2H Offshore, an Acteon company, has been appointed by Weatherford Secure Drilling® services to manage the design and delivery of the riser equipment for its Managed Pressure Drilling (MPD) system.

The project award follows a successful feasibility study carried out by 2H Offshore, which outlined multiple integrated concepts for the system. 2H's scope of work now includes the development and delivery of MPD riser stack equipment for the next two generations of Weatherford's MPD systems for offshore applications.

Despite the success that has been achieved using MPD offshore to date, there are still some challenges with the ability of offshore, particularly deepwater, rigs to accommodate MPD technologies. Weatherford is developing a fully integrated MPD solution that can be easily incorporated into nearly any deepwater drilling vessel, improving the adaptability and implementation for deepwater MPD systems.

Weatherford and 2H Offshore are working to ensure that the systems meet the new regulations currently being adopted by Det Norske Veritas (DNV) Drill Class N and the American Bureau of Shipping (ABS) CDS Certification.

"Weatherford has recognized that 2H is a leader in system integration and delivery management. This along with our expertise with riser systems has led them to partner with us to meet the demands of their customers and of the industry," said Mark Nolet, project manager at 2H Offshore. "The 2H team in Houston is extremely excited about assisting Weatherford Secure Drilling Services in developing its next generation of managed pressure drilling."

The next generation of Weatherford's MPD system is expected to be delivered in 2015.

First orders for Semco Maritime Rig Projects at Invergordon, UK: Orders for equipment and upgrading of two Prospector Drilling jack-up rigs and Norwegian operated semisubmersible rig Songa Dee.

At the beginning of the year Semco Maritime entered into a strategic partnership with the Port of Cromarty Firth to establish a center for rig upgrades at Invergordon in UK. The first solid orders have now been awarded: In the course of the next months, Semco Maritime will complete various scopes of work on two Prospector Drilling jack-up rigs and the semisubmersible rig Songa Dee.

Two Prospector Drilling rigs
Rig operator Prospector Drilling has chosen Semco Maritime to complete final installations at Prospector 5, a new state-of-the-art jack-up drilling rig. Prospector 5 will see follow-up installation of client supplied equipment for the rig's first assignment. Moreover, minor installation work is to be performed on another Prospector Drilling rig, Prospector 1.

Songa Dee (photo)
The 112 by 80 meters wide Norwegian operated semisubmersible rig Songa Dee is now moored at the Invergordon facilities deep water quay Queens Dock, with various electrical, structural, mechanical and pipe-work scopes to be performed over the next 60 days.

Frank Hall, General Manager Semco Maritime UK:

"Songa Dee is a good example of the type of large rigs that Semco Maritime is able to handle at the deep water facilities at Invergordon. The three orders bode well for our ambition to be the preferred leading provider of rig upgrades in the North Sea region."

As well as Songa Dee, the two Prospector Drilling rigs have arrived at Invergordon, and the Semco Maritime crew of approximately 60 rig upgrade specialists has commenced the work simultaneously at all three rigs.

Center for rig upgrades
The promising start for the newly established Semco Maritime rig yard facility is, not least, a result of a successful and seamless cooperation with the Port of Cromarty Firth.

Bob Buskie, Chief Executive of the Port of Cromarty Firth:

"We are pleased to support Semco Maritime's activities in Invergordon. The Port of Cromarty Firth is transforming, expanding and investing in facilities at Invergordon, particularly within logistics and agency services as well as new warehousing facilities, office buildings and expansion of laydown and storage areas."

For more than 40 years, the Invergordon area in Northern Scotland has delivered engineering work and support for the North Sea's energy sector. With its strategically important location and its position as Scotland's deepest harbor, the port has handled more than 650 rigs through the years.

The Bureau of Safety and Environmental Enforcement (BSEE) published an Advanced Notice of Proposed Rulemaking today in the Federal Register Reading Room soliciting public comments on improving the safety of helideck and aviation fuel operations on fixed offshore facilities. This notice is the most recent step in BSEE's continued efforts to strengthen safety on the Outer Continental Shelf (OCS).

"We know that transportation accidents account for the majority of fatalities on the OCS, and that helicopter-related accidents are a significant concern" said BSEE Director Brian Salerno. "We are looking at our regulations to ensure that the aviation related areas over which we have jurisdiction have the benefit of rigorous safety standards."

