 2013, in the Santos Basin pre-salt region (Sapinhoá Field). It is capable of processing up to 120,000 barrels of oil and 5 million cubic meters of gas per day.

7) P-61

The first TLWP (Tension Leg Wellhead Platform) type rig to be built and operated in Brazil, P-61 will operate in the Papa-Terra field (Campos Basin) with P-63. Together, the units will have capacity to produce 120,000 barrels of oil per day. It is forecast to go on stream in the second half of 2014.

8) P-62
Installed about 125 km offshore, in the Campos Basin, at water depths of 1600 meters, this FPSO-type platform is expected to go into production in the first half of 2014. It is capable of processing up to 180,000 barrels of oil and 6 million cubic meters of gas per day from post-salt reservoirs.
Check out the construction and assembly process of P-62.

9) SS-88 TAD
The SS-88 TAD (Tender Assisted Drilling) semi-submersible unit will be anchored next to P-61, in the Papa-Terra field (Campos Basin), to provide power, accommodations, drilling fluid storage space, and support systems.

Technological development and knowledge sharing are crucial for conducting prudent operations and avoiding adverse environmental impacts in the northern reaches of the Norwegian Continental Shelf.

"The precautionary principle is fundamental now that petroleum activities are advancing further and further north on the Norwegian Continental Shelf", say Ellen Hambro, Director General of the Norwegian Environment Agency, and Anne Myhrvold, Director General of the Petroleum Safety Authority Norway (PSA).

Prevention and emergency preparedness were the topics of the day on Tuesday, 8 April, at "Når ulykker truer", the accident-risk seminar held by the Norwegian Environment Agency and the PSA.

Many challenges ahead
The northern waters over the Norwegian Continental Shelf pose different potential challenges than areas further south.

Low temperatures increase the risk of icing, drift ice and collisions with icebergs. It is dark for half of the year and polar low pressure systems can bring on sudden changes in the weather with driving snow and strong winds.

Distances are also long. Operations in areas without existing infrastructure present logistical difficulties for ordinary transport and for emergency response.

At the same time, the Barents Sea and northern Norwegian Sea are known to be vital feeding, spawning and nesting grounds for many species of fish and birds. The eco-system around the ice edge is especially productive, and the combination of huge biological diversity and high levels of production make these areas extremely valuable.

The responsibility rests with the companies
The role of the Petroleum Safety Authority Norway in the efforts to protect nature and the environment from harm is primarily focused on the preventive aspect – in other words, trying to stop accidents from occurring in the first place.

The Authority's position is clear: petroleum activities must be conducted as safely in the Barents Sea as on the rest of the NCS. In practice, this means that the special natural conditions in the North may require different technical solutions than further south on the Shelf.

"In areas where the current technical solutions are inadequate, the industry itself needs to produce specific recommendations for resolving the difficulties. The responsibility for operating in a prudent manner rests with the companies. The authorities monitor that the companies are properly assuming this responsibility through consents and audits", explains Anne Myhrvold of the PSA.

Is emergency preparedness good enough?
The Norwegian Environment Agency's particular interest is emergency response to acute pollution.

"We have insufficient knowledge about how emergency response measures work in the ice-filled waters in the High North. For example, how do we handle oil spills in the ice? Many experts propose burning as an effective means of removing oil between ice floes, but it is not known how effective this is for larger oil spills", says the Environment Agency's Ellen Hambro.

Another example is using dispersants to combat oil pollution. At present, these have not been sufficiently well tested in Arctic waters.
Normally, the Environment Agency requires industry to use the best available techniques (BAT) for emergency preparedness for acute pollution. But we currently know too little about how these work when oil meets ice.

"There is a need for improvements in technology and know-how for emergency preparedness in ice-filled waters. This is an urgent issue since we are already having to deal with applications for exploration drilling for oil operations on the ice edge. The oil industry has a responsibility for providing us with the basis we need to be able to regulate petroleum activities", says Hambro.

Knowledge-sharing
The key message to the industry from the Norwegian Environment Agency and the Petroleum Safety Authority Norway is to think cooperatively and holistically.

A number of the operators and rig companies in Norway have experience of high-latitude and Arctic petroleum activities in other countries. This knowledge now needs to be placed on the table, shared and systematised.

