OGJ Newsletter
GENERAL INTEREST Quick Takes
Australian government unveils plan to secure domestic gas supplies
The Australian government released its first full National Gas Infrastructure Plan (NGIP) and infrastructure investment framework to help secure natural gas supplies over the next 20 years.
The NGIP provides a development pathway for supply to households and manufacturers along with five priority actions for the country’s east coast gas supply and infrastructure to 2040.
At least one new basin will need to be brought on stream before 2030 to meet the projected east coast demand, it said. Critical basins include the Narrabri gas project in northern New South Wales, the Beetaloo subbasin in the Northern Territory, the Galilee basin in central Queensland, and the North Bowen basin in Queensland.
Expansions of existing pipeline capacity and construction of new pipelines to transport gas to east coast markets also are needed. In conjunction, expanded transportation capacity from north to south is needed as northern gas supply expands and the country’s gas supplies in the southeast decline.
The government has called on industry to contribute to a new expressions of interest process to identify projects that require support to accelerate delivery. This would include projects that enhance marketplace competition and allow for consideration of gas infrastructure that also supports hydrogen, carbon capture storage projects, and biomethane.
Australia’s Minister for Industry, Energy and Emissions reduction, Angus Taylor, said the investment framework will enable the government to accelerate development of critical projects to final investment decision stage.
The NGIP is part of the Morrison Government’s plan for a gas-led recovery for the nation’s economy from the COVID-19 pandemic first unveiled in September 2020.
EOG moves into Australia with Beehive buy
EOG Resources Inc. plans its first move into Australia following completion of the acquisition of Western Australian Bonaparte Gulf permit WA-488-P containing the Beehive prospect from Melbana Energy Ltd., Sydney.
EOG paid an initial sum of US$7.5 million for 100% interest and will make conditional additional payments based on EOG’s future program and success.
The company will begin a round of geophysical and geotechnical work in February-June 2022 in a 440-sq km envelope surrounding the Beehive prospect in the northeast corner of the permit close to the marine boundary with the Northern territory.
Studies will be designed to collect seabed data and shallow geological information to aid selection of a drilling location for Beehive-1.
The well could be drilled as early as third-quarter 2022, but no later than August 2023 (to comply with permit work program commitments) using a jack up rig. Water depths in the area are 40-50 m.
McDaniel & Associates previously estimated the prospect to potentially contain 388 MMboe on a best estimate basis with an upside to 1.6 billion boe.
Melbana later revised these figures to estimates of 416 MMboe (best estimate) and 1.4 MMboe (upper estimate) following interpretation of 3D seismic data acquired across Beehive in 2018.
The prospect is enhanced by its proximity to the existing ENI-operated Blacktip gas field (discovered in 2001) and pipeline connection to the Northern Territory gas grid.
Melbana retained its 100% interest in adjoining permits WA-544-P containing the undeveloped Turtle oil discovery and NT-P87 in the Northern Territory sector containing the undeveloped Barnett oil discovery. Melbana is currently running geoscientific studies over both permits.
NEO Energy acquires UK business of JX Nippon
NEO Energy has agreed to acquire 100% of the share capital of JX Nippon Exploration and Production (UK) Ltd. (JK UK), a subsidiary of JX Nippon Oil & Gas Exploration Corp.
JX UK holds non-operated interests in multiple producing fields and associated infrastructure in the UK North Sea including a 20% interest in Mariner field and an 18% interest in Culzean field. The transaction excludes JX UK’s interests in the Andrew area.
The deal, the purchase price of which is based on an enterprise value of $1.655 billion, is subject to approvals from the relevant authorities and regulatory consents.
Talos, Freeport LNG to develop Gulf Coast CCS project
Talos Energy Inc. and Freeport LNG Development LP intend to develop a carbon capture and sequestration (CCS) project, the Freeport LNG CCS project (FLNG CCS), immediately adjacent to Freeport LNG’s natural gas pretreatment infrastructure near Freeport, Tex., on the Gulf Coast, about 60 miles southwest of Houston. The companies anticipate first injection could occur by end 2024. Talos will be project manager and operator and will be joined by its partner, Storegga Geotechnologies Ltd., lead developer of the Acorn CCS project in the UK with ExxonMobil (OGJ Online, Oct. 6, 2021).
FLNG CCS will use a Freeport LNG-owned geological sequestration site less than half a mile from point of capture with as long as a 30-year injection term and will permanently sequester CO2. The site also is within 25 miles of as much as an additional 15 million tonnes/year (tpy) of incremental CO2 emissions from major industrial sources, offering the potential for future expansion.
FLNG CCS remains subject to execution of definitive agreements.