Specifically, BSEE is seeking comments on whether to incorporate in its regulations certain industry and international standards for the design, construction and maintenance of offshore helidecks, as well as standards for aviation fuel quality, storage and handling. The bureau is also soliciting information on past accidents or other incidents involving helidecks, helicopters or aviation fuel on or near fixed OCS facilities.

BSEE is responsible for the regulation of offshore facilities engaged in oil and gas operations, including the safety of helidecks and aviation fuel storage and handling on fixed offshore facilities. This notice begins the process of addressing any additional safety issues through new regulations.

The Advanced Notice of Proposed Rulemaking can be viewed hereThe public is invited to submit comments starting tomorrow. Comments can be submitted by any of the following methods:

Federal eRulemaking Portal: http://www.regulations.gov. In the entry titled Enter Keyword or ID, enter BSEE-2014-0001, then click search.

Mail or hand-carry comments to the Department of the Interior; Bureau of Safety and Environmental Enforcement; Attention: Regulations Development Branch; 381 Elden Street, HE3313; Herndon, Virginia 20170-4817

Due to overcapacity in their rig portfolio, Statoil will lay up the COSL Pioneer rig in the fourth quarter of 2014.
The rig is currently carrying out an assignment on the Visund field and is scheduled to complete this work at the end of September.

The COSL Pioneer drilling rig.
(Photo: Ole Jørgen Bratland)

"After a careful review of our drilling plan, we find it necessary to suspend COSL Pioneer for the time being," says rig procurement responsible Tore Aarreberg.

In the beginning of July Statoil also announced that the drilling rig Scarabeo 5 will be temporarily suspended. Scarabeo 5 will be taken out of operations at the end of September for the rest of the year.

"At the moment we have three rigs contracted from COSL Drilling Europe. Our offshore organisation enjoys excellent cooperation with the contractor's drilling teams, and COSL Pioneer has demonstrated consistent, high efficiency in drilling operations. We are in close dialogue with the contractor concerning how the suspension of the rig will be implemented in practice, and we continue to look forward to many years of cooperation with COSL on the Norwegian shelf," Aarreberg says.

The rig is contracted until 2016 and will be used for drilling and completion of production wells on the Norwegian continental shelf.
COSL Pioneer being taken out of operation for a shorter period will have no impact on Statoil's production targets or planned exploration activity on the Norwegian shelf. The company will still be drilling 20-25 exploration wells on the Norwegian shelf in 2014, where the company operates about two-thirds of all wells.

Claxton, an Acteon company, has released an infographic guide to well abandonment costs in the North Sea. Released on the eve of the Oil and Gas UK Offshore Decommissioning Conference, held annually in St Andrews, Scotland, to discuss decommissioning in the region, the infographic highlights the costs operators are facing as they plan future campaigns. Abandonment cost reduction is an area where Claxton helps operators in the North Sea and beyond, via a proven suite of rigless technology.

Claxton has significant experience in platform well abandonment and conductor recovery, having completed the world's first rigless platform well abandonment in 2003. More recently, Claxton carried out the first rigless recovery of a stuck BHA for Maersk on the Tyra East field. More than 280 conductor cutting and recovery projects have been carried out using Claxton's equipment and offshore crews, and the company has worked with Acteon sister company, OIS, to deliver pioneering multi-operator campaigns with the SWAT™ suspended well abandonment tool.

Jamie Hall, marketing communications manager, Claxton, said, "Our infographic, created from Oil and Gas UK's recent review of the North Sea market, highlights the scale of the challenge facing operators. Claxton has a long standing track record of reducing costs associated with platform well abandonment, which Oil and Gas UK estimates at around £4.8 million per well.

"We are also delighted to be sponsoring the annual Offshore Decommissioning conference dinner at the Fairmount Hotel in St Andrews. It is rewarding to be involved in such a significant event for the decommissioning industry, and our commercial team will be on hand during the event to talk to operators about how we can help to reduce their abandonment costs."

The new compressor in operation on the Kvitebjørn field in the North Sea from 17 September will increase production there by 220 million barrels of oil equivalent and extend the field's lifetime with eight years.

