GENERAL INTEREST Quick Takes
bp awarded exploration blocks offshore Indonesia
bp has been awarded Agung l and Agung ll oil and gas exploration blocks by the Indonesian government as part of the second round of 2021 Oil and Gas Working Area (WK) Bid Round.
Agung I block covers an area of 6,656 sq km deepwater offshore Bali and East Java, while the Agung II block lies in deepwater offshore of South Sulawesi, West Nusa Tenggara and East Java covering an area of 7,970 sq km. The area is underexplored with potential of gas resource close to growing gas demand, bp said Mar. 18.
bp will serve as operator with 100% interest.
bp currently operates Indonesia’s largest gas-producing field in Tangguh LNG in Bintuni Regency, Papua Barat, contributing about 20% of national gas production. It is expected to increase to more than 30% with Train 3 startup following completion of the Tangguh expansion project. bp also has non-operated interest (30%) in Andaman II PSC, an offshore deepwater exploration block in Aceh.
Australia lets contract for Northern Endeavour Phase 1 decommissioning
The Australian Government has awarded a $325 million (Aus.) contract to UK-based Petrofac Facilities Management for the first stage of clean-up at the abandoned Laminaria-Corallina oil fields in the Timor Sea.
Stage one involves the disconnection of the Northern Endeavour FPSO from subsea equipment at the fields, which were abandoned when owner Northern Oil & Gas Australia entered liquidation in 2019.
The government has taken charge of cleanup but passed legislation in Federal Parliament to impose a temporary levy on the industry in Australia to recover the costs of removing infrastructure at the field and remediating the site, delivering on the government’s commitment that Australian taxpayers are not left footing the bill, according to Resources Minister Keith Pitt.
The legislation was passed despite disapproval from companies led by Chevron, ExxonMobil, and Shell, who were opposed to funding decommissioning of a site in which they were not involved.
Petrofac expects disconnection of Northern Endeavour to take about 18 months.
Kinder Morgan-backed Ruby Pipeline files Chapter 11
Kinder Morgan Inc.-backed Ruby Pipeline LLC, a natural gas pipeline joint venture with Pembina Pipeline Corp., filed to reorganize under Chapter 11 of the Bankruptcy Code in response to a $475 million unsecured bond repayment obligation.
The JV owners will continue to work with Ruby’s bondholders to work out a resolution and Kinder Morgan will continue to operate the pipeline as Chapter 11 permits daily operations to continue.
Ruby Pipeline is a 1.5 bcfd, 680-mile, 42-in. diameter pipeline system that extends from Wyoming to Oregon providing natural gas supplies from the major Rocky Mountain basins to consumers in California, Nevada, and the Pacific Northwest.
ExxonMobil, QatarEnergy sign farmout for block offshore Egypt
ExxonMobil signed an agreement to farm out working interest in an exploration block offshore Egypt to QatarEnergy.
Subject to customary approvals by the government of Egypt, QatarEnergy will hold a 40% working interest in the North Marakia Offshore Block in the Mediterranean Sea, An ExxonMobil affiliate will remain operator with 60% interest.
The block, which covers an area of 4,847 km2 in water depths of 1,000 m to 2,000 m, lies 5 miles offshore Egypt’s northern coast in the Herodotus basin. It was awarded to ExxonMobil in 2020 (OGJ Online, Dec. 30, 2019).
PTTEP readies to become Yadana operator
PTT Exploration and Production Public Co. Ltd. (PTTEP) is advancing plans to become operator of the Yadana gas project (Blocks M5, M6) off Myanmar’s southwestern coast. In January, TotalEnergies SE noted plans to withdraw as operator and joint venture partner citing worsening human rights conditions.
PTEEP said it has carefully considered the field status and said gas production continuity to prevent disruption to energy demand is of the utmost importance. Yadana “is a pivotal source of natural gas supply to the livelihood of the people in both Myanmar and Thailand,” the company said.
Yadana field produces around 6 billion cu m/yr gas of which about 70% is exported to Thailand where it is sold to PTT and 30% is retained by Burmese state-owned Myanmar Oil and Gas Enterprise (MOGE) for domestic use.
