LNG

July 12 (LNGJ) - Malaysia’s Jerun natural gas field operated Sapura-OMV Upstream has achieved first gas to boost LNG supply prospects at the Bintulu liquefaction plant in Sarawak. UK major Shell has a 30 percent equity stake in the field, through its Malaysian subsidiary.

   The field is located about 160 kilometres northwest of the Bintulu LNG plant. “Comprising an integrated central processing platform, Jerun will export gas through a new 80km pipeline into the E11RB production hub, for onward delivery to Bintulu-based customers including Malaysia LNG,” said Shell.

Challenger Energy, the Americas-focused and London-listed exploration and production company, has formally signed the Area 3 licence offshore Uruguay where field resources include around 9 trillion cubic feet of gas.

The Area 3 licence was awarded under the Open Uruguay Round process and, following final regulatory approvals being granted, was signed in Montevideo on March 7.

“Accordingly, the Area 3 first exploration period will commence on 7th June 2024 and will run for four years, until 6th June 2028,” said Challenger.

Depth and range

The Area 3 licence covers an area of 13,252 square kilometres located in relatively shallow water depths (from 20 metres to 1,000 metres) around 100 kms (62 miles) off the Uruguayan coast.

“The block has substantial existing 2D and 3D seismic coverage, with two previously identified material prospects possessing currently estimated gross resource potential of up to 2 billion barrels of oil and up to 9 Tcf of natural gas,” said Challenger.

Uruguay’s state-owned oil and gas company ANCAP awarded Challenger with the Area 1 block licence in May 2020 and the company confirmed a farm-out process for the block three years later.

“Thanks to the farm-out agreement with Chevron Corp., the company is in the process of divesting a 60 percent interest in the Area 1 block,” explained Challenger.

During the initial exploration period, the Company's minimum work obligations on the Area 3 block are relatively modest, comprising licensing and reprocessing of 1,000km of legacy 2D seismic data and undertaking two geotechnical studies.

“The company intends to follow a similar strategy to that successfully adopted for the Area 1 licence (the farm-out of which to Chevron was announced on 6th March 2024), specifically to accelerate its technical work programme including additional discretionary work,” Challenger added.

Strong position

Eytan Uliel, Chief Executive of Challenger, said that the signing of the Area 3 licence cements the company’s position as a significant industry participant in Uruguay's offshore.

“It represents a successful expansion of the company's business in Uruguay, a country that has fast become one of the world's frontier exploration hotspots,” explained Uliel.

“We believe that Area 3 has strong technical merit and offers an exciting value-creation opportunity,” the CEO stated.

Challenger noted that to the east is the Brazilian maritime border, an area that was subject to considerable licensing in December 2023, with 13 nearby Brazilian blocks licenced variously to Chevron, Shell, China National Offshore Oil Corp. and Brazil’s Petrobras.

To the south, the block is adjacent to two deepwater Uruguayan blocks, Area 6, held by Houston, Texas-based APA Corp. and Area 7, which is held by Shell.

UK major Shell plc reported an increase in net profits for the first three months of the year as liquefied natural gas sales volumes rose by 6 percent on the previous quarter, though were slightly less than the same quarter of 2022.

ADNOC Gas, the recently spun-off subsidiary of Abu Dhabi National Oil Co (ADNOC), has signed its first big deal since the floatation in the form of a three-year LNG supply agreement with French major TotalEnergies.

Following an initial public offering completed in March 2023, ADNOC Gas is now listed on the Abu Dhabi Securities Exchange as a separate company and is responsible for running Abu Dhabi’s world-scale LNG, natural gas processing and gas marketing operations in the United Arab Emirates.

The ADNOC Gas liquefaction plant on Das Island in the Arabian Gulf currently has export capacity of 6 million tonnes per annum and TotalEnergies is already a customer.

A statement said that the ADNOC Gas supply deal with TotalEnergies was with the French company’s Gas and Power unit and was for a period of three years, though the volumes involved were not immediately disclosed.

“Our new LNG supply agreement with TotalEnergies represents another significant milestone in our strategy to expand our global reach and strengthen our position,” said Ahmed Mohamed Alebri, Chief Executive of ADNOC Gas.

Commitment

“This agreement reflects our commitment to meeting the needs of our customers by offering supply security, price competitiveness,and flexibility,” Alberi added.

TotalEnergies has a long-standing presence in the UAE, having operated in the country for more than 80 years.

“We are pleased to have signed this three-year contract with our long-standing strategic partner,” said Thomas Maurisse, Senior Vice President LNG at TotalEnergies.

“These additional volumes will strengthen our global LNG portfolio and our ability to supply the growing Asian markets,” Maurisse added.