Freeport LNG is adding a fourth 5-million tpy train to its plant, expanding liquefaction capacity to more than 20 million tpy. It is targeting 2022 FID on the train, pending sufficient offtake agreements (OGJ Online, Aug. 2, 2021).
Exploration & Development Quick Takes
Lukoil discovers oil offshore Mexico
LUKOIL discovered an oil field within the Yoti West structure at Block 12 offshore Mexico. The field was discovered after drilling the first exploration well. Preliminary estimates put initial oil in place of 250 million bbl.
Yoti West-1 EXP was drilled 60 km offshore from the Valaris 8505 semisubmersible platform (OGJ Online, Aug. 16, 2021). The well penetrated a sand reservoir in Upper Miocene sediments with high permeability and effective oil-saturated thickness of about 25 m. An assessment plan for Yoti West field is expected to be developed based on drilling results.
In 2017, LUKOIL Upstream Mexico obtained exploration and production rights for the 521-sq km Gulf of Mexico block. LUKOIL is operator with 60% interest. Eni holds the remaining 40%.
Two successful exploration wells were previously drilled at Block 10 offshore Mexico where LUKOIL owns 20% and Eni is operator. The resource base of the block is currently being assessed based on drilling results.
Petrobras finds hydrocarbons in Aram block
Petroleo Brasileiro SA (Petrobras) identified hydrocarbons in well 1-BRSA-1381-SPS (Curaçao) in Aram block, Santos basin presalt, 240 km from the city of Santos, São Paulo, at a water depth of 1,905 m.
The well is a pioneer in the block. The oil-bearing interval was verified through wireline logging and fluid samples, which will be further characterized through laboratory analysis. This data will evaluate the potential and direct the next exploratory activities in the area. The consortium will drill the well to the expected depth and verify the extent of the discovery and characterize the conditions of the reservoirs.
Petrobras is operator of the block (80%) in partnership with CNODC (20%).
FAR spuds deepwater well in The Gambia
FAR Gambia Ltd., a wholly owned subsidiary of FAR Ltd., has spudded the Bambo-1 exploration well in Block A2, about 85 km offshore The Gambia in 930 m of water.
The well will be drilled by the Stena IceMax drillship to a planned depth of about 3,400 m. The drillship arrived on site on Nov. 12 and drilling is expected to take about 30 days.
The well is designed to drill into a series of vertically stacked targets including Bambo (S390 and S400) with two shallower horizons not previously intersected, Soloo (S410 and S440) which is an extension of the hydrocarbon-bearing reservoirs in adjacent Sangomar oil field, Senegal, and Soloo Deep (S552 & S562), which has two additional horizons, also not previously penetrated.
The targets have combined best estimated recoverable, prospective resource of 1,118 million bbl. FAR calculates the chance of geological success for the various horizons from 7-36%.
FAR is operator at A2 and A5 blocks (50%). Its joint venture partner, PC Gambia Ltd., a subsidiary of Petroliam Nasional Berhad (PETRONAS), holds the remaining 50%.
Drilling & Production Quick Takes
CNOOC starts production at Buzzard Phase II
CNOOC Ltd. started production at the Buzzard Phase II development, offshore UK North Sea, about 96 km northeast of Aberdeen with average water depth of about 96 m.
While fully utilizing the existing Buzzard infrastructure, the project also includes a newly built set of underwater production systems (OGJ Online, July 8, 2021). Two production wells and two water injection wells have been brought on stream.
Buzzard Phase II is expected to reach peak production of about 12,000 boe/d in 2022, increasing Buzzard’s total production to 80,000 boe/d.
CNOOC Petroleum Europe Ltd., a wholly owned subsidiary of CNOOC, is operator of Buzzard (43.21%) with partners Suncor Energy Co. (29.89%), Harbour Energy Co. (21.73%), and ONE-Dyas BV (5.16%).
Zenith Energy to drill in Niger Delta
Zenith Energy Ltd. entered into an option agreement with Noble Hill-Network Ltd. (NHNL) for development of the North-West Corner of Block OML 141, Nigeria, covering 105 sq km of the Niger Delta region. The block contains Barracuda and Elepa South oil fields, as well one prospective field with an estimated 232.7 million bbl of discovered oil.
Plans have been finalized to drill, test, and complete the Barracuda 5 well (B-5), situated between two previously drilled wells which have both encountered significant hydrocarbons, the company said.
The drilling location for B-5 has been acquired by NHNL, and all necessary civil works (including dredging and clearing of the designated well location) have been performed in preparation for mobilization of a barge-mounted drilling rig.
The drilling contract is expected to be signed in January 2022 to begin operations in first-quarter 2022. Production from Barracuda is expected to begin in second-quarter 2022 at about 4,000 b/d.