"For example, in exploration drilling, it will be advantageous to have several rigs in operation at the same time. This allows more resources to be on hand if something goes wrong", say Myhrvold and Hambro.

Shared understanding
Oil extraction is important for Norway and has broad acceptance in society. But the activity entails a risk of serious harm to the environment and natural resources.

It is important to reduce this risk as much as possible. Stringent requirements from the Environment Agency and the Petroleum Safety Authority will not solve all the problems. The oil companies need to assume their share of the responsibility. This requires cooperation and a shared understanding of which are the most important challenges.

"Precaution is the main principle underpinning our administrative activities. The industry needs to be able to say the same", is the view of the two agencies.

As part of President Obama's Climate Action Plan to create American jobs, develop clean energy sources and cut carbon pollution, the Bureau of Ocean Energy Management (BOEM) has announced the publication of its environmental assessment (EA) of an application for a wind energy resource assessment lease offshore Tybee Island, Georgia.

Southern Company would like to lease an area covering three Outer Continental Shelf (OCS) blocks, approximately three to 11 nautical miles off the coast of Tybee Island, with the intent to deploy a meteorological tower and/or buoys during a five-year lease term. The purpose of these devices is to characterize the wind resources (e.g., wind speed, direction) and collect other data regarding the lease area and surrounding region.

As required under the National Environmental Policy Act (NEPA), BOEM conducted an EA to consider environmental and socioeconomic impacts associated with issuing such a lease and subsequent site characterization activities, such as geophysical, archaeological and biological surveys conducted prior to constructing the meteorological tower and/or deploying the buoys.

Southern Company submitted to BOEM the application to lease the proposed area offshore Georgia in April 2011. Southern Company provided supplemental filings in 2012, which included additional data collection and technology testing activities to be conducted on the proposed lease. On December 14, 2012, BOEM published a Notice of Intent (NOI) to prepare an EA and requested public comments on alternatives for consideration in the EA, as well as identification of important environmental issues associated with issuing the lease and related activities (77 FR 74512). BOEM considered these public comments in drafting the alternatives and assessed reasonably foreseeable environmental impacts associated with them. Comments received in response to the NOI can be viewed at http://www.regulations.gov by searching for Docket ID BOEM-2012-0074.

BOEM is now requesting public input on the recently completed EA, including comments on the completeness and adequacy of the environmental analysis, and on the measures and operating conditions in the EA designed to reduce or eliminate potential environmental impacts. BOEM will consider public comments on the EA before determining whether to issue a Finding of No Significant Impact, or conduct additional analysis under NEPA. The EA can be found by clicking here.

A 30-day comment period follows the April 2 Federal Register publication of BOEM's Notice of Availability of an Environmental Assessment for the lease application submitted by Southern Company. Comments on this EA must be postmarked or received by May 2.

Comments may be submitted to BOEM via the BOEM website at: http://www.boem.gov/About-BOEM/Public-Engagement/Public-Engagement-Opportunities.aspx (click on the "Open Comment Documents" link) or deliver to the following address. Office of Renewable Energy Programs Bureau of Ocean Energy Management 381 Elden Street, HM 1328 Herndon, Virginia 20170-4817 In addition to the request for written comments, BOEM is hosting two open house poster sessions to discuss the EA at the following locations. Wednesday, April 23 (6:00 p.m. to 8:00 p.m.) Coastal Georgia Center 305 Fahm Street Savannah, GA 31401 Thursday, April 24 (6:00 p.m. to 8:00 p.m.) Old School Cafeteria 204 Fifth Street Tybee Island, GA 31328 For more information about this project, go to http://www.boem.gov/State-Activities-Georgia/

Chevron Corporation (NYSE: CVX) announced on Wednesday, its Myanmar subsidiary, Unocal Myanmar Offshore Co., Ltd., has been granted exploration rights in a block located offshore Myanmar, in the Rakhine basin.

Block A5, which spans more than 2.6 million acres (10,600 sq. km), is located approximately 125 miles (200 km) northwest of Yangon. Unocal Myanmar Offshore Co., Ltd. will be the operator of the block with a 99 percent interest. Royal Marine Engineering (RME), a Myanmar-based company, will hold the remaining interest in the block.