Operatorship transfer is expected to close July 20.
Under the production operating agreement, TotalEnergies’ share will be allocated proportionately to the remaining joint venture partners with no commercial value. After TotalEnergies’ withdrawal, PTTEP will hold 37.0842% participating interest, while a subsidiary of Chevron, Unocal Myanmar Offshore Co. Ltd. will hold 41.1016%.
Energean lets CCS contract for Prinos basin
Energean PLC has let a contract to Halliburton to assess carbon storage potential of Prinos basin in the North Aegean Sea south of Kavala, Greece, in 31 m of water.
Halliburton carbon capture, utilization, and storage (CCUS) experts will collaborate with Energean to evaluate the area’s CO2 storage complex. Work will include long-term plume modeling, characterizing the storage complex, and a conceptual development plan with performance modeling. The subsurface study began in March.
Prinos basin includes Prinos oilfield and South-Kavala gas field and is the only oil and gas producing area in Greece. It has been identified as a location to host a CO2 storage plant with potential capacity to store close to 100% of Greek manufacturing sector emissions for 10 years, starting in 2025.
Enbridge gains approval to advance Alberta CCS hub
Enbridge Inc. is advancing development of a carbon sequestration (CCS) hub west of Edmonton, Alta. The company plans to conduct evaluations and testing in the Wabamun area to ensure safe and permanent sequestration.
The company was granted approval by the Alberta government to pursue the Open Access Wabamun Carbon Hub being developed to support near-term carbon capture projects being advanced by project partners Capital Power Corp. and Lehigh Cement, a division of Lehigh Hanson Materials Ltd.
Capital Power and Enbridge Inc. signed a memorandum of understanding (MOU) in November 2021 to collaborate on CCS solutions in area. The proposed hub would serve Capital Power’s Genesee Generating Station. The Genesee CCS Project is expected to capture up to 3 million tonnes/year (tpy) of CO2 from repowered units, which would be transported and stored through Enbridge’s open access carbon hub.
In January 2022, Lehigh Cement and Enbridge signed an MOU for a carbon solution for Lehigh’s cement manufacturing facility in Edmonton. Lehigh is developing North America’s first full-scale carbon capture, utilization and storage (CCUS) solution for the cement industry at its Edmonton plant, with the goal of capturing some 780,000 tpy of CO2. Captured emissions would be transported via pipeline and permanently sequestered by Enbridge.
The hub and associated carbon capture projects could help avoid nearly 4 million tonnes of atmospheric CO2 emissions with phased in-service dates starting as early as 2025, Enbridge said in a Mar. 31 release. The hub could be scaled to meet the needs of other nearby industrial emitters, it said.
The CCS infrastructure will be co-developed and ultimately co-owned with local Indigenous partners, including the First Nations Capital Investment Partnership (comprised of Alexander First Nation, Alexis Nakota Sioux Nation, Enoch Cree Nation, and Paul First Nation) and the Lac Ste. Anne Métis Community.
Exploration & Development Quick Takes
ExxonMobil to analyze gas discovery offshore Cyprus
A consortium led by ExxonMobil Corp. will analyze data collected from the Glaucus-2 appraisal well in Block 10 of the Exclusive Economic Zone of the Republic of Cyprus. The well has been completed and drilling demonstrated the presence of a gas reservoir with high quality characteristics, according to the Cyprus Ministry of Energy, Trade, and Industry.
This is the second discovery well in the block, which covers 635,554 acres (2,572 sq km) in the Eastern Mediterranean in about 6,800 ft of water. Data will be used to help determine the qualitative and quantitative characteristics of the reservoir more accurately, as well as the potential options for development and commercialization of the discovery.
The well was drilled by the Stena Forth drillship.
Pursuant to current legislation, the consortium will notify the Ministry of Energy, Trade, and Industry of the data evaluation results as soon when they are completed.
