Talos Energy LLC Announces Historic Oil Discovery Offshore Mexico

1TalosEnergylogo copyTalos Energy LLC ("Talos" or the "Company") as operator, together with its joint venture partners Sierra Oil and Gas S. de R.L de C.V. ("Sierra") and Premier Oil Plc ("Premier"), is pleased to announce that the Zama-1 exploration well, offshore Mexico, has discovered oil. Talos holds a 35% participation interest with Sierra and Premier holding 40% and 25% participation interests, respectively.

The Zama-1 well is the first offshore exploration well drilled by the private sector in Mexico's history. The well, located in 546 feet (166 meters) of water and approximately 37 miles (60 kilometers) from the Port of Dos Bocas, has reached an initial shallow target vertical depth of approximately 11,100 feet (3,383 meters).

Preliminary analysis indicates:

  • A contiguous gross oil bearing interval of over 1,100 feet (335 meters), with 558-656 feet (170-200 meters) of net oil pay in Upper Miocene sandstones with no water contact
  • Initial gross original oil in place estimates for the Zama-1 well range from 1.4 to 2.0 billion barrels, exceeding pre-drill estimates, some of which could extend into a neighboring block
  • Initial tests of hydrocarbon samples recovered to the surface contain light oil, with API gravities between 28° and 30° and some associated gas

"This is both a historic and significant discovery, and we could not be more proud of the highly skilled personnel from Mexico and the US who have been working together in a safe and efficient manner to make it a reality," said Tim Duncan, President and Chief Executive Officer. "We believe this discovery represents exactly what the energy reforms intended to deliver: new capital, new participants and a spirit of ingenuity that leads to local jobs and government revenues for Mexico.We are eager to begin appraising this discovery and drilling more unique opportunities. The future is bright for offshore Mexico for years to come."

"This success is the culmination of a tremendous amount of work by our technical and operations teams in concert with our consortium partners Sierra and Premier," Duncan continued. "The team deserves a great deal of credit for their conviction in this opportunity and their leadership in making Talos the first private sector operator to receive acreage and drill a successful offshore exploration well in Mexico following the landmark energy reforms of 2014."

The well spud May 21, 2017 utilizing the Ensco 8503, a moored floating drilling rig. The Company is currently setting a liner to protect the discovered reservoirs prior to drilling deeper exploratory objectives to a total vertical depth of approximately 14,000 feet (4,267 meters). There are no plans for immediate well testing. Further evaluation will be required to calibrate the well with the existing reprocessed seismic to determine future plans and optimal follow up locations to define the extent of the discovered resource.

During 2015, the Company, together with its consortium partners Sierra and Premier (the "Consortium"), executed two production sharing contracts ("PSCs") with Mexico's upstream regulator, the National Hydrocarbons Commission, for Block 2 and Block 7. The PSCs were awarded to the Consortium during the first tender of Mexico's oil and natural gas fields in over 80 years. Block 2 and Block 7 are located in the

Sureste Basin, a prolific proven hydrocarbon province, in the shallow waters off the coast of Mexico's Veracruz and Tabasco states, respectively. Block 2 and Block 7 contain approximately 162,904 gross acres with numerous high impact prospects in well-established and emerging plays.


Talos is a technically driven independent exploration and production company focused on the exploration, development and acquisition of oil and natural gas properties primarily in the Gulf of Mexico Developed Deepwater and Shelf and on the Texas and Louisiana Gulf Coast, with year-end net proved reserves of over 100 million BOE and production of approximately 30,000 BOE/day net to the Company's interest. During 2015, we leveraged our technical and operational expertise in the Gulf of Mexico and expanded our acreage position into two shallow water exploration blocks off the coast of Mexico.

Otto Energy Farms into South Timbalier 224 Lease in Gulf of Mexico

Otto Energy Limited (ASX:OEL) (‘Otto’ or the ‘Company’) announces it has farmed into the South Timbalier 224 (‘ST 224’) lease in the Gulf Of Mexico shelf, for a 25% working interest. ST 224 contains a large, amplitude supported, high CGR, gas condensate exploration prospect located in the prolific Bul. 1 trend which is expected to be drilled in Q4 2017. The prospect is surrounded by analogue high CGR discoveries which present a similar amplitude expression on 3D seismic data making this a very attractive low risk exploration opportunity. Otto intends to release further information on the prospect, including prospect volumetrics, closer to the drilling date. A summary of lease working interests can be seen in the table below.

CompanyWorking Interest (%)
W&T Offshore (Operator) 39%
Otto 25%
Houston Energy 11%
Other Private US Company 25%

The prospect sits in approximately 170 feet of water and has a relatively shallow target depth. Several existing production platforms fall within tie-back distance of the proposed well, enhancing economics and making development of any discovered hydrocarbons both quick and cost effective. Additional follow up drilling potential exists on the lease.

2OttoEnergyOtto Energy Limited’s Interests in the Gulf of Mexico

Under the terms of the participation agreement, Otto will be required to fund 25% of the initial test well in the ST 224 lease (up to casing point) to earn a 25% working interest in the ST 224 lease. The financial commitment is currently estimated at US$2.7 MM (Otto share of dry hole costs), including funds to evaluate the well using wireline techniques and in a failure case to P&A the location. Otto will also pay US$81,250 in back costs.

There is no promote on the exploration well payable by Otto. Should a development proceed at ST 224, Houston Energy will be entitled to a backin after payout at the point where Otto recovers its share of all exploration and development expenditures from its share of net project revenues. Otto’s Working Interest would be reduced by 10% at this point in time from 25% down to 22.5%.

Otto’s Managing Director, Matthew Allen, commented: “We are excited to secure a 25% interest in the highly prospective ST 224 lease partnering with an experienced Gulf of Mexico operator in W&T Offshore and Houston Energy a very successful Gulf of Mexico prospect generator. This complements our existing SM 71 development in the Gulf of Mexico which is due to commence production in late 2017. The farm in structure with no promote on the initial test well, and a back in after payout only in the success case after all costs have been recovered minimizes up front entry costs. In the success case, pre-drill economics support a very robust development project at current oil price which W&T Offshore have indicated could have first production by end 2018. Otto hopes this is the start of a fruitful working relationship with these companies in the Gulf of Mexico.”



Location: Offshore Gulf of Mexico
Gross Area: 20.23 km2 (5000 acres)
Otto’s Initial Working Interest: 25%
Water Depth: 170 feet
Prospect Target Depth: 10,500 feet (TVD)

Through the drilling of an exploration well in ST 224, Otto will earn a 25% Working Interest (equal to a 19.5625% Net Revenue Interest) in the license in exchange for paying 25% of the initial test well costs to casing point, currently estimated at US$2.7 MM (Otto share) dry hole costs (including funds to evaluate the well using wireline techniques and in a failure case to P&A the location). In addition, Otto will be required to fund US$81,250 in back costs.