The compressor will help boost recovery rate and accelerate production on the Kvitebjørn field. (Photos: Harald Pettersen)

The new compressor contributes to an increase in the recovery rate at the Kvitebjørn field from 55% to 70%. "These are very profitable barrels, which make a considerable contribution to wealth creation on the Norwegian continental shelf.

Increased production and extended lifetime for the field also provides increased ripple effects across the entire value chain," says Kjetil Hove, senior vice president for operations in Development and Production Norway in Statoil.

Valuable modules
The compressor project is making a substantial contribution to the increased recovery of gas resources from the field, which has increased its reserves by 50% since the plan for development and operation was submitted in 2000.

The extra barrels from the compressor are equivalent to a medium-sized, separately developed field.

"Many people don't realize that these relatively small modules are able to contribute as much or more value as new fields and that they cost much less to develop because the platform is already in place," explains Statoil brownfield projects senior vice president Terese Kvinge.

The reason why the new compressor is being installed on a field that has been in production for some years is that pressure in the reservoir has gradually fallen as the oil and gas has been produced. By lowering the pressure on the platform, more can be produced.

The compressor module was built by Bergen Group Rosenberg (now Rosenberg Worley Parson Group) in Stavanger. The 1000-ton module was lifted into position during the summer of 2013.

This is the first phase of pre-compression on Kvitebjørn, but space has been left in the new module for a potential second pre-compression phase as well.

Kvitebjørn value chain
Rich gas and condensate (light oil) from Kvitebjørn are piped to Kollsnes near Bergen and Mongstad further north respectively.
After processing at Kollsnes, the dry gas is piped to continental Europe. The separated NGL is transported by pipeline to the Vestprosess plant at Mongstad for fractionation into propane, butanes and naphtha.

Condensate travels through the Kvitebjørn Oil Pipeline, which ties into the Troll Oil Pipeline II to Mongstad.

Eni has made a new oil discovery in Block 15/06, in the Ochigufu exploration prospect, in deep water offshore Angola. Oghigufu is the 10th commercial oil discovery made in Block 15/06. The new discovery is estimated to contain 300 million barrels of oil in place.

Ochigufu 1 NFW well, which has led to the discovery, will be brought into production in record time. The well is located at approximately 150 kilometers off the coast and 9.8 kilometers from the Ngoma FPSO (West Hub) and the closeness to Ngoma FPSO allows the increase of the resource base of the West Hub project, currently underway. The well was drilled by the Ocean Rig Poseidon Drilling Unit in a water depth of 1,337 meters and reached a total depth of 4,470 meters.

Ochigufu 1 NFW was directionally drilled in order to reach the targets in optimal position and proved a net oil pay of 47 meters, (34° API) contained in the Lower Miocene and Oligocene sandstones with very good petrophysical properties. The data acquired in Ochigufu 1 well indicate a production capacity equal to more than 5,000 barrels of oil per day.

Claudio Descalzi , Eni's CEO said: "This important discovery , which will be brought into production in record time, adds even more value to Block 15/06. Like the recent discoveries in Congo and Gabon, this new find exemplifies the results we can achieve by applying leading edge technologies to exploration, and substantiates the decision to refocus Eni on key oil and gas competences".

Studies are underway in order to evaluate an early tie-in to the Ngoma FPSO, already in location in the West Hub and designed to handle 100,000 barrels of oil production per day.

Eni is operator of the Block 15/06 with a 35% stake. The other partners of the Joint Venture committed to the block are Sonangol P&P (30% stake), SSI Fifteen Limited (25% stake), Falcon Oil Holding Angola SA (5% stake) and Statoil Angola Block 15/06 (5% stake).

Angola is a key Country in the strategy of organic growth of Eni, which has been present in the Country since 1980 with a daily production in 2013 of about 90,000 barrels of oil equivalent per day. In Block 15/06 the two oil development projects West hub and East Hub have already been sanctioned. The production start up of the West Hub project, through FPSO Ngoma, is expected by the end of 2014. In Angola, Eni is also operator of Block 35, located in the deepwater Kwanza Basin.

Production is now underway from the Cardamom development, the second major deep-water facility Shell has brought online in the U.S. Gulf of Mexico this year, following the start-up of Mars B in February.

Oil from the Cardamom subsea development (100% Shell) is piped through Shell's Auger platform (photo). When at full production of 50,000 barrels of oil equivalent a day (boe/d), Auger's total production capacity will increase to 130,000 boe/d.

