OGJ Newsletter

Feb. 6, 2023
A roundup of General Interest, Exploration & Development, Drilling & Production, Processing, and Transportation news from around the industry.


TotalEnergies EP Canada to acquire additional Fort Hills interests ahead of planned spin-off

TotalEnergies EP Canada Ltd., a TotalEnergies affiliate, has exercised its preemption right to acquire an additional 6.65% interest in the Fort Hills Energy LP and associated sales and logistics agreements from Teck Resources Ltd., Vancouver, for $312 million (Ca.).

TotalEnergies is exercising its right following an October 2022 deal struck between Teck Resources and Suncor Energy Inc. for Teck’s entire 21.3% interest share in the Fort Hills partnership for $1 billion (Can.). TotalEnergies challenged the deal.

In December 2022, TotalEnergies filed an application in the Court of King’s Bench of Alberta related to the validity of the right of first refusal notice delivered to it by Teck Resources in connection with the sale of Teck’s interest in Fort Hills to Suncor.

TotalEnergies expects to spin off TotalEnergies EP Canada this year as it exits the Canadian oil sands market (OGJ Online, Sept. 9, 2022). The spin-off is planned to be submitted to vote at TotalEnergies’ annual shareholders’ meeting in May. The deal to acquire additional Fort Hills interests will deliver value to the entity, said Jean-Pierre Sbraire, chief financial officer of TotalEnergies, in a release Jan. 27.

Fort Hills is 90 km north of Fort McMurray in the Province of Alberta. Prior to the transaction, TotalEnergies EP Canada held 24.58% working interest in the Fort Hills project. After deal close, TotalEnergies will hold 31.23%.

TotalEnergies EP Canada also holds a 50% working interest in the Surmont project in the region. 

Chevron lets pipeline contract for Tamar field expansion

Chevron Mediterranean Ltd. has let a contract to Corinth Pipeworks SA to manufacture and supply about 155 km of 20-in. longitudinally submerged arc welded steel pipes for Tamar gas field in the Southeastern Mediterranean.

The project will connect the subsea manifold at a maximum water depth of 1,700 m to the offshore platform where gas will be processed before being transported to shore in Israel.

Pipes will be manufactured in Corinth Pipeworks’ facilities in Greece, and installation will start in 2024. Scope of supply also includes internal and external anticorrosion coating, applied at the same location as pipe manufacturing at Thisvi, Greece.

Tamar lies 90 km west of Haifa about 5,000 m subsea. Natural gas is extracted through five production wells and gas flows through two 140-km pipelines to the Tamar platform where most of the gas processing takes place. Gas is then transmitted via pipeline to the onshore terminal in Ashdod, and into the Israeli market through the INGL national gas pipeline with a portion exported to Jordan and Egypt. 2P reserves in the Tamar lease, after production of more than 69.3 billion cu m, is about 300 billion cu m of natural gas and 14 million bbl of condensate (OGJ Online, Sept. 2, 2021).

The contract is part of the operator’s first phase to expand field production to about 1.6 bcf of natural gas.

Chrevron is operator of the Tamar project with 25% interest. Partners are Mubadala Energy (22%), Isramco (28.75%), Tamar Petroleum (16.75%), Dor Gas (4%), and Everest (3.5%).

Repsol acquires Eagle Ford assets from INPEX

Repsol Oil & Gas USA LLC, a Repsol subsidiary, has acquired INPEX Eagle Ford LLC from parent company INPEX Corp. A purchase price was not disclosed.

With the sale, INPEX exits its Eagle Ford tight oil development and production activities, the company said in a release Feb. 1.

INPEX entered the US tight oil business through acquisition of the Eagle Ford assets in April 2019 from GulfTex Energy. Most of the assets acquired were in in Karnes County, Texas.

Repsol acquired Eagle Ford assets in November 2019 through a $325-million deal with former partner Equinor, through which it became asset operator (OGJ Online, Nov. 18, 2019). That deal saw Repsol acquire some 70,000 net acres and 34,000 boe/d of production.

Exploration & Development Quick Takes

ExxonMobil adds to Stabroek block resource estimate with new discovery

ExxonMobil discovered oil in the Stabroek block, offshore Guyana, at Fangtooth SE-1, about 8 miles southeast of the original Fangtooth-1 discovery, partner Hess Corp. said in its Jan. 25 quarterly earnings report (OGJ Online, Jan. 5, 2022; Jan. 26, 2023).

The Fangtooth SE-1 well encountered about 200 ft of oil bearing sandstone reservoirs, Hess said, noting the discovery adds to the block’s gross discovered recoverable resource estimate of more than 11 billion boe and has the potential to underpin a future oil development.

