Eni has confirmed the presence of oil in multiple reservoirs at the Amoca-2 well, the first well drilled by an international oil major offshore Mexico since the 2013 Energy Reform.
Map of Area 1, from Eni.
The Italian giant drilled the Amoca-2 well in the shallow waters of Campeche Bay, in Area 1, 200km west of Ciudad del Carmen, at 25m water depth. It marks the first well in a four-well campaign at Amoca.
The well reached a total depth of approximately 3500m, encountering approximately 110m of net oil pay from several good quality Pliocene reservoir sandstones, of which 65m were discovered in a deeper, previously undrilled horizon, says Eni. The well confirmed the presence of 18° API oil in the shallower formations, while the newly discovered deeper sandstones contain high quality light oil.
Eni continues to assess the reserves; however, the company says that the well indicates a meaningful upside to the original estimates.
Eni will continue its Area 1 drilling campaign with a new well in the Amoca area (Amoca-3) followed by the Miztón-2 and Tecoalli-2 delineation wells, which will be drilled in 2017 to appraise existing discoveries as well as targeting new undrilled pools.
Area 1 or Block 1 was won by Eni in Mexico’s Round One, Phase 2 held in September 2015. The area in the Southeast basin. It is 67sq km and consists of the three fields: Amoca, Mizton and Tecoalli. The fields contain 2P reserves of 107 MMbbl of light oil, and 69 Bcf of natural gas at 33m water depth.
Eni says it is already evaluating options for a fast-track phased development of the fields.
“This important discovery comes in a country where Eni has not yet operated and confirms our exploration capabilities, building upon our strong exploration track-record, and is another confirmation of the validity of our ‘Dual Exploration Model’ approach. Focusing on conventional exploration with high initial stakes and operatorship, we manage to fast-track exploration activities, monetize exploration successes early and receive competitive development opportunities, therefore maximizing value generation for our shareholders,” Eni CEO Claudio Descalzi said.
Eni announced its plans to explore Area 1 in December 2015. By October 2016, Mexico’s National Hydrocarbons Commission granted its approval for Eni to drill the Amoca-2 well, in which drilling began in December 2016.
Eni holds a 100% stake in the Area 1 production sharing agreement.
Maersk Oil reached an agreement with the government of Denmark that will see a full redevelopment plan for the Tyra project in the Danish North Sea.
Tyra East. Image from Maersk Oil.
The deal comes nearly three months after the Danish giant announced plans to shut in the field next year.
“The agreement provides the terms that enable the DUC (Danish Underground Consortium) partners to progress a full redevelopment plan for the Tyra facilities towards a decision to invest in the project by the end of 2017,” says Maersk Oil.
Denmark’s largest gas field, the Tyra field requires redevelopment due to subsidence of the chalk reservoir, which has led to the platforms sinking by around 5m in the last 30 years, according to Maersk. This has reduced the gap between the sea and the platform decks. As a result, investment is required if the Tyra complex is to continue producing safely into the next decade.
Since 1984, Tyra, 225km west of Esbjerg, has been at the center of Denmark’s national energy infrastructure, processing 90% of the nation’s gas production. Tyra East and Tyra West are also the hub for a number of smaller facilities in the Tyra field. This includes the neighboring unmanned facility, Tyra Southeast, which was extended in 2015.
Maersk Oil says that a full redevelopment will restore the current infrastructure, including the gas processing hub and five surrounding satellite fields, which include Harald and Valdemar, and thereby ensure continued production from the Tyra field. The new asset could enable future production of oil and gas volumes from the DUC license area as well as third party projects.
According to the Danish company, the full redevelopment program requires a resequencing of engineering activities versus the decommissioning and partial redevelopment scenario outlined to the gas markets on 30 December 2016.
Maersk Oil today (22 March) issued a further REMIT notice to the gas markets on behalf of all DUC partners outlining that, pending a final investment decision, production from Tyra is now expected to shut in December 2019, and restart in March 2022. More information on the revised schedule for a full redevelopment of Tyra will be made available on final investment decision later this year.
The deal is also expected to facilitate future oil and gas in investments in the Danish North Sea, in which oil and gas have been produced for nearly 50 years.