"Cardamom is a high-value addition to Shell's production at the Auger platform and is another example of our excellence in deep-water project delivery," said Marvin Odum, Shell Upstream Americas Director. "The work to extend the production life of our first deep-water tension-leg platform is impressive and involved advanced exploration and development technology. Our future opportunities in deep water mean that this will remain an important, high-return growth area for Shell."

Since its first production in 1994, the facility has received several upgrades to process additional production from new discoveries. Cardamom is Auger's seventh subsea development.

The Cardamom reservoir sits beneath thick layers of salt in rock more than four miles (6.4 kilometers) below the sea floor and went undetected by conventional seismic surveys. Shell used the latest advancements in seismic technology to discover Cardamom in 2010.

The Cardamom field is 225 miles (362 kilometres) south-west of New Orleans, Louisiana, in water more than 2,700 feet (820 metres) deep.

Other deep-water Gulf of Mexico growth for Shell includes the Mars B (Shell 71.5%) development, which continues to ramp up production; the ultra-deep-water Stones (Shell 100%, 50,000 boe/d) project, which is under construction; front-end engineering and design is progressing for the Appomattox (Shell 80%) project; and, in a recent exploration success, Shell announced a major discovery at its Rydberg (Shell 57.2%) well in the Norphlet play. Shell also discovered oil at its Kaikias (Shell 100%) well in the Mars basin, which will require further appraisal in 2015.

Last month, Shell also started oil production from its Bonga North West (Shell 55%, 40,000 boe/d) deep water development off the coast of Nigeria and recently announced a natural gas discovery at its Marjoram-1 (Shell 85%) deep-water well in Malaysia, where the Gumusut-Kakap (Shell 33%) deep-water platform is also on track for production this year.

Bechtel has been selected by Louisiana LNG Energy, LLC to provide front-end engineering and design for a new midscale liquefaction facility and export terminal in Louisiana, south of New Orleans on the Mississippi River. The design will center on a modular approach, which shortens the construction schedule and accommodates future expansion.

"Bechtel brings world-class expertise in the engineering, design, and construction of LNG liquefaction projects coupled with leadership in modularization and Gulf Coast self-perform work," said Jim Lindsay, chief executive officer of Louisiana LNG Energy.

"This is an exciting project that will harness the region's energy potential," said Jack Futcher, president of Bechtel's Oil, Gas & Chemicals business unit. "We will apply our extensive project delivery experience to provide Louisiana LNG Energy the most efficient design for fast-track construction of the facility. We look forward to working with them."

The new facility will have an initial export capacity of 2 million metric tons per annum of liquefied gas and will use Chart Energy and Chemicals' proprietary liquefaction technology. The export terminal will be positioned to serve large liquefied natural gas (LNG) carriers. Completion of the project is expected in late 2017.

Bechtel is the global leader in the LNG industry. The company is responsible for a third of LNG liquefaction capacity under construction today, including four projects in Australia and the first LNG export facility in the United States.

Global energy company Repsol has selected Deep Sea Mooring (DSM) to provide a range of mooring services for their drilling operations on the Norwegian Continental Shelf.

DSM will be responsible for marine engineering and supplying the mooring equipment. The company will also assist in offshore operations, including both pre-lay and rig move.

Åge Straume, CEO of Deep Sea Mooring said: "Winning this contract further proves that major energy companies appreciate our experience, robust technology and competence in delivering complete mooring systems for the harsh environment of the North Sea."

He added that this was the first time the two companies have worked together: "It's always exciting to showcase our expertise with a new client and we look forward to developing a solid and long-term partnership with Repsol."

The framework agreement is set to commence immediately and last four years including options. Deep Sea Mooring will manage the contract from its headquarters in Bergen.

Statoil ASA (OSE: STL, NYSE: STO) farms down in Aasta Hansteen, Asterix and Polarled andexits two assets on the NCS for a consideration of USD 1.3 billion, including contingent payment.

Illustration: The Aasta Hansteen platform will be the largest SPAR platform in the world. (Illustration: GeoGraphic / Statoil)

Through this transaction Statoil monetizes on the Aasta Hansteen field development project, while retaining the operatorship and a 51 % equity share. In addition Statoil exits the non-core Vega and Gjøa fields. The transaction includes a farm down in four exploration licenses in the Vøring area. The buyer is Wintershall, a Germany-based energy company and a well-established player on the Norwegian Continental Shelf (NCS).