The three-year contract is expected to commence in 2023 and will run through 2025.

The ADNOC Gas IPO followed the sale of 5 percent of its shares for around $2.5 billion and the company is now listed on the Abu Dhabi Securities Exchange.

In addition to operating the Das Island LNG plant ADNOC Gas now independently runs eight processing sites, both onshore and offshore, and has a pipeline network of over 3,250 kilometres (2,020 miles) in length in the region.

Existing joint venture partners in the company’s LNG plant include Japan’s Mitsui & Co and UK major BP, as well as TotalEnergies.

TotalEnergies is also a gas-processing partner of ADNOC Gas and Shell and Thailand’s PTT Exploration and Production have similar joint venture partnerships with the company.

Abu Dhabi National Oil Company (ADNOC) is proceeding with its plans to offer a minority stake in new subsidiary ADNOC Gas, which consolidates the emirate’s gas processing and LNG operations, through an initial public offering on the Abu Dhabi Securities Exchange in 2023.

Jan 6 (LNGJ) - Shell Plc has updated its earnings forecast for Integrated Gas and the other divisions and sees lower liquefaction volumes in Australia. Shell said these lower volumes mainly reflected the longer than expected plant outage at the “Prelude FLNG” plant offshore northwest Australia and “operational issues” at the Queensland Curtis LNG export facility.

   Shell’s adjusted earnings in Integrated Gas will see pre-tax depreciation of $1.2 billion to $1.6 billion. Shell added that its Trading and Optimisation earnings in the fourth quarter were “expected to be significantly higher” compared with the third quarter of 2022. In the Upstream division production was expected to be between 1,825 and 1,925 kboe/d.

Nov 1 (LNGJ) - Shell completed the sale of its 45 percent shareholding in the Malampaya gas field in the Philippines to Malampaya Energy XP Ltd, a subsidiary of Prime Infrastructure Capital of the Philippines. Shell staff will continue their employment under the new ownership. The other main remaining shareholder in the gas field is local company Udenna Corp.

   “Since operations began in 2002, the Malampaya gas field has supplied an important part of the Philippines’ energy demand through the dedicated work of our partners and staff, past and present,” said Zoe Yujnovich, Shell’s Upstream Director. “This sale supports our strategy to create a resilient and competitive Upstream portfolio,” she added. The Malampaya gas field is in the process of depleting and is increasing the urgency for LNG imports to the Philippines.

The Netherlands said production at the Groningen natural gas field would be lowered to the minimal amount needed to keep wells operational in the coming 12 months and the field is still scheduled to be shut down in 2024 even amid gas shortages, while floating LNG terminals have begun operating offshore the Dutch province.

The Government said in a statement that the Groningen field, formerly the largest supplier to the Netherlands and which sent some volumes to Germany, will be capped at 2.8 billion cubic metres from the start of October 2022, down from 4.5 Bcm.

The Groningen field is operated by a joint venture comprising Shell and ExxonMobil and still holds huge reserves of natural gas.

Production at Groningen has gradually been reduced over the past 10 years because of complaints about earth tremors.

The Government said that all 11 production locations in the Groningen region would remain operational until at least April 2023 to enable an increase in production in case of an emergency.

More claims

The authorities added that more than 100 claims for structural damage had been filed since two earthquakes, the largest measuring 2.7 on the Richter scale, hit Groningen province on Saturday, September 24.

Most of the 1,000 tremors reported in Groningen since 1986 have been measured at 2.7 on the Richter scale or less.

Analysts note that such small tremors can be felt by some people though are unlikely to cause damage.

An investigation published by the Dutch financial newspaper, “Het Financieele Dagblad”, said that the Dutch Government had earned more than €360 billion ($349Bln) in revenues from the Groningen gas field since it came on stream.

“Total revenues from the gas region amounted to €428Bln when adjusted for inflation, of which €363.7Bln went to the government while €64.7Bln was split between Shell and ExxonMobil,” said the report.

Surge in costs

The report noted that Groningen production costs started to rise rapidly from less than €500 million a year in 2013 to a peak of €2.9Bln in 2018, as the government started to compensate people in Groningen who said their homes had been damaged by tremors.

A further €8.36Bln has been set aside by the Dutch Government for further compensation payments for Groningen residents.

The Dutch floating LNG facilities are sited at Eemshaven on the waterway between Eemshaven port in the province of Groningen and the North Sea. Analysts added that LNG imports would likely be less costly in the long run than the controversial Groningen gas field with its soaring compensation claims.

Eemshaven LNG comprises two floating storage and regasification units (FSRUs), the “Golar Igloo” vessel and a regasification barge provided by Belgian shipping company Exmar.