In February 2019, ExxonMobil discovered natural gas offshore Cyprus at the Glaucus-1 well. At the time, the operator said the discovery could represent an in-place natural gas resource of about 5-8 tcf (142-227 billion cu m).
ExxonMobil Exploration and Production Cyprus (Offshore) is operator (60%) with partner Qatar Petroleum International Upstream OPC (40%).
Esso Australia plans Bass Strait gas development expansion
Esso Australia Pty Ltd., a subsidiary of ExxonMobil and operator of the Gippsland basin oil and gas fields in Bass Strait offshore eastern Victoria, is planning a $400 million (Aus.) investment to expand gas development in the region.
Plans include progressing additional gas development from Kipper field and advancing a funding decision for Turrum field.
The company expects delivery of an additional 200 petajoules of gas to the Australian domestic market between 2023 and 2027, the company said.
About 30 petajoules will be brought on line in 2023 to provide gas supplies to help avert (Australian) winter supply risks forecast for the country’s southern states.
The Gippsland basin remains the largest single source of natural gas for Australia’s east coast, said ExxonMobil’s Australian Chair, Dylan Pugh.
In early 2021, Esso Australia commissioned the West Barracouta project in the basin, calling it one of the largest domestic gas projects in the country this decade.
Esso Australia is a 50-50 partner with BHP in Bass Strait fields. BHP’s interest will shift to Woodside Petroleum, which has acquired BHP’s petroleum interests.
Frontera discovers oil in Ecuador
Frontera Energy Corp. discovered oil on the southern portion of the Perico block in Ecuador.
Tui-1, the company’s second well on the block—about 7 km from the Jandaya-1 exploration well—was drilled to a total depth of 10,975 ft and encountered a total of 125 ft net pay across seven hydrocarbon bearing reservoirs including the Hollin, Basal Tena, T and U Sandstones, and Limestones B, A and M2. After 2 days of initial production tests, the Basal Tena formation was producing an average of 1,200 b/d of 27.2° API light crude oil with a water cut of 5.2%.
Frontera is preparing the permits to move forward with a long-term test at the site. Additional appraisal activities will be conducted to confirm size and mid- to long-term production levels for the multiple potential formations.
At Jandaya-1, production tests in the lower Hollin formation have produced 37,674 bbl, with daily production of 798 b/d of 27.9° API light crude oil and 1.7% water cut after 54 days of testing. Production from Jandaya-1 and Tui-1 is being transported by truck to PetroEcuador’s Lago Agrio infrastructure nearby and moved through the Transecuadorian Pipeline System to Balao terminal where the crude is exported.
Frontera holds about 16,700 net acres in the Perico and Espejo exploration blocks in Ecuador. The blocks lie near existing production and infrastructure in Sucumbíos Province.
Frontera is operator in a 50-50 JV with GeoPark Ltd.
ExxonMobil sanctions fourth Guyana offshore project
ExxonMobil has made a final investment decision (FID) for the Yellowtail development offshore Guyana after receiving government and regulatory approvals. The company’s fourth, and largest, project in the Stabroek block is expected to produce about 250,000 boe/d starting in 2025.
In May 2019, the operator reported the Yellowtail-1 oil discovery, which encountered 292 ft of oil-bearing sandstone reservoir. The well was drilled to 18,445 ft in 6,046 ft of water. Yellowtail-2 encountered 69 ft of net pay in a newly identified, high-quality oil-bearing reservoirs among the original Yellowtail-1 discovery intervals.
Yellowtail production from the ONE GUYANA floating production storage and offloading (FPSO) vessel will develop an estimated resource of more than 900 million bbl of oil. The $10-billion project will include six drill centers and up to 26 production wells and 25 injection wells.
ExxonMobil’s ongoing offshore exploration in Guyana has discovered a recoverable resource of more than 10 billion boe.
ExxonMobil affiliate Esso Exploration and Production Guyana Ltd. is operator and holds 45% interest in the block. Hess Guyana Exploration Ltd. holds 30% interest and CNOOC Petroleum Guyana Ltd. holds 25% interest.
