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OE Press: 2016 / December

OE Press: 2016 / December (66)

Wednesday, 28 December 2016 09:48

Energean completes Tanin, Karish deal with Delek

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Energean has closed its deal with Delek Group, Avner Oil Exploration, and Delek Drilling for 100% stake in the I/16 Tanin and I/17 Karish leases, offshore Israel, paving the way for Energean to stick to its plan of first oil at the two fields in 2020.

Map from Energean. 

According to Delek, a cash payment of US$40 million was received earlier this month on 22 December. 

“The transfer of the rights in the leases in the Petroleum Register will be performed in the coming days upon the deposit of a guaranty by Energean in accordance with the provisions of Section 57 of the Petroleum Law, 5712-1952 and the regulations promulgated thereunder,” Delek said in a statement.

In early-December, Energean said it is planning first gas from Tanin and Karish by 2020. The firm also said it will submit a field development plan (FDP) within six months and would be investing about $1 billion over "the next few years."

The deal, which was first inked on 16 August, was for a total of $148.5 million. Operator Noble Energy had to set out of the two leases under Israel’s Gas Framework, due to its part in the giant Leviathan field. 

The Israeli trio agreed to sell their 26.4705% shares in each in the I/16 Tanin and I/17 Karish leases offshore Israel to Ocean Energean Oil - a subsidiary of Cypriot based, Energean Oil & Gas. Noble Energy's 47.059% stake in the blocks were also sold to Energean.

Karish and Tanin are two small gas fields, 40km apart, with a combined gas capacity estimated at 60-80 Bcm. 

Tanin, discovered in 2011, contains about 22.4 Bcm of natural gas (contingent resources) and 12.7 Bcm of natural gas (prospective resources) was discovered.

Karish, discovered in 2013, contains about 36.3 Bcm of natural gas (contingent resources) and 14.0 Bcm of natural gas (prospective resources) was discovered.

In addition, about 14.3 MMbbl of condensate (contingent resources) and about 4.3 MMbbl of condensate (prospective resources) was discovered in the two reservoirs.

Read more:

First gas from Tanin, Karish 2020 - Energean

Energean acquires Israeli gas assets

Wednesday, 28 December 2016 08:45

Statoil to drill Mim with Deepsea Bergen

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Statoil has received consent from Norway’s Petroleum Safety Authority (PSA) to drill exploration well 6507/3-12 on the Mim prospect in the Norwegian Sea.

Statoil is the operator for production licence 159B in block 6507/3 in the Norwegian Sea west of Sandnessjøen.

Water depth at the site is 381m. Drilling is scheduled to begin in early January 2017 and will last 27 days. A possible sidetrack from the well will take a further 18 days. 

The well is to be drilled by the Deepsea Bergen semisubmersible drilling facility owned and operated by Odfjell Drilling. The facility is an Aker H-3 type, built in 1963. It is classified by DNV GL and registered in Norway.

Tuesday, 27 December 2016 13:21

Eni inks Egypt concession duo

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Eni signed two new concession agreements for the North El Hammad and North Ras El Esh, in the shallow waters in Egyptian Mediterranean Sea, as a result of the EGAS 2015 international bid round.

Eni is the operator of the North El Hammad block with 37.5% stake, in participation with BP, (37.5%), and Total (25%). 

The block, which covers an area of 1927sq km, is to the west of the Abu Madi West and Baltim-Baltim South development areas, where Eni recently made the significant discoveries of Nooros, in production since August 2015 and Baltim South West.

Moreover, Eni has a 50% participation stake in the North Ras El Esh block, operated by BP with an equity of 50%. The block, which covers an area of 1389sq km, is southwest of the development areas of Temsah and Port Fouad.

The two new concession agreements follow the recently awarded blocks of Shorouk, Karawan and North Leil in the deepwaters of the Egyptian Mediterranean. 

“They strengthen Eni’s portfolio and positioning in Egypt, a country of historic and strategic importance, and further confirm the company’s commitment to pursue new exploration after the recent and important successes of Nooros, Zohr and Baltim South West, made in 2015 and in 2016,” Eni said in a statement.

Eni has been present in Egypt since 1954, operating through its subsidiary IEOC. The company is the main producer in the country with an equity of approximately 224,000 boe/d at year-end 2016.