“The agreement makes the Danish North Sea a more competitive investment area for oil and gas companies to invest and to develop new opportunities. A redevelopment of Tyra can be a catalyst for prolonging the life of the Danish North Sea. It can protect valuable revenues to the Danish state and Danish jobs– especially in the Esbjerg area. We will now issue tenders and progress engineering work towards detailed plans in preparation of a final investment decision by end 2017,” says Maersk Oil Chief Operating Officer Martin Rune Pedersen.
The agreement with the government of Denmark is subject to Danish parliamentary approval.
At the beginning of the year, Maersk Oil expected to shut in Tyra in October 2018, due to a lack of an economic strategy.
The Tyra field is operated by Maersk Oil on behalf of the DUC, a partnership between A.P. Moller – Maersk (31.2%), Shell (36.8%), Nordsøfonden (20%) and Chevron (12%).
The latest Gulf of Mexico lease sale had 28 companies vying for 163 tracts in a total of 913,542 acres in the Central Planning Area of the Outer Continental Shelf (OCS), bringing in nearly US$275 million in high bids.
Image from BOEM Twitter.
US Secretary of the Interior Ryan Zinke said that the Gulf of Mexico Lease Sale 247 garnered $274.8 million in high bids. A total of 28 companies submitted 189 bids, with the sum of all bids totaling more than $315 million
The Department’s Bureau of Ocean Energy Management (BOEM) offered 9,118 unleased blocks, covering 48 million acres, located from 3-230mi offshore Louisiana, Mississippi, and Alabama, in water depths ranging from 9ft to more than 11,115ft (3-3400m).
The hottest block with the most bids, Garden Banks 1006, went to France’s Total. The French company won with the high bid of $12.6 million against Shell, Statoil, Chevron, and Cobalt International.
However, Shell walked away with the highest bid on a block, paying $24 million for Atwater Valley 64. Shell was also the highest bidder with a total of 20 bids thoughout the bidding process, and a sum of $55.9 million.
Other high bidders included: Statoil for Walker Ridge 55 at $21 million; Hess Corp. for Green Canyon 287 at $18 million; Total for Garden Banks 1006 at $12.6 million; Chevron for Green Canyon 642 at $11 million.
BOEM estimates that Lease Sale 247 could result in the production of 460-890 MMbbl, and 1.9-3.9 Tcf of natural gas.
Statoil was the high bidder for 13 leases, securing stake in all of the company's main priorities, and marking the reset of its exploration efforts in the US Gulf of Mexico. Of all 13 blocks to be obtained by Statoil, the company secured 100% stake in each.
“The leases awarded reinforce Statoil’s exploration strategy of securing prospective acreage, while taking advantage of the cycle to access these leases at favorable rates in the US Gulf of Mexico,” says Tore Løseth, head of exploration in the US and Mexico.
“The results today are the fruits from taking sufficient time to review lessons from our past exploration campaign, and from thoroughly strengthening our regional subsurface understanding of this area. We continue to believe in the potential of the Gulf of Mexico. Our participation in the lease sale is part of a targeted, step-wise approach to test our play concepts in the area,” says Løseth.
Following Lease 247's sales, each bid will go through a 90-day evaluation process to ensure the public receives fair market value before a lease is awarded. Lease awards will be posted to BOEM’s website as they are completed.
Secretary Zinke called the Gulf of Mexico one of the most productive oil and gas basins in the world.
“Today’s strong sale reflects continued industry optimism and interest in the Gulf’s Outer Continental Shelf, a keystone of the Nation’s offshore oil and gas resources and a vital part of President Trump’s plan to make the United States energy independent,” Secretary Zinke said. “In cooperation with the Gulf offshore industry, we are committed to responsible energy development that spurs economic opportunities, generates jobs for American workers, and produces revenues for local, state, and federal partners. Expanded Gulf production is critical to America’s economic and energy security, and will play a greater role as we move to break our dependence on foreign oil and strengthen the Nation’s energy independence.”
Today’s (22 March) lease sale marks the final lease sale in the Obama Administration’s Five-Year Program. The first 11 sales offered nearly 73 million acres for development and garnered more than $3 billion in bid revenues. The lease sale, announced in December, was livestreamed from New Orleans.