Drilling & Production Quick Takes
Shell Trinidad and Tobago starts Colibri production
Shell Trinidad and Tobago, through Shell PLC subsidiary BG International Ltd., started production at Colibri natural gas field offshore Trinidad and Tobago.
Colibri is a backfill project in Block 22 and NCMA-4 in the North Coast Marine Area (NCMA). It is expected to add about 30,000 boe/d (174 MMscfd) of sustained near-term gas production with projected peak production of 43,000 boe/d (250 MMscfd) through a series of four subsea gas wells tied back to the existing Shell-operated Poinsettia platform, also in NCMA acreage. Final investment decision for the project was announced in March 2020.
Colibri, when combined with Barracuda and existing developments, will deliver more gas to the Trinidad and Tobago domestic market and the LNG export markets.
Shell is operator at Colibri with partner Trinidad and Tobago national oil company Heritage Petroleum Co. Ltd. Shell holds 90% and 80% working interests in Block 22 and NCMA-4, respectively. In Trinidad and Tobago in total, Shell is present in seven offshore and onshore blocks as well as pipelines and in the Atlantic LNG plant where its equity is 46-57.5% in each of four trains.
88 Energy plugs Merlin-2 without testing
88 Energy Ltd. has plugged the Merlin-2 appraisal well on the Alaskan North Slope. The company was unable to obtain hydrocarbon samples due to the lower than anticipated porosity and permeability of the reservoir zones.
The result follows previously encouraging oil shows and logging-while-drilling data that indicated thicker target intervals than encountered in the earlier Merlin-1 well.
Provisional analysis of the wireline logging program indicated that reservoir quality is insufficient to warrant a production test, the company said.
Both wells were drilled on sparse vintage 2D seismic data. The company is considering the merit of future 3D seismic acquisition to better identify drilling locations in its Project Peregrine acreage.
All data from Merlin-2 will be evaluated to determine the next move, including the possibility of finding drilling locations for its Harrier prospect to test the N-14 and N-15 Nanushuk reservoirs.
88 Energy holds 100% interest in Project Peregrine.
SDX Energy ties back West Gharib infill development well
SDX Energy PLC tied back the MSD-25 infill development well on Meseda field in the West Gharib concession, Egyptian Eastern Desert.
The well, the second in a possible 13-well development campaign at Meseda and Rabul fields, targeted the Asl formation. The primary top Asl formation reservoir was encountered at 4,109 ft MD (3,361 ft TVDSS) and reached 4,385 ft TD on Feb. 22 after drilling through 84.8 ft of good-quality, net oil pay sandstone with 26.1% average porosity.
The well has been perforated, tied-in to the existing infrastructure, and flow tested. Post-clean up, the well is expected to produce a stabilized rate of about 300 b/d, in line with pre-drill estimates.
The rig is moving to MSD-20, the next well in the campaign. A second rig will begin operations to drill MSD-24 and accelerate the development plan.
The development drilling campaign is aimed at growing gross production to about 3,500-4,000 b/d by early 2023.
SDX holds 50% working interest in the well.
Vintage begins Vali fracturing program
Vintage Energy Ltd. has begun its fracture stimulation program at Vali gas field in southwest Queensland Cooper basin permit ATP 2021.
The campaign, expected to take 42 days, involves fracturing the gas-bearing Permian-age Patchawarra formation reservoir across multiple zones in the Vali-2 and Vali-3 wells.
Fracturing at discovery well Vali-1ST is complete, Vintage said.
The campaign is a prelude to completion of all three wells for gas production for sale to AGL under a March sales agreement.
Work is being carried out by Schlumberger and supervised by Griffin Energy Solutions.
Production from the Patchawarra will be supplemented by flows from another reservoir in the Toolachee formation, the company said.
Vali field is to be connected to the Moomba gas gathering network in South Australia with the gas destined for the eastern Australian domestic market.
Vali field has been independently assessed as containing 2P reserves of 101 petajoules.
Vintage is operator with 50% interest. Metgasco Ltd. and Bridgeport (Cooper Basin) Pty Ltd. each hold 25% interest.