Tuesday, 27 December 2016 12:35

Shell fails at Knarr FPSO audit

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Norway’s Petroleum Safety Authority (PSA) has unveiled a number of failings, following an audit of Shell's management of the integrity of flexible risers, transfer lines and associated safety equipment on Knarr floating production and storage offloading (FPSO) unit.

The Knarr FPSO, from Teekay. 

Knarr is in the North Sea, west of Måløy in Sogn og Fjordane county and some 50km north-east of Snorre, at 410m water depth.  

The field has been developed using subsea wells and a floating production unit, Petrojarl Knarr FPSO. Oil is loaded from Knarr FPSO into tankers, while the gas is piped to St. Fergus in Scotland. Production on the field began in March 2015.

From 3-6 October 2016, the PSA carried out an audit of how Shell is managing the integrity of flexible risers, transfer lines and associated safety equipment, and of Teekay's activities as production operator. The Petrojarl Knarr FPSO received acknowledgement of compliance (AoC) from the PSA in October 2014.

The audit revealed non-conformities relating to: overpressure protection of gas export pipeline; follow-up of overpressure protection performance requirements; passive fire protection; and follow-up of flexible pipelines. 

In addition, improvement points were detected in connection with the labelling of equipment; follow-up and verification; and maintenance management.

Shell (AS Norske Shell) is the operator of the field, while Teekay owns and operates Petrojarl Knarr. Shell took over operatorship of Knarr from BG Group Norway in February 2016.

The companies have been given a deadline of 1 February 2017 to report on how the non-conformities will be dealt with and how the improvement points will be assessed.

Tuesday, 27 December 2016 12:00

Lundin to use Leiv Eiriksson for Gohta

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The Petroleum Safety Authority Norway (PSA) has given Lundin Norway consent to drill exploration well 7120/1-5 in a prospect named Gohta. The prospect is located in Lundin-operated production license 492 (PL492), which is comprised of blocks 7120/1 and 7120/2 in the Barents Sea.

The well's coordinates 71° 56' 15.97" N and 20° 14' 57.37" E, around 185km northwest of Hammerfest, and in 368m water depth. Drilling is scheduled to begin in late December 2016 and estimated to last 73 days. There will also be a potential well test.

The well is to be drilled using the Leiv Eiriksson mobile drilling facility, which is owned and operated by Ocean Rig. The facility is a BINGO 9000 type, built in 2001. It is classified by DNV GL, registered in the Bahamas, and received Acknowledgement of Compliance from the PSA in July 2008.

Image: Leiv Eiriksson/Ocean Rig

Tuesday, 27 December 2016 08:39

Petrobras axes Golar FSRU

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Brazil’s Petrobras has terminated its contract for the Golar Spirit floating storage and regasification unit (FSRU) one year early, according to Golar LNG. 

Image from Golar LNG.

Golar LNG confirmed it received a notice for early termination for the FSRU, which is now scheduled to end on 21 June 2017. The original end date of the charter was August 2018. 

According to the terms of the charter agreement, Petrobras will pay Golar LNG a compensation fee as a result of the early termination representing approximately 62% of the EBITDA remaining under the contract from 21 June 2017 to the original contract end date, according to Golar LNG.

Golar LNG said it will immediately start re-marketing the vessel for FSRU employment post June 2017. 

“There is currently significant interest and bidding activity in the FSRU market and also a limited number of FSRUs available for the next two years. Golar Spirit, as a relatively small capacity FSRU could be well suited for a number of emerging smaller scale FSRU projects as well as a potential bridging solution for larger projects,” the company said in a statement.

Friday, 23 December 2016 08:11

Statoil hits Gullfaks 30-year mark

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Gullfaks was Statoil’s first field where the company was both developer and operator. Since production started 30 years ago on 22 December 1986, 2.6 billion bbl have passed the loading buoys.

Image of Gullfaks C on its way to the field in 1989. (Photo: Leif Berge/Statoil)

"Gullfaks is a prime example of the best that this industry has achieved in Norway," Gunnar Nakken, senior VP for the operations west cluster said.

Nakken said that Gullfaks also played a key role in Statoil's development as an operating company, learning a lot from the development of Statfjord and from the international companies that were involved on the Norwegian continental shelf in the pioneering days.

The establishment of the operations organization in Bergen was a strategic decision, in order to build a petroleum cluster here, Statoil said.