The FSRUs supply the Dutch system and most regasification capacity at Eemshaven has been reserved for the Dutch operations of Shell and the French utility and energy group Engie, while the main utility of the Czech Republic is also importing shipments. 

TechnipFMC, the US oil and gas services company based in Houston, was awarded an engineering, procurement, construction and installation contract by UK major Shell plc for the Jackdaw gas development in the UK North Sea to help offset rising LNG imports.

The company said the contract, whose value was not disclosed, covered pipelay for a 30 kilometres tieback from the new Jackdaw platform to Shell’s Shearwater platform, as well as an associated riser, spool-pieces, subsea structures and umbilicals.

The tieback will use pipe-in-pipe technology, which is designed for high-pressure, high-temperature usage.

“We’re excited to embark on this significant project together in the UK North Sea,” said Jonathan Landes, President, of Subsea at TechnipFMC.

“Our strong technical record and our ability to design, engineer, construct and install were key to our success in winning this award,” stated Landes.

Shell in the UK took the final investment decision in July 2022 to develop the Jackdaw gas field following regulatory approvals granted earlier in the year as European countries tried to underpin their domestic supplies hit by the Russian war in Ukraine that led to sanctions.

Development plan

The Jackdaw field is located about 250 kilometres (155 miles) east of Aberdeen, Scotland, and is adjacent to the UK-Norway median line.

The field is 100 percent owned and operated by an affiliate of Shell UK which became part of the Shell group of companies in 2016 after BG Group was taken over.

The Jackdaw development consists of a new Wellhead Platform (WHP), four production wells and the 30km pipeline from the Jackdaw WHP to the Shearwater gas hub.
Peak production from the field is estimated at 40,000 barrels of oil equivalent per day.

Shell said that the UK North Sea remained one of Shell’s core Upstream positions, attracting capital to high margin hydrocarbon projects that can be resilient to commodity price cycles.

The gas from the Jackdaw field will come ashore at the St Fergus gas terminal in Scotland.

The project is expected to come on stream by 2025 and at peak production rates could represent over 6 percent of projected UK North Sea gas production in the middle of this decade.

Shell has said that the Jackdaw gas field was part the company’s broader intent to invest up to £25 billion ($30Bln) in the UK energy system in the next decade.

The company added at the time that the St Fergus terminal that will handle the Jackdaw gas will also be part of the development of the Acorn Carbon Capture and Storage project, which will aim to sequester carbon dioxide from industrial clusters in Scotland, the UK and northern Europe.

Russian natural gas company Gazprom confirmed it had cut off pipeline natural gas to Germany purchased by Denmark's Orsted and Shell subsidiary Shell Energy as output by the Saint Petersburg-based company declined almost 5 percent and deliveries to Europe dropped by a quarter in the first five months through May 2022.

Gazprom said gas production fell by 4.8 percent year-on-year to 211.4 billion cubic metres compared with the same January-to-May period of 2021.

Gas exports to non-Commonwealth of Independent States (CIS) countries, meaning to Western Europe, dropped by 27.6 percent, or by 23.2Bln cubic metres, in the January-to-May 2022 period and amounted to 61 Bcm.

“Gazprom confirms complete suspension of gas supplies to Denmark’s Orsted Salg & Service A/S and Shell Energy Europe due to failure to pay in roubles,” it said.

“As of the end of the working Gazprom Export did not yet receive a payment from Orsted Salg & Service for the gas supplied in April, which was to be made in compliance with the Russian President's Decree No. 172 dated March 31, 2022,” it added.

“No payment has been received from Shell Energy Europe for gas delivered in April either,” it added.

Export data

In its gas production and export data, Gazprom said the average daily exports of Gazprom in May fell by 9 percent in monthly terms to 351.6 million cubic metres for  deliveries of gas with confirmed nominations.

Gazprom added that gas deliveries to China via the “Power of Siberia” pipeline were increasing, but it did not provide any figures.

Since Russian President Vladimir Putin sent troops into Ukraine on February 24, Moscow has demanded that clients from “unfriendly countries”, including the 27 EU member states, pay for their gas in roubles.

The new requirement is aimed at stopping Western financial sanctions against Russia’s central bank further weakening the rouble.

So far Poland, Bulgaria, Finland and the Netherlands have had their natural gas deliveries suspended over refusing to pay in roubles.

Dutch natural gas trader GasTerra was the most recent not to comply with Gazprom’s payment requirements in roubles and consequently was cut off by the Russian company.

GasTerra, which buys and trades gas on behalf of the Dutch Government, said it had contracted elsewhere for the 2 Bcm it had expected to receive from Gazprom through October 2022.

GasTerra is 50 percent-owned by Dutch Government entities while another joint 50 percent stake is shared between Shell and ExxonMobil.