Western Gas secures funding to spud Sasanof-1
Western Gas Corp. Pty Ltd. (WGC) has secured commitments to fully fund drilling of the Sasanof-1 wildcat in Carnarvon basin permit WA-519-P offshore Western Australia.
WGC will fund 25% of the cost. Farminees Global Oil and Gas Ltd. and Prominence Energy Ltd. will pay 50% and 25%, respectively.
Working interests are WGC 62.5%, Global Oil and Gas 25%, and Prominence 12.5%.
Major service and supply contracts for the program have been awarded and the well is scheduled to spud in May using the Valaris MS-1 semisubmersible rig.
Sasanof-1 is west and southwest of WGC’s Equus gas fields, all of which lie between Woodside group’s Scarborough fields and Chevron group’s Gorgon-Io-Jansz fields.
The prospect covers about 400 sq km and is updip of WGC’s Mentorc field in retention lease WA-70-R—part of Equus field group.
ERC Equipoise Ltd. estimated the prospect to contain a 2U prospective resource of 7.2 tcf of gas and 176 million bbl of condensate on a P50 basis. The high 3U prospective resource estimate is 17.8 tcf of gas and 449 million bbl of condensate on a P10 basis.
The prospect is a seismic amplitude-supported structural-stratigraphic trap in high quality sands at the top of the Cretaceous Lower Barrow group formation within the Exmouth Plateau.
PROCESSING Quick Takes
Sinopec starts up new Ionikylation unit at Anqing refinery
China Petroleum & Chemical Corp. (Sinopec) subsidiary Sinopec Anqing Co. has commissioned a new unit based on composite ionic liquid (IL) alkylation technology for production of high-octane alkylate at its 161,000-b/d refinery in Anqing, Anhui Province, China (OGJ, Jan. 7, 2019, p. 61).
Operational as of late-March, the newly commissioned 7,400-b/d (300,000-tonnes/year) unit is equipped with Beijing-based China University of Petroleum’s Ionikylation process, which enables Sinopec Anqing to produce high-octane alkylate free of sulfur, benzene, olefins, and aromatics, ensuring the refinery’s fuel production complies with China’s current National VI-A (equivalent to Euro 6) emission standard, Well Resources Inc.—the technology’s global licensor—said.
“We are very pleased with the smooth and successful [startup] of this new alkylation unit,” said Qingsong Qian, Sinopec Anqing’s deputy general manager, adding that the refinery’s implementation of the environmentally friendly Ionikylation technology aligns with Sinopec’s broader ESG mandates.
Sinopec Anqing’s commissioning of the new unit—which completed construction in 2019—marks operation of the third Ionikylation unit in Sinopec’s refining system (OGJ Online, July 8, 2019).
Sinopec previously revamped brownfield alkylation units with Ionikylation technology at Sinopec Jiujiang Co.’s 161,000-b/d refinery in Jiujiang City, Jiangxi Province, China, and Wuhan Petrochemical Co. Ltd.’s 161,000-b/d refinery in Wuhan City, Hubei Province (OGJ Online, Apr. 2, 2019).
Alongside reducing operational hazards by eliminating the presence of strong acids (e.g., hydrofluoric acid, concentrated sulfuric acid) required by more traditional alkylation processes, Ionikylation also will help Sinopec refineries meet China’s national goals in alignment with the global energy transition.
“As the world moves towards an increasingly sustainable and decarbonized economy, the use of clean-burning transportation fuels will only become more pronounced,” said Warren Chung, president of Well Resources. “Ionikylation [meets] evolving fuel standards while allowing operators to ensure that their staff and nearby communities are afforded the highest levels of safety.”
Lukoil’s Kstovo refinery finishing work on new deep conversion complex
PJSC Lukoil subsidiary LLC Lukoil Nizhegorodnefteorgsintez (NNOS) is nearing completion of the operator’s long-planned deep conversion, delayed coking complex at its 17-million tonne/year (tpy) Kstovo refinery in central Russia’s Nizhny Novgorod region (OGJ Online, Mar. 24, 2021).