Houston Energy will be entitled to a back in after payout, when Otto recovers from its net revenues from ST 224, all development and exploration expenditures (including back costs) spent on ST 224.

Otto’s interests before and after payout can be seen in the table below.

 Before Payout After Payout 
  Working Net Revenue Working Net Revenue
  Interest Interest Interest Interest
Otto 25.0000% 19.5625% 22.5000% 17.60625%

BOEM Completes Analysis of Royalty Rates for Offshore Oil and Gas Leases

3BOEM logoBOEM announces that they have completed an analysis of their royalty rates and have decided to set the royalty rate at 12.5 percent for leases located in water depths less than 200 meters in the proposed Gulf of Mexico (GOM) Sale 249. This is lower than the proposed 18.75 percent royalty rate for shallow water leases that we published in the Proposed Notice of Sale, and is consistent with the Federal onshore oil and gas lease royalty rate of 12.5 percent. The purpose of this change is to adjust the royalty rate to reflect recent market conditions, thereby encouraging competition and continuing to receive a fair and equitable return on oil and gas resources. The royalty rate in 200 meters of water and deeper will remain at 18.75 percent as in the Proposed Notice of Sale.

BOEM has made this decision after careful consideration of market conditions, available resources, leasing, drilling, and production trends, along with comparable international fiscal systems. In particular, hydrocarbon price conditions and the marginal nature of remaining GOM shelf resources suggest a royalty rate reduction is an appropriate and timely action. The shallow water royalty rate reduction targets the GOM shelf where exploration, development, and production are in decline and where critical infrastructure already exists.

If BOEM moves forward with the sale, the royalty rates and other lease terms related to GOM Sale 249 will be formally announced in the Final Notice of Sale at least 30 days prior to the sale date. The sale date is currently scheduled for August 16, 2017. BOEM is sending this Note to Stakeholders informing you of this change ahead of the Final Notice of Sale because it was made after the Proposed Notice of Sale for GOM Sale 249 (published in March of this year).

GOM Sale 249 is the first scheduled lease sale in the 2017-2022 Outer Continental Shelf Oil and Gas Leasing Program, and is also the first scheduled Gulf of Mexico region-wide sale that encompasses all available acreage in the Western, Central, and Eastern planning areas. The unleased blocks are located between 3 nautical miles offshore out to the outer limit of the United States' jurisdiction over the Outer Continental Shelf (OCS) in water depths ranging from 3 meters to more than 3,400 meters.

BOEM also announces that they are analyzing a price-based royalty system and will be engaging stakeholders on this concept later this year. BOEM's concept of a price-based royalty system would provide an incentive to lessees through lower royalty rates in times of lower oil prices, while also ensuring the Federal government receives a greater return for Outer Continental Shelf resources when prices are high. A price-based royalty system will not be in place for GOM Sale 249. BOEM expects to provide more information and provide opportunity for stakeholder input in the coming months.

Snefrid Nord to be Developed by Statoil and Partners


Photo credit: Statoil

Statoil and partners have decided to develop the Snefrid Nord gas discovery near the Aasta Hansteen field in the Norwegian Sea. The discovery, scheduled to come on stream in late 2019, will be tied back to Aasta Hansteen.

The authorities therefore received a supplement to the Plan for Development and Operation (PDO) of the Aasta Hansteen field describing the Snefrid Nord development.

Aker Solutions, the supplier of subsea equipment for the Aasta Hansteen development, will also deliver the single-slot subsea template, a suction anchor and umbilicals for the Snefrid Nord development.

The subsea template and suction anchor mooring it to the seabed will be delivered by Aker Solutions at Sandnessjøen.

“We are pleased to see that Snefrid Nord generates spin-offs and activities at Helgelandskysten,” says Torolf Christensen, project director for Snefrid Nord and Aasta Hansten.

The umbilicals will be delivered by Aker Solutions in Moss.

Subsea 7 will deliver flowlines and spools in addition to performing all subsea installations. They are also the supplier for Aasta Hansteen, and by using the same supplier for both projects Statoil expects to capture synergies.

All contracts are subject to MPE (Ministry of Petroleum and Energy) approval of the supplement to the Aasta Hansteen PDO.

Snefrid Nord was discovered in 2015. Recoverable reserves are estimated at about five billion cubic metres of gas. The development concept includes one well in a single-slot subsea template. This will be tied back to the Aasta Hansteen platform through the Luva template six kilometers away. Snefrid Nord will produce some four million cubic meters of gas per day in the plateau phase, the planned productive life being 5-6 year.

The capital expenditures for the Snefrid Nord development total about NOK 1.2 billion. “Aasta Hansteen is a strategically important development as the platform and Polarled pipeline open a new area in the Norwegian Sea for gas exports to Europe. The projects also establish a new infrastructure, which will create opportunities for future field development projects in the area. Snefrid Nord is an excellent example of this,” says Siri Espedal Kindem, senior vice president for operations north in Statoil.


  • Statoil Petroleum ASA is operator with an interest of 51 percent. The partners are Wintershall Norge AS (24%) OMV Norge AS (15%) and ConocoPhillips Skandinavia AS (10%)
  • Water depth: 1 312 meters

Stena Drilling Extends Inspection Contract with Sparrows Group

5stena don1Sparrows Group has been awarded a three-and-a-half-year extension to its inspection services contract for Stena Drilling’s global fleet of drilling vessels.

The contract scope includes carrying out LOLER lifting gear surveys, potential dropped objects surveys, cargo carrying unit (CCU) and non-destructive testing (NDT) inspections as well as rig specific maintenance.

As well as an extension to the contract, the scope has also been expanded to cover Stena’s entire fleet of seven vessels, including the Stena Don in Norway.

Initially awarded until the end of 2017, the extension will see Sparrows deliver the inspection service provision until the end of 2020 and marks over 10 years of Sparrows holding the contract.

Stewart Mitchell, chief executive officer of Sparrows Group, said: “We have developed a strong relationship with Stena and we are pleased to continue it with the extension of the inspection services contract. The inclusion of the Stena Don is testament to the excellence of our inspection team and the level of service delivery they have achieved to date.

“Effective inspection and maintenance routines are essential to guarantee the safe and reliable operation of critical equipment and avoid unnecessary downtime. Our inspection team’s experience and reliability will ensure continuity and integrity across Stena’s global fleet.”