As of 1 March 2017, about 16.9 million acres on the US OCS are under lease for oil and gas development (3194 active leases) and 4.6 million of those acres (929 leases) are producing oil and natural gas. More than 97% of the leases are in the Gulf of Mexico; about 3% are on the OCS off California and Alaska, according to BOEM.
National Ocean Industries Association (NOIA) President Randall Luthi said that he was pleased with the results of the lease sale, which reflect an improving offshore oil and gas market.
“Today’s sale demonstrates that the offshore oil and gas industry remains committed to staying in US waters and underscores the importance of offshore development to the US economy and domestic energy security. The offshore oil and gas industry provides tremendous economic and energy benefits for our nation,” Luthi said. “What’s more, the Energy Information Agency (EIA) predicts that U.S. oil production in the Gulf of Mexico will reach record highs in 2017, which will continue to boost Gulf state economies.”
Earlier this month, US Department of the Interior (DOI) announced its first lease sale under the Trump Administration’s new Outer Continental Shelf Oil and Gas Leasing Program for 2017-2022, Lease Sale 249, will be held on 16 August. It will offer 73 million acres in the Gulf of Mexico, offshore Texas, Louisiana, Mississippi, Alabama, and Florida.
Past Gulf of Mexico lease sales
Looking back at prior lease sales, today's lease sale went much better.
Lease Sale 248, BOEM’s first-ever online lease sale held in August 2016, only received bids for 24 of 4399 blocks, for a total of just over $18 million. The 24 tracts included in the offer, cover 138,240 acres in the Western Gulf of Mexico Planning Area.
At this time last year, on 23 March 2016, BOEM held two GoM lease sales, Lease Sale 241 and Lease Sale 226. Both failed to impress.
Lease Sale 241 garnered about $156 million in high bids, which offered 128 tracts covering 693,962 acres of the Outer Continental Shelf offshore Louisiana, Mississippi and Alabama.A total of 30 oil and gas companies submitted 148 bids for Sale 241, with a sum of all bids received coming in at more than $179 million. However, Lease Sale 241 fared better than August 2015’s Lease Sale 246, which only collected $22.7 million for 33 tracts, covering 190,080 acres.
Lease Sale 226 received zero bids, which included 162 whole or partial unleased blocks and covering 595,475 acres in the Eastern Planning Area. The blocks are 125mi offshore in 2657-10,213ft water depth. The area is south of eastern Alabama and western Florida; the nearest point of land is 125mi northwest in Louisiana.
German operator DEA has gained approval from Norway’s Ministry of Petroleum and Energy for the US$1.2 billion (NOK 10 billion) Dvalin development plan in the Norwegian Sea, with production set for 2020.
Illustration of Dvalin, from DEA.
The Dvalin field is in PL435, Blocks 6507/7/9 and 6507/8 in the Norwegian Sea, about 15km northwest of Heidrun and 290km from Nyhamna in Mid-Norway. Recoverable resources are estimated to be some 18.2 Bcm of natural gas from two reservoirs.
Dvalin will be developed with a four wells subsea template, tied back to the Heidrun platform. At Heidrun, the gas will be partly processed in a new module, before the gas is transported via the new Polarled pipeline, going to the Nyhamna onshore gas terminal.
According to DEA, the plan for development and operation (PDO) was the largest PDO handed over to the Ministry in 2016.
“This approval is a major milestone for the Dvalin project, and we are committed to develop the project and start production in 2020,” says Hans-Hermann Andreae, managing director of DEA Norge.
Andreae says that Dvalin will create jobs in Trøndelag, Møre og Romsdal, Rogaland and Oslo/Akershus.
“We are proud of leading a project that has widespread ripple effects. In addition, the development contributes significantly to DEA’s ambition to further grow our business in Norway,” says Andreae.
Currently, DEA says that engineering and detailed planning are carried out. Production of the new modules to be placed at the Heidrun platform and the subsea production systems is expected to start later this year.
DEA Norge is operator of license PL435 with a 55% stake. Partners are Petoro (35%) and Edison (10%).