"This award expands Chevron's leading position in Asia and complements the company's portfolio of exploration opportunities," said George Kirkland, vice chairman and executive vice president, Chevron Corporation. "The exploration of this block is aligned with Chevron's long-term strategy to seek opportunities to provide energy to a growing region."

"We are pleased with the result of this bid round and the opportunity to evaluate the potential of this strategic acreage," said Melody Meyer, president of Chevron Asia Pacific Exploration and Production Company. "We have a 20-year history in Myanmar, and we look forward to supporting the continued development of the nation's energy sector through the exploration of this prospective block."

Chevron subsidiaries hold a 28.3 percent non-operated working interest in a production sharing contract for the production of natural gas from the Yadana and Sein fields within Block M5 and M6 in the Andaman Sea. The company also has a 28.3 percent non-operated interest in a pipeline company that transports the natural gas from Yadana to the Myanmar-Thailand border for delivery to power plants in Thailand.

Saipem has been awarded two contracts in Angola by Total, for a combined total of more than $4 billion.

The main contract is worth more than $3 billion, and is an EPCI for the engineering, procurement, installation and commissioning of two converted turret-moored Floating Production Storage and Offloading units (FPSO) for the Kaombo Field Development Project, located in Block 32, offshore Angola. Saipem has also been awarded a seven-year contract of approximately $1 billion for operation and maintenance services of the two vessels.

The two converted FPSO units, owned by Total, will each have an oil treating capacity of 115,000 barrels per day, a water injection capacity of 200,000 barrels per day, a 100 million scfd gas compression capacity and a storage capacity of 1.7 million barrels of oil. The scope of work of the contract includes engineering, procurement, conversion of the tankers, fabrication and integration of the topsides of the FPSO units and the installation of the mooring systems, as well as the hook-up, commissioning and operations start-up. Saipem will provide seven years of operation and maintenance services for the FPSO units.

The Kaombo FPSO project will be managed by the Saipem Floaters Business Unit located in France. Part of the activities related to engineering, procurement, topsides modules fabrication and integration as well as commissioning onshore and offshore works will be carried out in Angola. The topsides fabrication activities will be undertaken in Saipem's Karimun Island Yard, located in Indonesia. The tankers conversion and the topsides modules integration will be executed at a shipyard in the Far East. The first FPSO unit will be operational by the first quarter of 2017 and the second unit by the second quarter of the same year.

Commenting on the award, Umberto Vergine, Saipem CEO, said: "This contract is in line with Saipem's strategy of pursuing growth opportunities in high complexity Floaters and FLNG construction in specific geographic areas, such as Asia Pacific and Africa, where the company can leverage its engineering capabilities, strong local content competencies and unique availability of fabrication yards."

At 07.25 on 7 April, Statoil and its partners (GDF SUEZ and OMV) started production on the Gudrun oil and gas field in the North Sea.

"Gudrun is the first new Statoil-operated platform to come on stream on the Norwegian continental shelf since 2005. This is a red-letter day for the company," says Arne Sigve Nylund, Statoil's executive vice president for the Development and Production Norway business area.

The new field contributes to important production from the Norwegian shelf. Statoil expects to recover 184 million barrels of oil and gas (oil equivalent) from the field.

"Gudrun illustrates how we can maximize value creation and realize new projects on the Norwegian shelf by combining new field developments with existing pipelines and facilities," says Nylund.

Around 16.5 million man hours have gone into the Gudrun field development, and a significant number of suppliers from many different countries have contributed to this effort.

The Gudrun investment decision was made during the financial crisis. When the plan for development and operation (PDO) was submitted in 2010, Gudrun was Statoil's only mega-project (investments in excess of NOK 12 billion). Now Gudrun is the first in a long line of field developments operated by Statoil:

"We have delivered the Gudrun field on time and below the cost estimate in the PDO. Choosing a global strategy for Gudrun has contributed to reducing the costs," says Margareth Øvrum, head of the Technology, projects and Drilling business area in Statoil.

The Gudrun platform (Photo: Harald Pettersen/Statoil)

Worth the wait

Gudrun was discovered in 1975. This is a high temperature-high pressure field, and the need for new drilling technology was one of the reasons why these reserves were left in the bank for such a long time. Now we also have available capacity in existing facilities and pipelines.