This is the latest in a string of contract wins for Sparrows having recently announced the refurbishment of two offshore cranes for Centrica’s Morecambe Bay fields and a three-year maintenance, lifting and rigging contract for the Ichthys LNG project in Australia.

Federal Offshore Well Permits Support Safe Energy and Economic Development

The operation of drilling an offshore oil and gas well provides for economic development and supports as many as 450 new jobs. As Energy Week concludes, the Bureau of Safety and Environmental Enforcement’s well permit approvals in 2017 total 69. Approval of a well permit paves the way for an offshore operator to begin the drilling activity and initiates a vast project supported by drilling crews and service and supply contractors.

6BSEE noble globetrotter 1 permit storyThe drillship Noble Globetrotter I has been used by Shell Offshore Inc. at several sites in the Gulf of Mexico, most recently at Alaminos Canyon 772, a lease block near it's Perdido Spar.

“I believe BSEE holds the potential to move the U.S. offshore energy program forward in both energy production and economic development, and done in a safe and environmentally-responsible manner,” BSEE Director Scott Angelle said today. “Overall, operators in the U.S. Outer Continental Shelf are producing more oil and gas than ever before and it all begins with drilling the well.”

BSEE engineers consider well design, capabilities of safety barriers such as the blowout preventer, environmental determinations and other components involved in drilling a well through the application review and analysis, all of these considerations are done to ensure that offshore operations are conducted according to both industry and regulatory safety and environmental standards.

To date, nine wells have been completed in 2017, and 33 wells are currently being drilled on the U.S. Outer Continental Shelf. The economic activity surrounding an offshore drilling project is extensive; it involves the contracting of the rig, the manufacturing of the drill pipe and casing strings, to suppling drilling mud, and the multitude of services required for a successful project.

Federal permits for offshore wells have been issued for more than six decades throughout the Gulf of Mexico, and in the Pacific and Arctic oceans. As America continues to move forward on its path to energy dominance, BSEE plays a vital role in ensuring safe and environmentally-responsible operations to secure reliable and efficient energy production for America’s future.

Veolia and Peterson Facility Receives the First Offshore Structure for Decommissioning

7 1Veolia PetersonVeolia and Peterson have accepted the first offshore structure into their Great Yarmouth decommissioning facility. The Shell Leman BH platform accommodation block, known as the ‘topside’, arrived into the harbor on 11th July and the 50m-high steel jacket structure that supported the topside is due to follow later in July. The topside, which was previously used as living quarters for personnel working on the Leman BT and Leman BK platforms, has now come to its new home to be recycled.

The contract was awarded to the partnership by Boskalis which are responsible for offshore removal and transport operations. With a target of achieving a 97% recycling and reuse rate, it covers the receipt and treatment of offshore assets and materials from 50km off the Norfolk coastline in the Southern North Sea.

7 2Veolia Peterson2The purpose built Great Yarmouth decommissioning facility will manage the deconstruction and recycling of both topsides and jacket structures that comprise around 1,600 tonnes of materials and assets. The Great Yarmouth facility is ideally placed to manage projects from the Southern and Central North Sea, supporting the local economy and supply chain. It has also provided employment opportunities through the creation of approximately 10 jobs, with further expansion and employment as the projects develop.

Estelle Brachlianoff, Senior Executive Vice President, Veolia UK and Ireland said: “These are valuable assets in our seas and by decommissioning these platforms we can unlock resources to give them a second, third or even fourth life. This latest project will continue to show how we can maximize the recycling of these platforms and drive sustainability in the industry. Our partnership has successfully delivered a number of projects over the last ten years, this latest one will further the growth of the business and local opportunities in Great Yarmouth.”

Peterson’s Regional Director Ron van der Laan added: “This project is a positive sign for Veolia - Peterson in Great Yarmouth, and follows the award of two contracts late last year. It will build on the successes achieved so far and represents a further step towards establishing Great Yarmouth as a center of excellence.”

Recovering offshore production platforms and facilities and decommissioning them in a responsible manner is routine business for operators as oil and gas fields reach the end of their productive life. Decommissioning is a step in the lifecycle of any oil and gas project. Making use of the assets helps increase the sustainability of the industry and by using the new facilities the valuable materials that they contain can be carefully extracted and reused or resold if they have further use elsewhere.

Set up to provide a full decommissioning service Veolia-Peterson services include decontamination, deconstruction, waste management and environmental services together with associated integrated logistics, marine and quayside services. To date the joint venture has recovered over 80,000 tonnes of offshore materials and achieved ‘excellent’ environmental assessment ratings in the process.

GE to Provide a Suite of Marine Technologies to One of the World’s Most-Advanced Deep-Water Diving Support Vessels

8GE DSVPurpose-designed for a range of roles including deep-water salvage operations, deep-water pipelay and construction as well as a saturation diving capability for up to 24 divers in two bells, Shanghai Salvage Bureau’s new ship is a testimonial to the demand for top-rated technology and equipment of the highest reliability.

Recently, GE’s Marine Solutions (NYSE: GE) has been chosen by Shanghai Salvage Bureau (SSB), one of the largest rescue and salvage companies in the world, to provide a suite of marine technologies including power and propulsion equipment, dynamic positioning (DP) and automation and control systems to its newest deep-water dive support vessel (DSV). The vessel will become the world’s first deep-water DSV with a multi-saturation diving system. Once delivered, it will enable diving operations to be performed at depths of up to 500 meters and salvage work at 6,000 meters.

“This vessel will be the best of its class anywhere in the world. The sophisticated electrical system, including an innovative closed-ring arrangement of the propulsion switchboard, is a top priority for us to achieve our design goals. Undoubtedly, reliability of the technology onboard the ship is of paramount importance, and that requires an experienced partner,” said Mr. Huang Yan, project director, SSB. “We are pleased to work with GE to ensure that the deep-water DSV will be one of the most advanced of its kind in the world.”

Particularly in the tough offshore environment and in challenging weather, keeping the vessel “on station” and enabling smooth deep-water operations makes the DP system a critical component.

The vessel will feature GE’s latest technology—SeaStream™ DP system (Class 3). Using multidirectional thrusters and sensors to monitor real-time wind, current and wave conditions and automatically activate the propulsion units to counteract the environmental forces, the technology will enable the ship’s position and orientation to be safely and efficiently controlled.

GE’s deep-domain expertise in DP has also extended its capability to include fuel usage optimization. GE’s Ecomagination™ energy-efficient mode uses advanced algorithms to optimize vessel heading and optimize the number of generators needed for operation, further reducing power consumption, operational costs and emissions.