"We realize significant value, created through successful asset development. The transaction increases our flexibility to further strengthen our portfolio," says Arne Sigve Nylund, president for Development and Production Norway in Statoil.

The transaction consists of a cash consideration of USD 1.25 billion and a USD 50 million consideration contingent on Aasta Hansteen milestones. The accounting gain from the transaction is expected to be between USD 0.7-0.9 billion and will be adjusted for activity between the effective date 1 January 2014 and the closing date.

The transaction releases around USD 1.8 billion of capital expenditure for the period from the effective date until end of 2020. Statoil's production from the divested Gjøa and Vega assets in the first half of 2014 is 22.000 barrels of oil equivalent per day. The transaction includes a transfer of operatorship of the sub-sea field Vega. The transaction will not involve transfer of personnel.
"We have a strong portfolio of projects. This transaction focuses our NCS portfolio and further improves our capacity to invest in core areas," says Nylund.

Statoil will invest around 20 USD billion annually in the period 2014-2016. This includes NCS project Gudrun which started up April this year, while Valemon will come on stream towards the end of year. In addition projects like Aasta Hansteen and Gina Krogh are in the execution phase, while Johan Sverdrup and Johan Castberg are under planning. The exploration activity remains high with 50 exploration wells planned globally for 2014.

Statoil and Wintershall have signed an extended agreement to continue cooperating on EOR efforts and exploration. 
The effective date for the transaction is 1 January 2014. Closing is expected around year end 2014, pending government approval.
Strategic portfolio management

In recent years Statoil has undertaken a series of transactions to position Statoil as a well-capitalized, technology focused upstream company. Active portfolio management continues to realize substantial value that is channeled to further strengthening the company's growth potential. Total proceeds of around USD 20 billion have been realized through divestments by Statoil since 2010, including this transaction.

Recent portfolio optimization activity includes divestments internationally as well as on the NCS. Last year Statoil divested their holdings in two West of Shetlands fields, Rosebank and Schiehallion. The same transaction also included shares in Gullfaks and Gudrun.

Lambert Energy Advisory was financial advisor to Statoil on this transaction.

With the oil & gas industry's push into new energy frontiers, the offshore pipeline industry is faced with greater technical challenges relating to pipelines and the expectation that it will optimize solutions to be cost effective. DNV GL is launching three new Joint Industry Projects (JIPs) to help the industry address these challenges.

The first JIP will make pipeline free span intervention less costly, the second will result in faster and more consistent pipeline repair and the last will optimize the design of pipeline components faster.

"Offshore pipelines are the veins on an offshore field development and represent a large part of the total investment and the value of the transported product can be enormous. DNV GL is committed to supporting the industry to work smarter, safer and greener. All three cooperation projects present an opportunity for the industry to work more efficiently, either through optimized and more reliable design, faster execution of projects, or safer and more robust operation", says Asle Venås, Global Director for Pipelines in DNV GL.

Free Spans in Trenches JIP
Gaps between the seabed and pipeline, known as free spans, can lead to vibrations which may damage the pipeline. "Lack of knowledge about the extent of vibrations in small gaps that typically occur on sandy seabeds means the industry is conservative and is potentially over-dimensioning designs and conducting unnecessary interventions. The DNV GL JIP aims to address this problem by developing improved free span assessments which will lead to fewer interventions and reduced cost," says Olav Fyrileiv, Project Manager, DNV GL – Oil & Gas.
The project comprises computational fluid dynamic analysis combined with a significant test program and the outcome will be an extension of DNV GL's Recommended Practice for Free Spanning Pipelines (DNV-RP-F105). DNV GL has already partnered with Dutch pipeline operator BBL Company V.O.F. and is now inviting other pipeline operators to also join the project.

Pipeline Repair JIP
Maintenance and modification technology on offshore pipelines is developing to accommodate deeper and harsher environments and reduce downtime. Technology and operational experience have been developed through several projects, such as remote pipeline operations using hyperbaric welding and Statoil's successful Hot Tap operations in the North Sea.