Oil and gas from Gudrun is sent to Sleipner, where it will be processed before the oil is sent on to Kårstø and the gas to Europe, all through existing pipelines tied in to Sleipner. This allows us to benefit from previous investments made on the Norwegian shelf, Nylund explains:

"The Gudrun concept is a win-win situation. By using existing infrastructure, the Gudrun development costs less and Sleipner gains an extra customer. Gudrun's start-up came at the perfect time."

Modifications have also been carried out on Sleipner and at Kårstø as part of the Gudrun project.

First in a row

Gudrun will be operated from Statoil's offices at Vestre Svanholmen in Sandnes, and is the first new field Statoil operates from the Stavanger region since Sleipner in 1993.

"It's good to see a new field joining the old giants - Statfjord, Snorre and Sleipner. Later on, Gina Krog will also come to Operations South. This field will also be tied in to Sleipner - yet another win-win situation," says Nylund.

GUDRUN FACTS
Gudrun is an oil and gas field in the middle of the Norwegian sector of the North Sea (production licence PL025). The field is located about 55 kilometres north of the Sleipner installations.



The licensees in PL025 are Statoil (operator - 51%), GDF SUEZ E&P Norge (25%) and OMV Norge A/S (24%).

Gudrun has a process facility for partial stabilisation of oil and gas. Oil and gas are transported on to the Sleipner A platform.  The oil is routed on to Kårstø, while the gas goes to European markets through the gas pipelines tied in to Sleipner.

 The field will be developed with a production platform with a steel jacket. 

The jacket was built at Kværner Verdal, the living quarters by Apply Leirvik at Stord. Aibel was awarded the contract for constructing the deck, and built two of the modules in Thailand and one in Poland and Haugesund, where the deck was also assembled. The helicopter deck came from China and equipment packages comes from several countries. 

112 kilometers of pipeline have been laid as well as a 55-km power cable on the seabed between Gudrun and Sleipner. 

430,000 meters of cable have been laid, 2,855 valves have been installed on the topsides and the living quarters has 42 cabins. 

The reservoir is located at a depth of 4,200-4,700 metres, and originates from the Jurassic Age. The pressure in the reservoir is about 860 bar and the temperature approaches 150 degrees. 

The platform will produce from seven production wells, including Gudrun Øst, a discovery made after the plan for development and operation of the Gudrun field was submitted.

Ecopetrol America Inc. placed bids partnering with Murphy Exploration and Production Company -USA and Venari Offshore LLC

- With the results from this round, Ecopetrol America Inc. could raise its share to 149 blocks in one of the most attractive areas for exploration in the world

Ecopetrol S.A. (BVC: ECOPETROL; NYSE: EC; TSX: ECP) announces that its U.S. affiliate (Ecopetrol America Inc.) placed the most competitive bids for 11 blocks in the "Central Planning Area Lease Sale 231" round held in New Orleans on March 19, as disclosed by the Bureau of Ocean Energy Management (BOEM), the governmental authority in charge of the process in the U.S.
In this lease sale, Ecopetrol America Inc. partnered with Murphy Exploration and Production -USA in 7 blocks and with Murphy Exploration and Production -USA and Venari Offshore LLC in 4 blocks.

The official awarding of the blocks will be conducted by BOEM in the coming months after the checking of bids and ascertaining that the companies fulfill the conditions required for the round.

The economic bids placed by Ecopetrol America and its partners in the 11 blocks add up to approximately US $73.2 million with Ecopetrol America's share consisting of approximately US $33.7 million.
In case of being granted, these blocks allow deep sea hydrocarbon exploration in water depths of over 221 meters for a 10-year period. Further, Ecopetrol America Inc. would increase its participation in the U.S. Gulf Coast basin to 149 blocks.
The results obtained strengthen Ecopetrol's position in the U.S. Gulf of Mexico, which it considers a focus area in its internationalization process.

Ecopetrol is Colombia's largest integrated oil & gas company, where it accounts for 60% of total production. It is one of the top 50 oil companies in the world and the fourth largest oil company in Latin America. The Company is also involved in exploration and production activities in Brazil, Peru and the United States Gulf Coast, and owns the main refineries in Colombia, most of the network of oil and multiple purpose pipelines in the country, petrochemical plants, and is entering into the biofuels business.