In addition, the vessel will be powered by an electric power and propulsion system, including GE’s 4,656-kilowatt generators, switchboards and medium-voltage frequency drive propulsion controllers as well as a vessel automation and control system, all configured for optimum power and propulsion performance. The main propulsion switchboard will be arranged in a closed-ring configuration to get to maximum efficiency and availability.

The ability to provide the full spectrum of marine solutions—from power and propulsion to navigation and positioning and automation and control—within one integrated package is also a key reason why GE was chosen.

“Thanks to the GE Store, we are able to provide a suite of marine technologies through a blend of high competence in one integrated package,” said Tim Schweikert, president & CEO, GE’s Marine Solutions. “This is one of the landmark projects in the offshore marine industry, and we are excited to be part of the journey”

Ocean Installer Awarded Subsea Installation Contract from Statoil

9OceanInstaller NormandVisionThe award is part of Statoil’s Marine Wave 2 program and means that Ocean Installer will continue playing a key role in the Johan Sverdrup subsea works, initiated under the Marine Wave 1 umbrella. The complete work scope encompasses umbilical installation at Johan Sverdrup, Bauge and Utgard, as well as spools, cover, tie-in and manifold installation at Utgard.

“Ocean Installer is conducting widespread work for Statoil under the Marine Wave 1 program this year and we are truly pleased to have been selected as a key contractor also for the second phase of this Statoil scheme in 2019. We welcome this opportunity to continue to develop our good working relationship with Statoil,” says Ocean Installer CEO Steinar Riise.

Project management and engineering will be based at Ocean Installer’s headquarters in Stavanger and commence with immediate effect. Offshore operations will take place in 2019 and Ocean Installer will utilize a combination of the construction support vessels (CSV) Normand Vision and Normand Reach.

Ampelmann Introduces the A-type Enhanced Performance Motion Compensated Gangway

10Ampelmann A EPAmpelmann has announced the launch of its latest gangway for personnel transfer: the A-type Enhanced Performace (AEP). Now providing clients with 10% greater workability in sea states up to 4m significant wave height; the AEP also has the ability to use smaller vessels to obtain similar performance (compared to current A-type).

The AEP features an advanced motion compensation control system with precision controls to enable fast landing and comfortable people transfers. The system significantly improves operational up-time on projects year-round and provides benefits to operators in rougher waters, including the North Sea and the coasts of South America and the Middle East.

The AEP can also be used to ensure comparable workability on a relatively small vessel, where bigger vessels were needed before, saving cost for Ampelmann’s client by allowing flexibility in positioning on the vessel.

Statoil Completes Two-Well Exploration Drilling Campaign Offshore Newfoundland

Statoil, along with its partner, Husky Energy, has finalized a two-well exploration drilling program in the Flemish Pass Basin offshore Newfoundland.

Both wells were drilled safely and efficiently by the Seadrill West Aquarius in the Flemish Pass Basin, located approximately 500 kilometres east of St. John’s, Newfoundland and Labrador. The two wells, located within tie-back vicinity to Statoil’s 2013 Bay du Nord discovery, did not result in the discovery of hydrocarbons.

11Statoil NewfoundlandThe Seadrill West Aquarius drilling rig. (Photo: Seadrill)

“These results are disappointing, as we had hoped to add additional optionality to the near-field area at Bay du Nord,” said Trond Jacobsen, vice president, Exploration, Statoil Canada.

“We will now take the time needed to evaluate the results before firming up any plans for additional drilling near-field to Bay du Nord.”

The volume estimates for Bay du Nord, including the Bay de Verde and Baccalieu discoveries announced in 2016, remain an estimated 300 million barrels of recoverable oil, as previously announced after Statoil’s 2014-16 drilling campaign.

Statoil continues to evaluate future drilling activities in other areas where the company holds acreage in the frontier Flemish Pass Basin. The company’s assessment of the commercial potential of the Bay du Nord discovery is also ongoing.

“We continue to evaluate the feasibility of a development at Bay du Nord,” said Paul Fulton, president, Statoil Canada. “While these results mean a reduction in optionality for a potential project development, we continue to work on this project.”

Corvus Energy Continues to Lead the Industry and Electrify Offshore Oil & Gas Platform Supply Vessels with Latest Project Win

Corvus Energy announces that it has been selected as the supplier of a lithium ion based energy storage system (ESS) for the hybridization of Farstad Shipping’s PSV Far Sun being integrated by Vard Electro, in the second half of 2017. The Orca Energy ESS from Corvus will supply electrical power to the PSV’s propulsion system electrical network to enable environmentally-friendly and lower cost operations.

12Corvus Vard Far Sub PSVFarstad Shipping’s Platform Supply Vessel (PSV) Far Sun

The energy storage system will be utilized during all aspects of the PSV’s operation, particularly during dynamic positioning and harbour operations where fuel consumption and emissions will be significantly reduced. Equally important to Farstad and Statoil (who maintains a long-term charter for the PSV), the ESS will increase safety through provision of spinning reserve for improved response time as well as increased redundancy.

“As we have experienced with many vessel types, the Orca ESS is ideally suited for the hybridization of the Far Sun PSV”, says Ronald Hansen, Global Service Manager of Corvus Energy. “Through close collaboration with Vard, our teams have developed a lean solution which meets the aggressive environmental, safety, performance and operating cost objectives of Farstad and Statoil.”

Statoil, an important client of Farstad Shipping, is focused on improved safety, efficient operations and reduced environmental impact. Through a long-term contractual relationship and a strong emphasis on reducing emissions, Statoil has been a key element in the efforts to have battery technology installed on board Far Sun.

“The energy storage system will provide significant savings for Farstad and Statoil over time, enabling the ship to more efficiently utilize energy produced by the generators, as well as simplifying the use of shore power. This will substantially reduce consumption and emissions. Another effect is less noise from ships in port”, says Christian Søvik, VP Global Services of Vard Electro.

As the leading manufacturer of energy storage systems for maritime applications, Corvus continues to lead the industry with 80+ installations utilizing a Corvus ESS, totaling over 45MWh and 1 million operating hours.

Damen Finalizes Keppel Verolme Takeover

13Damen Contract signing lowres 1Damen Shiprepair & Conversion (DSC), a part of Damen Shipyards Group, has announced the acquisition of the Keppel Verolme shipyard from Keppel Offshore & Marine.

DSC’s acquisition of the yard follows an initial agreement made between the two parties in April of this year. From 1 July, the Keppel Verolme shipyard, including its 250 staff members, will continue operations under the Damen flag.