"Wise decisions, outstanding subsurface work, the use of new technology and good team work in the Norwegian petroleum cluster have more than tripled the expected field life and ensured enormous value creation from Gullfaks. After 30 years, we still believe in Gullfaks, which has seen major investments and undergone extensive upgrades in recent years," Nakken said, who is also Statoil's site manager in Bergen. 
"This solidarity was palpable in the wake of the Turøy accident in the spring. We have faced many tough challenges in Gullfaks' history, but none as difficult as this tragic accident."  

The Golden Block

The name Gullfaks comes from "Gullblokken," meaning the Golden Block, as block 34/10 was known prior to its allocation in 1978. The Golden Block was awarded to a wholly Norwegian group consisting of Statoil (85%), Hydro (9%) and Saga (6%). This would be Statoil and the Norwegian petroleum industry's baptism by fire, the company said. Norwegian industry accounted for nearly 80% of the total investments. 

The first explorations in the 1970s indicated that this was a significant oil and gas reservoir; however, at the time the field was expected to run out not long into the new millennium. Today, the production horizon stretches towards 2040, according to Statoil. 

30 years on the seabed

Image of the installation of new loading buoys in 2014 is another example of projects that are extending Gullfaks' lifetime (Photo: Rune Morgan Kyrkjeeide/Statoil)

22 December is also the day Statoil opened the valves of its very first subsea well in Gullfaks, marking the start of an incredible technological development. Statoil has been at the forefront of several of the most important breakthroughs in the subsea industry in the world. Without this technology, it would not have been possible to develop fields such as Åsgard and Troll Oil. 

More satellites have subsequently been linked to Gullfaks: Gullfaks South has been developed with installations on the seabed and came on stream in October 1998, with production of oil and condensate and reinjection of associated gas. Phase two started in October 2001, comprising production and export of gas, linked to the A and C platforms. 

The Rimfaks satellite, consisting of three subsea templates, has production pipes linked to Gullfaks A, while Skinfaks has a production system linked to the templates in Gullfaks South. Another example is Gimle, situated between Gullfaks and Visund, which is connected to Gullfaks C. 

Reversed the decline

Gullfaks is also an outstanding example of improved oil recovery (IOR) and has won the Norwegian Petroleum Directorate's IOR prize, among other awards. 

After a significant decline in production from Gullfaks in late 2010, production soon picked up again. In 2011 and 2012, wells with compromised integrity were repaired and the injection of water was stabilized. Water injection has been the main reason for the high recovery factor at Gullfaks. In addition, Statoil has developed subsea gas compression, in collaboration with others, which accelerates gas production. 

The installation of new loading buoys in 2014 is another example of projects that are extending Gullfaks' lifetime, meaning the field is now expected to continue creating value for companies and society up until 2040. 

Friday, 23 December 2016 05:59

DEA ups stakes in Njord area

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Germany's DEA is acquiring participating interests in seven licenses in the Njord area of the Norwegian Sea, including 20% increased interest in the Njord field, from Engie E&P Norge. 

The agreement with France's Engie E&P Norge includes: 20% in the Njord field (PL107 and PL132), 10% in the Hyme field (PL348), 10% in the Snilehorn discovery (PL348B), 15% in the Noatun discovery (PL107B and PL107D) and 20% in the North Flank discovery (PL107C). 

Dea says the Njord Area is one of the key areas for the company in Norway, and increasing the presence with assets with long production life has been important for the company.

Earlier this year, production was stopped at Njord and Hyme and the Njord production facility was towed to Kvaerner's Stord facility in Norway for extensive modifications to extend its operating life and accommodate a number of new satellite field tie-back developments, including the Snilehorn, Pil and Bue fields.

These, as well as a redevelopment of the Njord and Hyme fields, come under Statoil's Njord Future Project, with production due to start in 2019. 

“All together the acquisition adds approximately 45 MMboe in reserves and contingent resources to DEA. This acquisition has attractive economics and establishes DEA as one of the major players in the area and confirms our commitment to growth in Norway”, said Hans-Hermann Andreae, Managing Director of DEA Norge.

The transaction between DEA Norge AS and Engie E&P Norge AS will be effective from 1 January 2017.