If successful, production will commence immediately using a barge-mounted early production infrastructure to initially transport produced oil to a nearby floating storage and offloading vessel.
Drilling locations for Barracuda wells 6, 7, and 8 have been identified.
Serica reaches first production at Columbus field
Serica Energy PLC has reached first production at Columbus field in the Central North Sea.
Hydrocarbons from the C1z development well started flowing into the Arran subsea system on Nov. 24.
Columbus produces from a gas-condensate reservoir in the Forties sandstone formation in Block 23/16f and part of Block 23/21a. The development consists of a single horizontal well which runs along the central axis of the reservoir, drilled in the spring of 2021.
The Columbus well is connected to the Arran export pipeline through which Columbus production is exported along with Arran field production. When production reaches the Shearwater platform, it is separated into gas and condensate. The gas is exported to St Fergus via the SEGAL line and the condensate to Cruden Bay via the Forties pipeline system.
Columbus is expected to be producing at its potential by early December.
Production marks the conclusion of the company’s first development project. Serica was involved in the original discovery and has acted as operator through the appraisal and development phases and now into operations.
Serica is operator with 50% interest. Partners are Waldorf Production (25%) and Tailwind (25%).
PROCESSING Quick Takes
Thai Oil lets contract for Sriracha refinery’s clean fuels project
Thai Oil PLC let a contract to a division of Godrej & Boyce Manufacturing Co. Ltd. to supply critical equipment for the operator’s ongoing Clean Fuel Project (CFP) at its 276,000-b/d refinery at Sriracha, in eastern Thailand’s Chonburi province (OGJ Online, Mar. 18, 2020).
In mid-November, Godrej Process Equipment completed supply of a high-pressure separator with a design pressure above 160 bar and a shell-wall thickness of more than 310 mm, which follows earlier delivery of other critical project equipment, including pressure vessels, high-pressure breech-lock heat exchangers, and columns, the service provider said.
Once completed, the CFP will increase the refinery’s overall production of high-quality clean fuels by 45%, according to Godrej & Boyce.
Designed to enhance competitiveness by improving process efficiency and improve quality of transportation fuels to Euro 5-quality standards, the Sriracha CFP—which primarily focuses on reduction of particulate matter and nitrogen oxides (NOx) emissions—will also expand the refinery’s crude processing capacity to 400,000 b/d, allowing the refinery greater flexibility to process a more diverse slate of less expensive crudes (OGJ Online, July 28, 2020).
In its latest annual report to investors, Thail Oil said the CFP—currently under construction—is scheduled to enter commercial operation in 2023.
Alongside expanding processing capacity and increasing clean-fuels production, the Sriracha CFP also included a crude oil tank (CFP C-COT) project to accommodate future increased storage demand. The CFP C-COT reached completion earlier this year, according to Thai Oil.
The operator also confirmed a related project under way aimed at upgrading additional existing units at the refinery to further expand the site’s production of Euro 5-quality fuels. The revamping project is due to be completed by yearend 2022, about 1 year ahead of Thailand’s enforcement of Euro 5 emission standards that will take effect on Jan. 1, 2024, Thai Oil said.
Rosneft opts to buy Shell’s interest in German joint-venture refinery
PJSC Rosneft subsidiary Rosneft Deutschland GMBH has exercised its preemption right to purchase Royal Dutch Shell PLC subsidiary Shell Deutschland Oil GMBH’s 37.5% minority interest in PCK Raffinerie GMBH’s 220,000-b/d refinery in Schwedt, Germany, located along Druzhba pipeline in Schwedt, Germany, about 120 km northeast of Berlin.
Pending necessary government and regulatory approvals, the transaction will increase Rosneft’s shareholding in the German refinery to 91.67% from its current 54.17% interest, Rosneft said in a Nov. 17 release.
Alongside strengthening the refinery’s technology leadership team, Rosneft said it also plans to implement low-carbon projects after finalizing the transaction.
Current projects under development for PCK Rafinerie’s site involve production of cleaner fuels, including sustainable aviation fuel and green hydrogen, which Rosneft confirmed it intends to continue.
Exercise of its preemption right for acquisition of additional interest in PCK Raffinerie effectively cancels Shell’s earlier plan to sell its shares of the Schwedt refinery to Vienna-based Alcmene GMBH, a subsidiary of privately owned Liwathon EOS of Estonia, in a deal that required approval by joint venture partners Rosneft and Eni SPA subsidiary Eni Deutschland GMBH (8.33%) (OGJ Online, July 8, 2021).
Shell previously said divestment of its interest in PCK Raffinerie comes as part of the global operator’s broader ongoing strategy to reduce its global refinery footprint to core sites integrated with the company’s trading hubs, chemicals plants, and marketing businesses (OGJ Online, May 27, 2021; May 5, 2021).