“We look forward to joining forces with the Verolme yard and its people. The facilities and personnel are complementary to our existing organisation. This acquisition will enable us to serve our existing clients even better while opening up new opportunities,” says Durk-Jan Nederlof, Managing Director of Damen Shiprepair & Conversion.

With three dry docks – the largest of which measures 405 x 90 metres – and almost 2km of quay capacity, the Verolme yard, located in Rotterdam’s Botlek harbour, will significantly expand DSC’s portfolio. DSC already operates eight repair and conversion yards in the Netherlands and another eight abroad.

Market Study Reveals Huge Potential for LNG as a Marine Fuel in the Iberian Peninsula

14CORE LNGas Hive credit IneaWith the global fuel sulphur limit of 0.5% entering into force in 2020, the interest towards LNG as a marine fuel is increasing. One of the main obstacles to the accelerated uptake of LNG, however, is the uncertainty regarding future market volumes for LNG. DNV GL has addressed this issue in a recent market study on the future LNG market in the Iberian Peninsula, as part of driving the development of an EU-wide network of LNG refueling points.

DNV GL conducted the market study on behalf of the six-year CORE LNGas hive project1, which aims to provide an investment plan for LNG fueling in Spain and Portugal. The 33 million Euro project is coordinated by Enagas, and co-funded by the European Commission.

The DNV GL market study has forecasted the potential future demand for LNG as a ship fuel and the required future infrastructure for the areas around Spain and Portugal, covering the Mediterranean, Atlantic and Gibraltar Strait peripherical regions. The results of DNV GL’s analyses have now contributed to the CORE LNGas Hive project’s recommendations for the development of the LNG supply chain infrastructure, involving over 40 ports in the project area.

Fernando Impuesto, CORE LNGas hive project coordinator from Enagas, says: “The consortium partners selected DNV GL to execute the demand studies of the project based on the fact that DNV GL has been at the forefront of the development of LNG as a ship fuel. DNV GL’s network and market knowledge have added to a successful outcome. Through this market study we now have a strong decision basis to prepare the supply side on the Iberian Peninsula in meeting future demand for LNG bunkering at competitive conditions.”

Despite LNG fueled shipping being high on the agenda in the maritime industry, the market drivers are seen to change. From previously being encouraged by a lower price of LNG compensating for the added cost for installation of the LNG fuel equipment, results from interviews conducted by DNV GL indicate a shift towards compliance with emissions regulations to be the main motivation.

The study has revealed a huge potential for LNG as a marine fuel that will utilize the current spare capacity of the existing LNG import terminals. The consolidated quantitative results show that by 2030 up to 2 million m³/y of LNG is to be bunkered by ships (with Algeciras, Las Palmas and Barcelona as most important ports) and by 2050 approximately 8 million m³/y of LNG.

On the logistical side, the market study further concludes that existing LNG terminals will need to develop break bulk capacity to allow for loading LNG to small carriers and LNG bunker vessels. In most ports, development of local intermediate storage capacity needs to be synchronized with increasing LNG demand by larger vessels. Besides bunker stations and local storage facilities, small carriers for delivering batches of LNG to ports over sea will play an important role for the times ahead.

However, in order to realize the predicted LNG supply chain in 2030, about 1 billion Euro of capital expenditures (CAPEX) investment will be needed, adding up to a total cost of 3,7 billion Euro in 2050.

Liv Hovem, Senior Vice President, DNV GL – Oil & Gas, adds: “DNV GL’s market study has clearly shown the major potential LNG has as a fuel in the region. We hope that the conclusions from our study will help ship owners, natural gas suppliers, bunker companies, port authorities and LNG terminal operators gain the confidence they need to move forward with LNG as a fuel for a more sustainable shipping industry.”

1. The six-year CORE LNGas hive project is co-funded by the European Commission and is scheduled for completion by December 2020. The CORE LNGas Hive project is to provide recommendations to the National Policy Framework (NPF) with regard to the demand for LNG as a maritime fuel in Spain and Portugal on the deployment of alternative fuels infrastructure. It also aims to provide an investment plan for scaling associated project results. See website here

BP 2Q 2017 Exploration Highlights

  • Discoveries in Egypt and Trinidad underpin major existing businesses
  • Actively managing exploration portfolio and exiting non-competitive assets, expects around $750 million non-cash exploration write-off in Angola
  • Exploration success in Senegal confirms new world-class basin
  • 2017 access in Senegal, UK, US, Canada and Mexico

15bp logo copy 2BP says that it continues to make progress in shifting its exploration portfolio toward natural gas and advantaged oil.

As first described to the financial community in 2016, BP is actively reviewing its exploration activities and refocusing them on growth in natural gas and advantaged oil in regions where BP currently operates. It is also selectively looking for opportunities to grow new material production regions while exiting less competitive exploration prospects.

Bernard Looney, BP’s Upstream chief executive commented: “We are making disciplined choices throughout our business, including in exploration, and pursuing only opportunities that will deliver clear value for our shareholders. Equally important to this disciplined, value-over-volume strategy, we are choosing not to pursue activities that we don’t think will deliver maximum value for our shareholders.”

Portfolio review

As part of the ongoing portfolio evaluation, BP has decided to relinquish its 50% interest in Block 24/11 offshore southern Angola. Katambi, a gas discovery made in the block in 2014, has not been determined to be commercial. As a result of this and other exploration write-offs in Angola, BP expects to include in its second quarter 2017 results a non-cash exploration write-off in Angola of around $750 million, which will not attract tax relief. This will not impact cash flow as part of re-balancing BP.

In October 2016 BP announced that it would not continue frontier exploration in the four blocks it operated in the Great Australian Bight, offshore southern Australia. BP and partner Statoil have now signed a swap agreement where Statoil has taken full ownership and operatorship of two of the blocks. BP is proceeding to discuss with the Australian government exiting its blocks. This is not anticipated to impact second quarter 2017 results.

BP continues to thoroughly review its existing portfolio of exploration assets, moving forward with the most attractive and exiting those that do not compete.


BP has announced four gas discoveries so far in 2017.

The Savannah and Macadamia gas discoveries in Trinidad, announced earlier in June, together are expected to unlock around 2 trillion cubic feet of gas in place and to support further development in BP’s long-standing business in Trinidad. The Qattameya discovery in Egypt, announced in March, was the third gas discovery on the North Damietta Offshore concession, where BP is already developing the Atoll field.

Following the completion of its entry into Senegal, in May BP and partner Kosmos Energy announced a major gas discovery with the Yakaar-1 exploration well, which further confirms offshore Mauritania and Senegal as a world class hydrocarbon basin. The partners plan a drill stem test at the Tortue Field and a further three exploration wells over the next 12 months.