ExxonMobil affiliate Esso Exploration and Production Guyana Ltd. is operator at Stabroek block (45%) with partners Hess Guyana Exploration Ltd. (30%) and CNOOC Petroleum Guyana Ltd. (25%).

bp to receive Tortue Ahmeyim FPSO

The floating production, storage, and offloading (FPSO) vessel for the bp-operated Greater Tortue Ahmeyim (GTA) LNG project set sail Jan. 20.

The FPSO left the COSCO shipyard in Qidong, China, following completion of a series of sea trials after 3.5 years of construction. It will travel 12,000 nautical miles via Singapore to its destination 75 miles offshore on the maritime border of Mauritania and Senegal in 9,350 ft of water.

The FPSO is part of the GTA development that also includes subsea development of gas fields and floating LNG (FLNG) liquification 10 km offshore. The FPSO will process natural gas, removing condensate, water, and other impurities. Most of the gas will be liquefied by the FLNG, enabling export to international markets, while some is allocated to help meet growing demand in the two host countries. Condensate will be periodically transferred from the FPSO to shuttle tankers for export to market.

With eight processing and production modules, the FPSO will process around 500 MMscfd. The project’s first phase is set to produce around 2.3 million tonnes/year of LNG.

Tortue Ahmeyim field development is on the C-8 block offshore Mauritania and the Saint-Louis Profond block offshore Senegal. The field holds estimated gas resources of 15 tcf. The integrated gas value chain and near-shore LNG development will export LNG to global markets as well as supplying gas to Senegal and Mauritania.

bp operates Tortue with 61%. Partners are Kosmos 29%, Senegal-state Petrosen 5%, and Mauritania state firm SMHPM 5%.

Eni to jointly develop gas project offshore Libya

Eni SPA and the National Oil Corp. of Libya (NOC) agreed to jointly develop a gas project in contractual area D, offshore Libya.

In a release Jan. 28, Eni said the project is aimed at increasing gas supply to the Libyan domestic market as well provide exports to Europe.

The project includes development of gas fields Structure A and Structure E. Combined gas production startup is expected in 2026. A plateau of 750 MMscfd is expected.

Gas will be produced through two main platforms tied into the existing treatment plants at the Mellitah complex. The project also includes construction of a carbon capture and storage (CCS) plant at Mellitah. Estimated overall investment is $8 billion.

Eni produces 80% of Libyan gas (1.6 billion scfd in 2022). Operations are run through the joint company Mellitah Oil and Gas BV (Eni 50%, NOC 50%).

Drilling & Production Quick Takes

Neptune Energy adds production at Cygnus field

Neptune Energy has started drilling the eleventh well on Cygnus field, which is expected to begin production in this year’s second quarter. The progress follows the recent start of production from the tenth well at the Neptune-operated field in the UK southern North Sea.

With the start-up, the Neptune-operated Cygnus gas infrastructure is now capable of producing enough natural gas to meet the needs of about 2 million UK households, the company said in a release Feb. 1.

Drilling was carried out by Borr Drilling’s Prospector 1 jack-up rig, the first in Borr’s fleet to be equipped with technologies that reduce carbon and nitrogen emissions from operations by up to 95%, and particle matter emissions by more than 85%, the operator said.

Neptune is operator of Cygnus field with 38.75%. Spirit Energy holds 61.25%.

Wintershall Dea to perform multiple North Sea field well interventions

Wintershall Dea Norge AS has been given consent by the Petroleum Safety Authority Norway (PSA) to use the Island Constructor mobile drilling unit for light well intervention on Dvalin, Maria, Nova, and Vega fields.

Dvalin is in the central part of the Norwegian Sea and consists of two separate structures, Dvalin East and Dvalin West. Dvalin East was proven in 2010 and is 15 km northwest of Heidrun field in 344 m of water. Dvalin West was proven in 2012 and is 3.5 km west of Dvalin East in 400 m of water. The development concept is a subsea template with four gas producers tied-back to the Heidrun platform. Production started in 2020.

Maria is on Haltenbanken in the Norwegian Sea, 25 km east of Kristin field in 300 m of water. The field is developed as a subsea tie-back with two templates. There are five producers and two water injectors on the field. Production started in 2017.

Nova is in the northern part of the North Sea, 17 km southwest of Gjøa field in 370 m of water. The planned development consists of two 4-slots subsea templates, one for oil production and one for water injection, each with three wells tied-back to the Gjøa platform. Production started in 2022.

Vega is in the northern part of the North Sea, 28 km west of Gjøa field in 370 m of water.  The field has been developed with three subsea templates with four slots, tied to the processing facility on the Gjøa field. Production started in 2010.