"DNV GL is inviting the main players in the pipeline repair equipment sector to collaborate with us in reviewing recent developments in pipeline repair and maintenance. We plan to develop formalized criteria and procedures in an updated version of DNV GL's Recommended Practice on Pipeline Subsea Repair (DNV-RP-F113). The aim is to reduce the time and cost spent on the design and execution of pipeline repairs," says Dag Øyvind Askheim, Project Manager, DNV GL – Oil & Gas.

Design of Pipeline Components JIP
Today, internationally recognized standards and recommended practices cover the limit state design of subsea pipelines. However, such design codes only provide high level guidance on how to consider pipeline components within a pipeline system.

Currently, there is not a consistent and unified approach to the design of pipeline components. With modern pipeline standards, the pipeline design is optimized and this gap becomes even more pronounced. The objective of this JIP will be to develop an approach, based on industry experience and best practice, to pipeline component design that is compatible with a modern pipeline limit state design code such as DNV-OS-F101. "The aim is to help prevent project delays, increased costs and, in some cases, compromised safety, which can happen when the interpretation of codes is stretched. We are inviting major players working with pipeline systems and components," says Jonathan Wiggen, Project Manager, DNV GL – Oil & Gas.

The discovery well 7319/12-1, drilled by the drilling rig Transocean Spitsbergen, proved a 15-meter gas column in the well path. Statoil estimates the volumes in Pingvin to be in the range of 30-120 million barrels of recoverable oil equivalent. The discovery is currently assessed as non-commercial.

Pingvin is the first well drilled in PL713 – a large frontier area northwest of Johan Castberg awarded in the 22nd concession round. For a discovery in this area to be commercially viable it needs to be an oil accumulation of a significant size. A gas discovery does not have commercial value at present. 

"On the positive side, it is encouraging that the first well drilled in this unexplored area has proven hydrocarbons in sandstones. This indicates that we have both a reservoir and a working hydrocarbon system in the area, and creates a good basis for further subsurface work in the licence," says Dan Tuppen, vice president exploration Barents Sea and Norwegian Sea.

Pingvin is a good example of efficient exploration performance.

"The partnership drilled Pingvin just 15 months after the acreage award. The chosen well location allowed us to clarify the hydrocarbon volume in the structure with one very efficiently executed exploration well," says Tuppen.

Exploration well 7319/12-1 is located in PL713 about 65 kilometers northwest of the Johan Castberg discovery. Statoil is operator with an interest of 40%. The partners are RN Nordic Oil AS (20%), North Energy ASA (20%) and Edison International Norway Branch (20%).

For further details on the results of exploration well 7319/12-1, please see the press release issued by the Norwegian Petroleum Directorate (NPD).

Leading oil and gas experts are lined up to present at the 20th SPE ICoTA European Well Intervention Conference which will, once again, bring industry professionals together to discuss current trends and new technologies within well intervention and completion.

Taking place on 12/13 November at Aberdeen Exhibition and Conference Centre, the annual conference is hosted by the Society of Petroleum Engineers (SPE) Aberdeen Section and the Intervention and Coiled Tubing Association (ICoTA) European Chapter. The conference will feature over twenty presentations from a variety of major oil and gas operators, including BP, Shell, ConocoPhillips and Statoil and specialists from the coiled tubing sector, including AnTech.

An extensive range of topics will be covered over the course of the two day conference, including the world's first deepwater propellant perforation for a depleted carbonate subsea gas well. Oil & Gas UK will also present the conference with the findings of the 4th Well Intervention Excellence Network.

Michael Taggart, Chairman of the conference committee, is looking forward to welcoming delegates to the event: "Sharing skills, knowledge and experience for the benefit of the oil and gas industry is high on the agenda for both SPE and ICoTA. We are therefore delighted that this conference has come to be regarded as Europe's premier forum for exchange and discussion of the latest developments in well intervention and completion techniques.

"Now in its 20th year, the conference has matured into an influential event where well intervention professionals attend to share knowledge, learn and do business. By imparting our knowledge and experiences from the North Sea and beyond, we can push the boundaries of well intervention and ensure a healthy oil and gas industry for the future."

A pre-conference short course on 11 November entitled, 'An introduction to well intervention', is aimed at those who have an interest in the topic but are new to the subject or are looking for a refresher and will appeal to those looking to gain a basic understanding of well intervention operations.