BP has also continued to seek and access attractive new exploration acreage and opportunities globally. Building on incumbent positions, BP has been awarded new licenses in the US Gulf of Mexico and in the UK North Sea. The 25 blocks awarded as a result of the UK’s 29th Offshore Licensing Round represent the largest acreage award for BP in the North Sea since the late 1990s.

In support of selectively looking for new material production regions, earlier in 2017 BP was awarded exploration licenses in Newfoundland, off the east coast of Canada, and in Mexico. Further to the deal announced between BP and Kosmos Energy in December 2016, BP deepened its position in Senegal agreeing to purchase a further 30% interest in two offshore blocks.

Howard Leach, BP’s head of exploration commented: “This combination of new discoveries and new access has given BP a strong, resilient and more diversified exploration portfolio that lays the foundation for future growth in some of the world’s most exciting hydrocarbon basins.”

Ashtead Strengthens Aberdeen NDT Team

16Ashtead Scott StephenSubsea equipment specialist Ashtead Technology has announced the appointment of Scott Stephen (photo) as its new Non-Destructive Testing (NDT) sales manager.

Based at the company’s headquarters in Aberdeen, Scott will be responsible for business development and general sales and rental of NDT equipment and accessories, including phased array, ultrasonic flaw detection, corrosion mapping, eddy current flaw detection, hardness testing, composite inspection and thickness management.

Scott joins Ashtead from RSL NDT where he held the role of UK manager and was previously with Euro NDT as general manager, both based in Aberdeen.

The move comes as the independent firm, which has facilities in Aberdeen, London, Abu Dhabi, Houston and Singapore, recently gained certification from the United Kingdom Accreditation Service (UKAS) for the calibration of NDT equipment and has expanded its NDT equipment rental fleet.

Allan Pirie, chief executive of Ashtead Technology, said: “At the beginning of 2017 we mapped out growth plans for our NDT department and Scott is very much part of that strategy. We’re delighted to welcome him into the team and look forward to pushing forward with our plans, particularly having also recently secured further UKAS accreditation.

“We continue to strengthen our team and our collaborative network of suppliers in order to offer the most reliable, innovative and cost effective equipment solutions to our customers.”

Having previously gained UKAS accreditation for the calibration of survey, positioning and oceanographic sensors, this most recent approval also covers the delivery of calibration services for ultrasonic testing equipment used by NDT inspection companies.

PIRA Energy Market Recap for the Week Ending July 10, 2017

17PIRALogoRig Count to Slow Further as Brent Falls Below $50/Bbl

Crude prices fell again in June, with Dated Brent dropping below $50/Bbl. With weaker prices in recent months, the growth in working rigs in the U.S. has slowed, and will likely slow further and level off in the second half of the year. Western Canadian production is slowly returning to normal following the March Syncrude fire, and U.S. Midcontinent production has now turned positive on a year-on-year basis. Cushing crude stocks declined 4 million barrels in June, and 10 million barrels in the second quarter – part of a 35 million barrel U.S. crude stock draw. Further stock draws are expected in the third quarter, although stocks will likely rebuild in Western Canada. Stocks will also climb in West Texas, in advance of a year-end surge in pipeline capacity, as Permian Basin production increases rapidly.

Inventories Drop the Week Ending June 30

U.S. ethanol inventories declined for the third consecutive week, falling by 267 thousand barrels to 21.6 million barrels, the lowest since January. Domestic ethanol production was relatively flat, dropping 1 MB/D to 1,014 MB/D. Ethanol-blended gasoline production fell to 9,387 MB/D from a record 9,529 MB/D during the preceding week. Brazil shipped 20 MB/D (24.6 million gallons) of ethanol to the U.S. in June. August ethanol futures fell 1.1¢ to $1.505 per gallon today as of 11:48 A.M. CT, following corn prices lower.

EIA Reports Little Growth in April; Subsequent Flows Tell Different Story

Following the long holiday weekend, the prompt NYMEX contract fell to a new seasonal low, ~$2.83/MMBTU, as weather and production gains negatively colored sentiment. With limited heat on the horizon in key regions, the window for sustained weather induced tightness is fast approaching. Moreover, production over the weekend reached YTD highs, fueling concerns over loosening balances. Until recently, supply gains have been slow in the making; the recently published EIA Monthly Crude Oil and Natural Gas Production (914) report — updated through April 2017 — affirmed an anemic pace of sequential supply growth in March and April. However, the lackluster EIA/state production numbers mask the substantially increased drilling activity that has occurred, and that even with fracking/completion delays, producers are in a good position to accelerate volumes in 2H17. Increasing signs of production recovery have already occurred, with flow data indicating substantial gains in Appalachia in recent weeks.

Big Week Ahead

If you’re on a July holiday, warm and dry are words you hope to hear from your meteorologist. Not so much if you’re a farmer waiting for your corn to pollinate west of the Mississippi River. The weather forecasts this week are critical for the market because for those who forecast pollination dates strictly off the NASS emergence data, the first “major” state to get past 50% pollination will be Illinois this Wednesday the 12th, followed by a vast majority of the other “majors” between the 18th and the 22nd.

U.S. Huge Stock Declines as Demand Performs

Commercial oil inventories declined 13.4 million barrels last week, the largest of the year, as reported product demand soared to 22.2 MMB/D, a new record. The largest individual product draw was not surprisingly in gasoline (3.7 million barrels), reflecting the July 4th holiday driving. Crude inventories declined 6.3 million barrels as runs increased and imports decreased. Cushing crude stocks fell 1.3 million barrels. Crude stocks are expected to continue to decline next week. Gasoline demand strength to continue to pull gasoline stocks lower. Middle distillate stocks modestly build next week, as demand eases during the holiday week.

U.S. Job Growth Is Solid; Central Bank Balance Sheet Issues Are Center Stage

The takeaways from the labor data release were straightforward: an underlying pace of U.S. economic growth remains constructive, based on solid job gains; and the tightness in the labor market is yet to generate substantial wage pressure. In the comings months, the Fed and the European Central Bank are expected to announce changes to balance sheet policy. Policy shifts are not necessarily negative developments for the outlook – after all, central banks are considering actions because of an encouraging growth backdrop; furthermore, changes to balance sheets will only occur gradually. But there are uncertainties about when and how the changes will be carried out, and it appears to be affecting the market’s mood.

