Oil & Gas

ExxonMobil Acquires Interest in Acreage Offshore Suriname

2Exxon guiana basin

Image credit: Staatsolie

Exxon Mobil Corporation (NYSE:XOM) announces that its subsidiary ExxonMobil Exploration and Production Suriname B.V., along with co-venturers Hess and Statoil, signed a production sharing contract for Block 59 with Staatsolie Maatschappij Suriname N.V., the national oil company of Suriname. The block adds significant acreage to ExxonMobil’s operated portfolio in the Guyana-Suriname Basin.

Deepwater Block 59 is in water depths ranging from nearly 2,000 meters to 3,600 meters, located approximately 190 miles (305 kilometers) offshore Suriname’s capital city, Paramaribo. The block is 2.8 million acres, or 4,430 square miles, and shares a maritime border with Guyana, where ExxonMobil is the operator of three offshore blocks, including the world-class Liza field discovered by ExxonMobil in 2015.

“We look forward to working with Staatsolie and our co-venturers to evaluate the potential of this new acreage,” said Steve Greenlee, president of ExxonMobil Exploration Company. “Adding this block enhances our leading global deepwater portfolio.”

Suriname represents a new country for ExxonMobil’s upstream business. The company has investments throughout South America. Following contract signing, the co-venturers are preparing to begin exploration activities, including acquisition and analysis of seismic data.

ExxonMobil and consortium partners Hess and Statoil each hold a third of the interest in the block. ExxonMobil is the operator.

Statoil and Partners Make Small Gas Discovery in the Barents Sea

Statoil and partners ENI and Petoro have made a small gas discovery in the Blåmann well, between the Snøhvit and Goliat fields in the Barents Sea. Recoverable volumes are estimated at 2-3 billion standard cubic meters (BCM), approximately 10-20 million barrels of oil equivalent (BOE).

7BarentsSeaImage credit: Statoil

The well was drilled in license PL 849, awarded in 2016 in Norway’s Awards in Predefined Areas (APA) licensing round. Gas was found in a 23 meter column in the Stø formation. No oil volumes were encountered.

“We were exploring for oil and this is not the result we were hoping for,” says Jez Averty, senior vice president for exploration in Norway and the UK.

“However, this gas discovery has the potential to contribute additional resources to the Snøhvit project,” he notes.

The discovery is located in the Hammerfest basin, approximately 21 kilometers southeast of the Snøhvit field.

This is the second discovery in Statoil’s 2017 Barents Sea exploration campaign, following the Kayak oil discovery announced on 3 July.

The well was drilled by the “Songa Enabler” semisubmersible drilling rig, which will now move on to the Hoop area to drill the Gemini North prospect in license PL855, northeast of the Wisting discovery.

Licensees Blåmann (PL849): Statoil (operator) 50%, ENI 30% and Petoro 20%
Licensees Gemini North (PL855): Statoil (operator) 55%, OMV 25% and Petoro 20%

Statoil Secures Drillship for Exploration Drilling in Brazil

Statoil Brasil Oleo e Gas Ltda has awarded Seadrill rig contracts for exploration drilling in the BM-S-8 license in the Santos basin.

The agreement includes two contracts: Seadrill Offshore AS will provide the drillship West Saturn and Seadrill Serviços de Petroleo Limitada will provide services on board. The fixed contract scope includes one exploration well and one drill stem test, which are part of the license commitments of the exploration phase. The BM-S-8 license contains parts of the Carcará pre-salt oil discovery.

9StatoilWestSaturnThe West Saturn drillship. (Photo: Seadrill)

The West Saturn is a 6th generation ultra-deepwater drillship, built in 2014 and equipped to drill in water depths of up to 12,000 feet (3600 meters). Commencement date for the contracts is planned between 1 December 2017 and 1 March 2018. Under the contract, Statoil intends to drill the independent Guanxuma prospect.

“Clearly it is not a given that we find what we hope for, but if we are successful Guanxuma could be another significant discovery in this highly prolific basin,” said vice president for exploration in Brazil, Ana Serrano Onate.

Following the Guanxuma well, Statoil plans to perform a drill stem test on the Carcará discovery.

“Testing the Carcará discovery will provide important information for developing the field. In addition, Statoil is evaluating its options for the Northern open area licensing round, expected in October 2017. We believe Statoil is well-positioned for future operatorship of a unitized Carcará field,” said Anders Opedal, country manager for Brazil.

In addition to the firm program, the contracts include options for seven more exploration wells. Statoil can exercise these options based on the results of the firm exploration program and may deploy the West Saturn across its Brazilian assets, given regulatory approval. “Securing this optional rig capacity demonstrates Statoil’s commitment to follow-up on potential exploration success in the 2017-2018 program,” Opedal added.

On 12 July, Statoil announced an agreement that will increase the company’s interest in the BM-S-8 license from 66% to 76%.

Statoil has been present in Brazil for over 15 years and built a robust portfolio, including the Peregrino field in Campos basin and assets in the exploration and development phase. In this period, the company has invested more than 10 billion USD, paid almost 1 billion USD of government take and employed more than 1.000 people either directly or indirectly.

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.

ABOUT TALOS ENERGY LLC

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.”

SCHEDULE 1 – BACKGROUND ON ST 224 PROSPECT FARM IN

LOUISIANA/GULF OF MEXICO – SOUTH TIMBALIER 224

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%

Snefrid Nord to be Developed by Statoil and Partners

4StatoilSnefridNord

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.

FACTS

  • 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

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.”

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

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.

FACTS

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%

Statoil and Partners ENI and Petoro Make Oil Discovery in the Kayak Well in the Barents Sea

Totaling between 25 and 50 million barrels of recoverable oil equivalents, the discovery may provide valuable additional volumes for the Johan Castberg development. The discovery also opens other exploration opportunities in the same area.

6Statoil KayakImage credit: Statoil

The Kayak well has for the first-time proven resources in this type of play in the Barents Sea.

“We are very pleased to have made a good discovery in our first completed well in the Barents Sea this year. We are particularly pleased to have proven resources in a type of play that has not been explored before. This opens interesting opportunities,” says Jez Averty, senior vice president for exploration, Norway and the UK.

“Efforts will be made to find a commercial solution for the Kayak discovery towards the Johan Castberg license, and to bring out other similar prospects in the Barents Sea,” Averty adds.

Totaling between 25 and 50 million barrels of recoverable oil equivalents, development of the discovery towards the Johan Castberg field will be considered.

“There may be additional resources in this structure, and we will now analyze the acquired data and consider possible appraisal of the discovery,” says Jez Averty.

The “Songa Enabler” rig will now return to and complete the Blåmann well. Next, drilling at Gemini North will start. All of the necessary permits are in place, and the work can start as early as 10 July.

www.statoil.com

www.eni.com

www.petoro.no