NNOS is currently finishing related construction works for the new 2.11-million tpy delayed coking plant, which once in operation, will increase he refinery’s overall product yield to 97%, with yield of light products reaching 74%, Lukoil said on Apr. 6.
Lukoil did not disclose a specific timeline for when it plans to officially commission the new plant, which previously was scheduled for startup in fourth-quarter 2021.
Separately, Lukoil also said NNOS is continuing to prepare design documentation for its earlier announced plan to add a new polypropylene complex at the Kstovo refinery. Upon formally breaking construction groundwork for the project last July, Lukoil said the planned polypropylene complex will process a feedstock of propylene supplied by the refinery’s two existing catalytic crackers to produce 500,000-tpy of product for other plastic manufacturers in the region (OGJ Online, July 22, 2021).
Further details regarding the proposed petrochemical complex, however, have yet to be disclosed.
Alongside its primary 2.11-million tpy delayed coker, Lukoil has said the new Nizhny Novgorod deep conversion complex also will include the following major units:
- A 1.5-million tpy combined diesel fuel and gasoline hydrotreater.
- A 50,000-cu m/hr hydrogen production unit.
- A 425,000-tpy gas fractionator.
- An 81,000-tpy combined elemental sulfur-sulfuric acid production unit.
TRANSPORTATION Quick Takes
Sempra enters Cameron LNG Phase 2 HOA; CCS, hydrogen MOU with Kogas
Sempra Infrastructure, a subsidiary of Sempra, has entered into a heads of agreement (HOA) with affiliates of partners TotalEnergies SE, Mitsui & Co., and Japan LNG Investment LLC, a company jointly owned by Mitsubishi Corp. and Nippon Yusen Kabushiki Kaisha (NYK) Line, for development of the Cameron LNG Phase 2 liquefaction plant in Hackberry, La. Phase 2 will add a fourth train (6.75-million tonne/year (tpy)) to the plant and debottleneck the three existing 4.5-million tpy trains, bringing total capacity to more than 20.25 million tpy.
The HOA allocates Sempra 50.2% of projected fourth-train production capacity and 25% of projected debottlenecking capacity under tolling agreements, with the remaining capacity allocated equally to existing Cameron LNG Phase 1 customers. Sempra plans to sell its LNG under long-term agreements before taking final investment decision.
Sempra Infrastructure also awarded two front-end engineering design (FEED) contracts for Cameron LNG Phase 2, one to Bechtel Energy Inc. and one to a joint venture between JGC America Inc. and Zachry Industrial Inc. At the conclusion of the FEED process, Sempra expects to select one of the contractors for Phase 2 engineering, procurement, and construction.
Cameron LNG began commercial operations of Train 3 in 2020.
Separately, Sempra Infrastructure and Korea Gas Corp. entered an MOU for collaboration around project development and offtake in LNG, carbon capture and sequestration, and hydrogen. Sempra last month agreed with TotalEnergies to expand cooperation in both LNG and renewables.
Woodside begins processing Pluto gas at NWS via interconnector
Woodside Petroleum Ltd. has started processing gas from Pluto-Xena fields offshore Western Australia through the Karratha LNG and domestic gas infrastructure via the newly completed Pluto-Karratha Gas plant interconnector.
The 3.2-km interconnector pipeline connects Pluto LNG with the Karratha plant, enabling access for third party gas producers. Both plants are on the Burrup Peninsula.
The interconnector start-up supports accelerated production of gas from Phase 1 of Pluto’s Pyxis Hub, Woodside said.
Karratha will process about 2.5 million tonnes of LNG in aggregate along with 20 petajoules of domestic gas from Pluto-Xena in the next 3 years.
Commercial agreements underpinning third-party gas processing at the North West Shelf (NWS) also allow NWS project participants to maximize the value and use of infrastructure on Burrup as the original NWS gas fields begin winding down.
NWS participants comprise Woodside Energy Ltd., BHP Petroleum (North West Shelf) Pty Ltd., BP Developments Australia Pty Ltd., Chevron Australia Pty Ltd., Japan Australia LNG (MIMI) Pty Ltd., and Shell Australia Pty Ltd. All hold a 16.67% interest. Woodside is operator.