Ukraine is Tightening Central European Balances – Making Russia Ever More Key

This summer has been characterized by very high pipeline flows from the two big stalwarts of European gas supply – Russia and Norway. Norwegian deliveries are up by 42-mmcm/d or 15.8% versus normal and Russia flows are up by 22% or 67-mmcm/d vs normal. These two pipeline sources far outweigh the 22-mmcm/d increase in LNG imports versus the last 5 years. These high flows are evidence of the continued price competitiveness of contract pricing that has aligned itself quite well with hub pricing. Then again, the high demand needs from storage this summer in some ways assures cost competitiveness on the part of contracts because it becomes an easy arbitrage for supply contract holders – ramp down on contracts and up on hub gas.

Korea Continues Gas Charge with Short and Long Term Implications for LNG

Taking on a telenova-like aspect, Korea is rapidly advancing a series of new measures designed to enhance the role of natural gas in the power generation fuel mix, which to date is dominated by coal and nuclear. In so doing, the trade relationship between Korea, as the world’s second largest importer of LNG, and the U.S., on target to be the world’s third largest exporter of LNG by the end of the decade, is on track to become that much stronger, benefiting both U.S. export prospects as well as LNG trade prospects in general .

French Climate Plan: Very Ambitious Targets, Very Little Details

While lacking key details and leaving many questions unanswered, the “Climate Plan” unveiled by the French energy minister this week nevertheless provides some additional clues to the government’s energy policy, with the French curve extending the gains seen at least since mid-May.

Japan Runs Rising Back Up

Japanese runs rose 136 MB/D on the week, as turnarounds continue to lessen. Crude imports rebounded to 3.77 MMB/D from extremely low levels and crude stocks built 5.6 million barrels from record lows. Finished product stocks fell modestly, with a good draw on naphtha, a lesser draw on fuel oil and gasoline, which were mostly offset by a rise in middle distillates. Aggregate demand fell 99 MB/D, but the 4-week average trend in demand has begun to move seasonally higher. Refining margins were higher on the week and have continued to improve.

Stresses Low, but Debt Pricing Shows Movement

In general, financial stresses remain fairly low. The S&P 500 and volatility (VIX) were little changed, but debt pricing took center stage. There was a noted pickup in yield, with lower pricing, on emerging market debt (EMB) and high yield debt (HYG). The deflationary trade, we had been seeing, appeared to reverse a bit. Commodities had negative week, particularly energy and precious metals.

Short Covering and Strong Demand Cause Coal Pricing Surge

Coal prices moved considerably higher this week, with FOB Richards Bay prices rising by the greatest extent. For 3Q17, FOB Richards Bay prices surged by over $7.00/mt W/W, while CIF ARA and FOB Newcastle prices increased by $5.00/mt and $4.40/mt, respectively. Short covering, the disruption in coal traffic to Richards Bay Coal Terminal, and the loss of hydro generation in China all contributed to the rise in prices this week. These factors built on the prevailing tightness that has been present in the market over the past several months, stemming from supply disruptions in Australia and Indonesia.

EPA Proposes Little Change in Biofuels Requirements for 2018

The EPA issued its proposed renewable fuel standards for 2018 and bio-mass diesel for 2019 on July 5. The Agency proposed requirements similar to this year’s mandates, which are substantially lower than originally set forth in the Renewable Standard (RFS2). The total requirement proposed for 2018 was 19.24 billion gallons including 4.24 billion gallons. The implication is that the proposed mandate for conventional biofuels, largely grain-based ethanol was 15 billion gallons.

Global Equities Show Little Change on the Week

There was very little change in the global aggregate performance. The U.S. market was little changed, but banking posted a good gain, while retail and energy performed the poorest. Internationally, only Latin America was able to outperform and post a modest gain.

Aramco Pricing Adjustments: No Reversal of Strategy

Saudi Arabia's formula prices for August were released. Last month, PIRA indicated that the pricing adjustments clearly discouraged liftings, while pricing for August barrels is not reversing that stance to any significant degree. Cuts were made for Asia, but they were basically in line with market expectations. European pricing was raised in line with a narrower discount on Urals. U.S. pricing was left unchanged on all but Arab Extra Light, after having been raised significantly for July barrels and reflected a clear willingness to let liftings fall. Pricing for September barrels will be closely watched for signals of a greater willingness to push barrels into the market or let the market work through what is typically a shoulder month, before rising 4Q demand establishes a firmer floor.

Saudi Arabia: Financial Drain of FX Reserves Lessens in May

Saudi’s foreign exchange reserves for May were released and indicate a much reduced draw for May. May reserves fell only $1.23 billion USD, with the 3-month drain rate easing to only $5.02 billion USD, the slowest call on FX reserves since May 2016.

The information above is part of PIRA Energy Group's weekly Energy Market Recap - which alerts readers to PIRA’s current analysis of energy markets around the world as well as the key economic and political factors driving those markets.

President Trump and Secretary Zinke Open Up Comment Period for New 5-Year National Offshore Oil and Gas Leasing Program

1BOEM Oil Platform Silhouette with sun set 257x343At an Energy Week event hosted by Energy Secretary Rick Perry, President Donald J. Trump announced that Secretary of the Interior Ryan Zinke has taken action to open up the public comment period for a new 5-year National Offshore Oil and Gas Leasing Program on the Outer Continental Shelf (OCS). President Trump announced on stage that the comment period is the first step in executing the new 5-year plan which was put in action by the April 28 executive order on American Energy. The 2017-2022 Five Year Program, which is set to begin this summer, will continue to be executed until the new National OCS Program is complete.

Monday's publication of the RFI begins a 45-day public comment period. Substantial public involvement and extensive analysis will accompany all stages of the planning process, which generally takes two to three years to complete. The notice will be on display in the Federal Register public reading room Friday, June 30, 2017, and published in the Federal Register Monday, July 3. Comments will be accepted until 45 days after the publication date which will be July 3.

“Developing a new National Offshore Oil and Gas Leasing Program that respects environmental and economic sensitivities but still allows us to responsibly develop our resources is critical to reaching President Trump’s goal of American energy dominance,” said Secretary Zinke. “Offering more areas for energy exploration and responsible development was a cornerstone of the President’s campaign and this action is the first step in making good on that promise for offshore oil and gas.”

“Under the last administration, 94% of the OCS was off-limits to responsible development, despite interest from state and local governments and industry leaders. The Trump Administration is dedicated to energy dominance, growing the economy and giving the public a say in how our natural resources are used, and that’s exactly what we are doing by opening up the Request For Information and a new 5-year plan,” said Acting Assistant Secretary Kate MacGregor.