After the transaction, DEA’s shares in the licenses will be:

  • PL 107 AND PL 132 (Njord): 50 % 
  • PL 348 (Hyme): 27,5% 
  • PL 348B (Snilehorn): 27,5% 
  • PL 107B and PL 107D (Noatun): 45% and 20% 
  • PL 107C (North Flank): 50% 
Thursday, 22 December 2016 12:08

Eni to use Scarabeo 8 for PL716 wildcat

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The Norwegian Petroleum Directorate (NPD) has granted Eni Norge a drilling permit for wellbore 7318/12-1, cf. Section 8 of the Resource Management Regulations.

Well 7318/12-1 will be drilled from the Scarabeo 8 drilling facility.

The drilling program for wellbore 7318/12-1 concerns the drilling of a wildcat well in production license 716 (PL716). Eni Norge is the operator with an ownership interest of 30&. The other licensees are Bayerngas Norge (20%), Faroe Petroleum Norge (20%), Petoro (20%) and Point Resources (10%). The area in this license consists of blocks 7318/11 and 7318/12. The well will be drilled about 80km northwest of Johan Castberg and 320km from the mainland.

PL716 was awarded on 21 June 2013 in the 22nd licensing round on the Norwegian shelf. This is the first well to be drilled in the license.

The permit is contingent upon the operator having secured all other permits and consents required by other authorities before the drilling starts, the NPD said. 

Early this week, Eni gained the nod from Norway's Petroleum Safety Authority to drill the Barents wildcat. 

Image: Map of PL716/Norwegian Petroleum Directorate

Read more:

Eni to drill Barents Boné-Bigorna with Scarabeo 8

Thursday, 22 December 2016 08:50

BW Offshore buys into Gabon PSC

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BW Offshore and the BW Group entered into agreement to acquire 66.67% of the Dussafu production sharing contract offshore Gabon.

Subject to closing of this first transaction, the partnership has secured a right to acquire a further 25% of the Dussafu license.

BW Offshore has formed a joint venture company with BW Group, known as BW Energy Holdings (BWEH), for the purpose of pursuing oil and gas interests. The JV is owned 66.67% by BW Offshore and 33.33% by Maple Co. Ltd., a wholly owned subsidiary of BW Group.

A wholly-owned subsidiary of BWEH, known as BW Energy Gabon Pte. Ltd. (BWEG), has entered into a sale and purchase agreement with Harvest Energia B.V. to acquire its 100% interest in Harvest Dussafu B.V., which owns a 66.667% interest in the Dussafu production sharing contract with an area covering 210,000 acres located offshore Gabon. Harvest Energia B.V. is a wholly-owned subsidiary of Harvest Natural Resource, Inc.The acquisition price is US$32 million in cash, subject to certain adjustments.

Closing of the transaction is subject to fulfilment or waiver of conditions precedents, including among others, approval by the stockholders of Harvest Natural Resource, Inc. and approval from the government of Gabon. It is estimated that closing will take place in Q1 2017.

The remaining 33.333% interest in the Dussafu block is owned by Pan-Petroleum Gabon B.V. (PPGBV), a subsidiary of the OSE-listed Panoro Energy ASA. BWEG has also entered into a memorandum of understanding (MOU) with PPGBV relating to the proposed acquisition of a further 25% interest in the Dussafu block for $12 million in cash subject to the closing of the Harvest transaction. In connection with and subject to such acquisition from Panoro and Harvest, BWEH is in discussions with the Gabon Oil Co. (GOC) for their participation.

"We have previously said that we are exploring partnerships and alternative commercial models. We are now starting to deliver on this strategy. We see the investment in the Dussafu block as an attractive opportunity with the potential to create significant value for the shareholders of BW Offshore," said BW Offshore CEO Carl K. Arnet.

The drop in oil price over the past years has reduced the costs of drilling and subsea equipment significantly, which in turn has lowered the break-even price required for a Dussafu development. Following Gabonese license requirements, first oil is planned for 2018, BW Offshore said.

"The availability of production assets that match field requirements de-risks the development and makes it realistic to achieve first oil within 2018. The project economics are robust at and below the current oil price," Arnet said.

BWEH plans to finance the acquisitions from Harvest Energia B.V and PPGBV through use of internal funds. In addition to the acquisition price payable for the interests, the field development is estimated to cost a total of $150 million until first oil.

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