McDermott International, Inc. (NYSE: MDR) ("McDermott") is pleased to announce the successful completion of the Jack and St. Malo project for Chevron U.S.A. Inc. The project involved the installation of jumpers, flying leads, subsea pump stations, umbilicals and subsea landing of some of the industry's largest and complex umbilical end terminations to a host floating production platform in 7,200 feet of water 279 miles offshore Louisiana. The project is part of the first stage of development of the Jack South, St. Malo South and St. Malo North Drill Centers.

McDermott subsea construction vessel NO102 installed umbilicals totaling 65 miles along with other related subsea structures. (Photo: Business Wire)

McDermott executed in-house fabrication of 21 high specification rigid flowline, manifold and pump jumpers and installed the structures using the Derrick Barge 50 ("DB50") with its specialized deepwater lowering system. In addition, more than 80 flying leads, five additional rigid production well jumpers and other subsea control and production boost components were installed by the DB50 – including three pump stations each weighing 209 tons to a depth of 6,988 feet. The DB50 was assisted by a fleet of up to 12 support vessels delivering material from various Gulf Coast fabrication and staging facilities to the offshore installation site.

Additionally, three control and two power umbilicals totaling 65 miles were transported and installed by the subsea construction vessel North Ocean 102 ("NO102") along with other related subsea structures.

"Our ability to fabricate the jumpers in house and utilize the combined strengths of the DB50's deepwater lowering system and the high payload and top tension capacity of the NO102's 330-ton vertical lay system allowed McDermott to deliver an integrated subsea solution for our client on this complex deepwater project," said Tony Duncan, Executive Vice President Subsea. "As the industry moves into deeper water, McDermott continues to tailor its subsea engineering expertise, fabrication facilities, and global fleet of specialized vessels to meet the evolving technical needs of our clients."

Located in the Gulf of Mexico Walker Ridge Area, the Jack and St. Malo fields are jointly being developed with a host floating production unit.

Statoil has completed the Martin well in US Gulf of Mexico and the Dilolo well in the Kwanza basin in Angola.

Statoil announces a small discovery in its Martin prospect located in the Gulf of Mexico (GoM). Statoil does not consider this to be a commercial discovery. The well has been drilled efficiently and plug and abandonment operations (P&A) are now ongoing.
Once P&A operations are completed the Maersk Developer rig  (photo) will move to the impact Perseus prospect in De Soto Canyon (DC) 231.

Angola, Kwanza basin
The Dilolo-1 exploration well in block 39 offshore Angola in the Kwanza basin was drilled to its pre-salt target.

The first drilling operation in block 39 has now been completed. In this first well hydrocarbons were not encountered, but the operation did provide a valuable calibration for other prospects in the area.

Further studies are needed in order to fully understand the well results. The well is now in the process of being plugged and abandoned.

The Stena Carron drillship (photo-right) will soon move to block 38 to spud the exploration well Jacaré-1.The Angolan pre-salt is a frontier play where Statoil will participate in eight commitment wells across five blocks.

Other ongoing activities
Statoil is currently also drilling the Giligiliani well in block 2 in Tanzania and has recently spudded the Romeo prospect near the King Lear discovery in the Norwegian North Sea.

Statoil is also preparing for its 18-month drilling campaign on the east coast of Canada following up the Bay du Nord oil discovery.
The company is also participating in two more wells in the Kwanza basin in Angola. These are the Puma well in block 25 (operated by Total) and the Locosso well in block 22 (operated by Repsol).

In Brazil, the Repsol-operated Seat-2 well in block BM-C-33 in the Campos basin is currently being drill stem tested (DST) after encountering a pre-salt hydrocarbon-bearing section.

Ownership overview:
Statoil is the operator (42.5%) of Martin, and its partners include Nexen (25%) and LLOG (26%).
In Angola on block 39, Statoil is the operator (37.5%), and its partners include Total (7.5%), WRG (15%), Ecopetrol (10%) and Sonangol P&P (30%). 

In block 38 Statoil is the operator (45%), with WRG (15%), Ecopetrol (10%) and Sonangol P&P (30%) as partners*.
* The Ecopetrol farm-in is subject to approval by Sonangol E&P and the Angolan minister of petroleum.