The Secretary's Order calls for enhancing opportunities for energy exploration, leasing, and development of the OCS, establishing regulatory certainty for OCS activities, and enhancing conservation stewardship, thereby providing jobs, energy security, and revenue for the American people.

“Our country has a massive energy economy and we should absolutely wear it on our sleeves, rather than keep energy resources in the ground,” said Vincent DeVito, Counselor to the Secretary of Interior for Energy Policy. “This work will encourage responsible energy exploration and production, in order to advance the United States' position as a global energy force and foster security for the benefit of the American citizenry."

Publication in the Federal Register of a Request for Information and Comments (RFI) on the Preparation of the 2019-2024 Outer Continental Shelf (OCS) Oil and Gas Leasing Program is the initial step. Per statute and consistent with previous efforts, BOEM will evaluate all 26 of the OCS planning areas during this first stage and is, therefore, requesting comments on all areas.

The initiation of a new National OCS Program development process, managed by the Bureau of Ocean Energy Management (BOEM), is a key aspect of the implementation of President Donald Trump’s America First Offshore Energy Strategy, as outlined in the President’s Executive Order (E.O.) 13795 on April 28, 2017, which was amplified by Secretary Zinke’s DOI Order 3350 on May 1, 2017.

The Outer Continental Shelf Lands Act requires the Secretary of the Interior, through BOEM, to prepare and maintain a schedule of proposed oil and gas lease sales in federal waters, indicating the size, timing, and location of auctions that would best meet national energy needs for the five-year period following its approval. In developing the National OCS Program, which has also been known as a Five Year Program, the Secretary is required to achieve an appropriate balance among the potential for environmental impacts, for discovery of oil and gas, and for adverse effects on the coastal zone. As required by the President’s Executive Order, DOI will cooperate with the Departments of Defense and Commerce on issues pertaining to this National OCS Program development process.

“This first step does not propose to schedule sales in particular areas, or make any preliminary decisions on what areas will be included in the schedule,” said BOEM Acting Director Walter Cruickshank. “The RFI considers all areas of the Outer Continental Shelf and provides an opportunity for interested parties to submit comments and suggestions about the potential for leasing and to identify environmental and other concerns and uses that may be affected by offshore leasing.”

BOEM seeks a wide array of input, including information on the economic, social, and environmental values of all OCS resources, as well as the potential impact of oil and gas exploration and development on other resource values of the OCS and the marine, coastal, and human environments.

Using the information received, BOEM will prepare a Draft Proposed Program, followed by a Proposed Program and a Proposed Final Program. Throughout the planning process, BOEM will consult with all interested parties and will seek additional public comment.

The current National OCS Program for 2017–2022 schedules 11 potential lease sales; 10 in the Gulf of Mexico and one in the Cook Inlet of Alaska.

BOEM currently manages more than 3,000 active OCS leases, covering more than 16 million acres – the vast majority in the Gulf of Mexico. Of those, approximately 885 are producing leases, covering 4.4 million acres. In 2016, OCS oil and gas leases accounted for about 18 percent of domestic oil production and 4 percent of domestic natural gas production. This production generates billions of dollars in revenue for state and local governments and the U.S. taxpayer, while supporting hundreds of thousands of jobs.

Under the RFI announced, comments will be accepted until August 17, 2017, in either of the following ways:

Electronically (preferred method): BOEM Public Engagement Opportunities the "Open Comment Document" link and follow instructions to view relevant documents and submit comments.

In written form, deliver to: Ms. Kelly Hammerle, National Program Manager, Bureau of Ocean Energy Management; 45600 Woodland Road-VAM-LD; Sterling, Virginia 20166.

Additional information on the process of developing the next National OCS Program as well as on the current National OCS Program can be found here.

Saipem Awarded $500 Million in New Contracts

2Saipem fpso gimboa sitoSaipem has been awarded a new E&C Offshore contract by Saudi Aramco for EPCI (Engineering, Procurement, Construction, Installation) activities and T&I (Trunklines & Installation) works in Saudi Arabia, under the Long-Term Agreement in force, renewed in 2015 until 2021.

Saipem's FPSO Gimboa

The scope of work includes the design, engineering, procurement, construction and installation of a total of 19 jackets for the development of fields in Marjan, Zuluf, Berri, Hasbah, and Safaniya, among the most important offshore fields in the region of the Arabian Gulf.

Stefano Cao, Saipem CEO, commented: “With this award, Saipem is further reinforcing its presence a highly strategic area such as the Middle East. The new contracts assigned by a long-standing customer like Saudi Aramco are also a strong and tangible sign of a major client’s trust in Saipem, in the high quality of its services and in the solid expertise the Company can ensure in the construction and installation of offshore platforms”.

Additionally, Saipem has negotiated the extension in Angola of the deployment of vessel FPSO Gimboa, inclusive of management and maintenance services, personnel, material and consumable supplies for 3 years, plus one optional year.

Finally, Saipem has defined change orders for projects in West Africa and in the Caspian Sea.

Together, these new acquisitions, relevant to the second quarter, amount to a total of $500 million.

Kick-Off for Statoil’s UK Exploration Campaign

Statoil will soon commence a three-well exploration drilling campaign on the UK continental shelf. In early July, the Transocean Spitsbergen semi-submersible rig will spud the first well in the campaign.

3Statoil Transocean SpitsbergeThe Transocean Spitsbergen drilling rig. (Photo: Kenneth Engelsvold)

“This is an exciting campaign testing three very different opportunities on the UKCS. We hope to make discoveries that can add value to existing projects and also provide the resources necessary for new developments on the UKCS,” says Jenny Morris, vice president Exploration, UK.

The wells will be drilled in a continuous campaign that is expected to last approximately 2-3 months. The first well, Mariner Segment 9, could prove additional resources and increase the extent of the Mariner Field.

After completing the well, expected to take between 15 and 25 days, the rig will move to Jock Scott, a prospect on the underexplored margins of the Viking Graben. The well is expected to be completed in 20-40 days.

The last well of the campaign will be the Verbier opportunity in the Moray Firth area. The well is assumed to take 30-70 days to complete.

“We have three exciting wells to test with a proven and efficient rig that will enable us to continue to develop our understanding of the full exploration potential of this mature basin and hopefully add new commercial reserves to our UK portfolio,” says Morris.


Segment 9 partners: Statoil 65.1111%, JX Nippon 20%, Siccar Point Energy 8.889%, Dyas 6%
Jock Scott partners: Statoil 75%, BP Exploration Operating Company 25%
Verbier partners: Statoil 70%, Jersey Oil and Gas 18% and CIECO Exploration and Production (UK) 12%