Robin Mooldijk, Shell’s executive vice-president of manufacturing, said sale of the PCK Raffinerie interest will support further development of Shell’s Rheinland energy and chemicals park, which includes Shell Deutschland’s 140,000-b/d refinery at Wesseling, Germany, that together with the former Godorf refinery near Cologne-Godorf, form the 325,000-b/d integrated Rheinland refinery, Germany’s largest.
TRANSPORTATION Quick Takes
Cheniere produces first LNG at Sabine Pass Train 6
Cheniere Energy Partners LP produced LNG for the first time at its 5-million tonne/year (tpy) Train 6 at the Sabine Pass liquefaction project in Cameron Parish, La.
The commissioning process continues, and Cheniere expects substantial completion of Train 6 to be achieved in first-quarter 2022, about 1 year ahead of the guaranteed completion date.
Upon substantial completion, Bechtel Energy Inc. will transfer the completed train to Cheniere Partners, and Sabine Pass’ total production capacity will be about 30 million tpy of LNG.
Full notice to proceed on Sabine Pass Train 6 was issued to Bechtel by Cheniere Partners in June 2019 (OGJ Online, June 3, 2019).
Cheniere owns 100% of the Sabine Pass LNG terminal. Five liquefaction trains are operational. The terminal includes five existing LNG storage tanks with capacity of 16.9 bcf of gas equivalent, two marine berths that can accommodate vessels with nominal capacity of as much as 266,000 cu m, and vaporizers with regasification capacity of 4 bcfd. A third marine berth is under construction.
Through its wholly owned subsidiary Cheniere Creole Trail Pipeline LP, Cheniere also owns a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines.
Woodfibre LNG hires McDermott for EPFC work
Woodfibre LNG Ltd. has signed an engineering, procurement, fabrication, and construction (EPFC) contract with McDermott International. In addition to the EPFC work, McDermott will be responsible for commissioning and start-up.
Preinstallation is planned for early 2022, ramping up to the start of major construction in September 2023. Substantial completion is expected third-quarter 2027. Woodfibre has two offtake agreements in place with bp totaling 1.5 million tonnes/year (tpy), more than 70% of the plant’s designed 2.1-million tpy output (OGJ Online, May 7, 2021).
McDermott will manage onshore construction, leveraging Canadian-based contractors and commitments included in Woodfibre LNG’s impact benefit agreements with the Squamish Nation. The EPFC contract commits McDermott to Woodfibre LNG’s hiring priority for qualified Squamish Nation members and local workers first, followed by British Columbians, and then Canadians.
Woodfibre LNG will be built on a former pulp mill site about 7 km west-southwest of Squamish, BC. It will use a single train driven 100% by hydroelectric power and have storage capacity of 250,000 cu m. McDermott and Woodfibre expect plant design to result in an 86% reduction of carbon dioxide emissions per tonne of LNG produced relative to typical liquefaction operations.
Woodfibre LNG is a subsidiary of Pacific Energy Corp. (Canada) Ltd.
AIE signs FSRU charter with Höegh for Port Kembla LNG terminal
Australian Industrial Energy (AIE), a subsidiary of Western Australian entrepreneur Andrew Forrest’s Squadron Energy, signed a long-term charterparty agreement with global infrastructure and transport group Höegh LNG to supply a floating storage and regasification unit (FSRU) for AIE’s proposed LNG import terminal at Port Kembla south of Sydney in New South Wales.
Under the agreement the vessel, Höegh Galleon, will be berthed at the terminal where construction of berth facilities has begun and is expected to be operational by mid-2023.
The vessel, built in 2019 by Samsung Heavy Industries in South Korea, has a regasification capacity of 750 MMcfd. It is currently on an interim charter with Cheniere Energy in Corpus Christi, Tex.
The $250 million (Aus.) Port Kembla terminal project will receive LNG imports and connect the regassified supply to the existing 800 km Eastern Gas pipeline that runs from Longford in eastern Victoria to Sydney in New South Wales via a new 12-km pipeline from the port.
In addition to the charter agreement, AIE and Höegh agreed to collaborate on the future design and development of a new generation FSRU capable of receiving clean fuels which can be used as part of future green energy supply chains.
Initial feasibility studies on the new FSRU have begun. The vessel is expected to have capability to deliver both natural gas and green hydrogen or its derivatives, a design that AIE plans will unlock further opportunities for the terminal to support a future hydrogen industry in Australia.
AIE is now looking to New South Wales and Victorian natural gas retailers to help resolve the predicted Australian east coast energy security shortfall with offtake contracts for the terminal’s regassified LNG supply.