March 19, 2014- As part of President Obama’s all-of-the-above energy strategy to continue to expand safe and responsible domestic energy production, Secretary of the Interior Sally Jewell announced  on Wednesday that the  oil and gas lease sales for federal waters in the Gulf of Mexico garnered $872,143,771 million in high bids on 329 tracts covering 1,707,358 acres.

“These lease sales underscore the President’s commitment to create jobs and home-grown energy through the safe and responsible exploration and development of our offshore energy resources,” Secretary Jewell said. “The Gulf is a critical component of our nation’s energy portfolio and holds vital energy resources that spur economic opportunities for Gulf producing states as well as further reduce our dependence on foreign oil.”

The Department of the Interior’s Bureau of Ocean Energy Management (BOEM) offered nearly 40 million acres covering tracts in the Central and Eastern planning areas of the Gulf of Mexico, and opened bids from previously offered acreage in the Western planning area. Today’s lease sales build on the first three sales held under the Obama Administration’s Outer Continental Shelf Oil and Gas Leasing Program for 2012-2017 (>Five Year Program) that offered more than 60 million acres for development and garnered $1.4 billion in bid revenues.

"While domestic energy production is growing rapidly in the United States, the Central Gulf of Mexico, as demonstrated by today's lease sale, will continue to be one of the cornerstones of the nation's energy portfolio," said BOEM Director Tommy P. Beaudreau. "The Gulf of Mexico is one of the most productive basins in the world, and the Obama Administration supports the development of our nation’s offshore oil and gas resources in the Gulf of Mexico while protecting the human, marine and coastal environments, and ensuring a fair return to the American people."

Domestic oil and gas production has grown each year the President has been in office, with domestic oil production currently higher than any time in two decades; natural gas production at its highest level ever; and renewable electricity generation from wind, solar, and geothermal sources has doubled. Combined with recent declines in oil consumption, foreign oil imports now account for less than 40 percent of the oil consumed in America – the lowest level since 1988.

Lease Sale 231 for the Central Planning Area attracted $850,809,921 in high bids on 326 blocks covering 1.7 million acres on the U.S. Outer Continental Shelf (OCS) offshore Louisiana, Mississippi and Alabama. A total of 50 offshore energy companies participated in submitting 380 bids.

Lease Sale 225, the first of two lease sales proposed for the Eastern Planning Area under the Five Year Program, is the first sale offering acreage in that area since 2008. The sale encompassed 134 whole or partial unleased blocks covering approximately 465,200 acres 125 miles south of eastern Alabama and western Florida. Though the sale did not receive any bids, continued interest in this area is evidenced by ongoing and planned activity on existing leases from past sales as well as from similar activity on existing leases immediately adjacent to this area within the Gulf’s Central Planning Area. The area will be offered to industry again in 2016 under the current Five Year Offshore Oil and Gas Leasing Program.

In addition to opening bids for these two sales, BOEM opened three pending bids submitted by a company in the August 2013 Western Planning Area Lease Sale 233 for blocks located or partially located within three statute miles of the maritime and continental shelf boundary with Mexico (U.S. - Mexico TransBoundary Area). A total of $21,333,850 in high bids was submitted on three tracts by one company. Leases awarded as a result of these bids will be subject to the terms of the >U.S.-Mexico Transboundary Hydrocarbons Agreement, which was approved by Congress in the Bipartisan Budget Act of 2013 and recently signed by the President.

BOEM established the terms for these sales after extensive environmental analysis, public comment and consideration of the best scientific information available. These terms include measures to protect the environment, such as stipulations requiring that operators protect biologically sensitive features as well as providing trained observers to monitor marine mammals and sea turtles to ensure compliance and restrict operations when conditions warrant.

The terms also continue a range of incentives to encourage diligent development and ensure a fair return to taxpayers, including an increased minimum bid for deepwater tracts, escalating rental rates and tiered durational terms with relatively short base periods followed by additional time under the same lease if the operator drills a well during the initial period.

Following today’s sales, each bid will go through a strict evaluation process within BOEM to ensure the public receives fair market value before a lease is awarded.

Statistics are available for Lease Sale 231 at >boem.gov/Sale-231 and for Lease Sale 233 at >boem.gov/Sale-233 or at >www.boem.gov.