Woodside holds a 90% interest in Pluto LNG and operates the infrastructure. Kansai Electric and Tokyo Gas each hold 5%.
The Pluto-Karratha interconnector pipeline was built and is operated by AGI Operations Pty Ltd.
New Fortress applies to build offshore Louisiana LNG plant
New Fortress Energy Inc. filed applications with the US Maritime Administration, Coast Guard, and Department of Energy to request necessary permits and regulatory approvals to site, build, and operate a 2.8-million tonne/year (tpy) LNG liquefaction plant 16 miles off the coast of Grand Isle, La.
Subject to the receipt of permits and approvals, the company targets beginning operations in first-quarter 2023.
In March, New Fortress executed two 20-year purchase agreements with Venture Global LNG Inc. for output from its 20-million tpy Plaquemines LNG plant and 20-million tpy CP2 LNG plant (OGJ Online, Mar. 16, 2022).
Enagas selling Quintero LNG terminal to Fluxys, EIG
Enagas Chile SPA and affiliates of OMERS Infrastructure Management Inc. are selling an 80% equity stake in the 5.5-billion cu m/year (bcmy) GNL Quintero SA regasification terminal in Quintero Bay, Chile, to Fluxys and EIG Global Energy Partners. The terminal also has 334,000 cu m of storage and 2,500 cu m/day of truck loading capacity.
Operational since 2009, Quintero is the largest LNG terminal in Chile. It holds 75% of the country’s LNG regasification capacity and in 2021, was the point of entry for 67% of Chile’s total natural gas imports, according to the purchasing companies.
Beyond the LNG business, Fluxys and EIG acquired Quintero as part of their energy transition plans. Fluxys described the partnership as “a forward-looking investment creating a foothold in another country in Latin America where the energy transition stands high on the government agenda. With its abundant solar and wind resources, Chile aims to produce the world’s cheapest green hydrogen. The Belgian Hydrogen Import Coalition with Fluxys as partner has affirmed the competitiveness and feasibility of a green molecule supply chain from Chile to Europe and Belgium.”
The companies expect the deal to close second-half 2022, subject to customary conditions, including any required merger control and related approvals.
Fluxys owns the 9-bcmy Zeebrugge LNG terminal in Belgium and the 13-bcmy Dunkerque LNG terminal in France. Last year, Fluxys took FID on an expansion of Zeebrugge LNG. Qatar Petroleum holds 100% of Zeebrugge’s current regasification capacity.
German LNG terminals sign offtake MOUs
Hanseatic Energy Hub (HEH), developers of a 12-billion cu m/year (bcmy) LNG terminal in Stade, Germany, has signed an MOU to supply 3 bcmy of natural gas to EnBW Energie Baden-Württemberg AG. HEH, held by Fluxys, Partners Group Holding AG, and Buss Group GMBH & Co. KG, plans to begin operation in 2026.
HEH says Stade LNG will meet 10% of Germany’s gas requirements. Expressions of interest in booking long-term capacity at the terminal were to be accepted through Apr. 8, with plans to submit permit documents before Apr. 17.
Stade city council approved the terminal, which is being designed to accommodate future import of ammonia, on Mar. 29.
Earlier in April, German LNG Terminal GMBH signed an MOU with Shell for long-term natural gas imports through the 8-bcmy terminal the former is developing in Brunsbüttel, Germany. The parties are working towards a binding agreement defining volume and duration.
German LNG will include two 165,000-cu m tanks, a two-berth jetty for LNG carriers up to QMax-size (266,000 cu m) and smaller LNG ships, regasification for shipment through Germany’s high-pressure gas grid, and infrastructure for loading LNG onto tanker trucks, rail cars, and LNG bunker ships for distribution. It is also being designed to accommodate future import of hydrogen or hydrogen derivatives.
Uniper is developing a 7-8 bcmy terminal in Wilhelmshaven, Germany.