Wintershall Dea is operator of the fields. 

Karoon completes Patola development drilling offshore Brazil

Karoon Energy Ltd., Melbourne, has completed its two-well development drilling and completion program in Patola oil field in the Santos basin off the Brazilian coast near Sao Paulo.

The Noble Developer rig installed wellheads and Christmas trees with work to begin shortly to install the remaining subsea infrastructure, including flowlines, umbilicals, and sundry pipework, the company said.

The field, in Karoon’s 100%-owned concession BM-S-40 in 280 m of water, will be developed as a subsea tie-in to the Cidade de Itajai floating production, storage, and offtake vessel that is currently producing the company’s nearby Baúna field.

Commissioning of the new infrastructure and first production from Patola is scheduled to begin by the end of first-quarter 2023.

Patola field was discovered in 2011. Karoon made final investment decision for development in June 2021. Oil will be produced from an Oligocene-age turbidite sandstone reservoir.

Contingent 2C resources are estimated to be 13 million bbl and initial production from the two vertical wells will be around 10,000 b/d.

The rig is being mobilized to drill the BAN-1 intervention well in Baúna field center. The well is expected to reopen a lower oil zone that had previously been in production.

On completion of BAN-1, the rig will move to nearby Neon field to drill the first of two control wells.


ExxonMobil lets contract for Baytown blue hydrogen project

ExxonMobil Corp. has let a contract to Technip Energies to deliver critical engineering and design services for a grassroots low-carbon hydrogen production plant and carbon capture and storage (CCS) plant proposed for construction at the operator’s 561,000-b/d integrated refining and petrochemical complex in Baytown, Tex. (OGJ Online, Mar. 3, 2022).

As part of the late-January contract, Technip Energies will provide front-end engineering and design (FEED) of the Baytown hydrogen plant that would be equipped to produce up to 1 bcfd of blue hydrogen, or hydrogen produced natural gas, and supported by CCS infrastructure for capturing about 7 million tonnes/year (tpy), or more than 98%, of associated carbon dioxide (CO2) emissions from the site for permanent storage, ExxonMobil and the service provider said in separate releases.

Part of ExxonMobil’s strategy to reduce emissions from its own and local industry operations, the proposed Baytown low-carbon hydrogen, ammonia, and CCS plant would allow the site to manufacture lower-emissions products for its own customers but also make surplus volumes of hydrogen and ammonia, as well as CO2 storage capacity, available to nearby industry.

While it does not plan to reach a final investment decision (FID) on the development until 2024, ExxonMobil said it has already started discussions with third-party customers for offtake agreements from the project that, if approved, would reach startup in 2027-28.

Upon first announcing the project in March 2022, ExxonMobil said use of hydrogen produced by the planned project as a fuel at the Baytown olefins plant could reduce the integrated complex’s CO2 emissions as defined by Scope 1 and Scope 2 of the Greenhouse Gas (GHG) Protocol Corporate Accounting and Reporting Standard by up to 30%, supporting the operator’s ambition to achieve net-zero greenhouse gas (GHG) emissions from its operated assets by 2050.

Imperial Oil takes FID on Strathcona refinery renewables project

ExxonMobil Corp.’s majority owned affiliate Imperial Oil Ltd. has taken positive final investment decision (FID) to move forward with its previously proposed plan to build a grassroots renewable diesel production complex at the operator’s 196,000-b/d Strathcona refinery near Edmonton, Alta., in western Canada (OGJ Online, Aug. 25, 2021).

At an estimated investment of about $560 million, the renewable diesel project will include construction of a new complex that combines low-carbon hydrogen—or hydrogen produced from natural gas with carbon capture and storage (CCS) technology—locally sourced renewable feedstocks, and a proprietary catalyst to produce more than 1 billion l./year (roughly 20,000 b/d) of low-carbon, renewable diesel for supply to British Columbia’s transportation sector and for reuse by the refinery itself, Imperial Oil and ExxonMobil said separately on Jan. 26.

Still awaiting final regulatory approval but with site preparation and initial construction works already under way, Strathcona refinery’s renewable diesel production—which could help reduce overall greenhouse gas (GHG) emissions in Canada’s transportation sector by about 3 million tonnes/year (tpy)—is currently planned for startup in 2025, the companies said.

Imperial Oil’s confirmation of FID on the Strathcona renewables project follows the operator’s previous contract awards to Fluor Corp. for delivery of front-end engineering and detailed design (FEED) and engineering and procurement (EP), as well as Air Products Inc. for supply of low-carbon hydrogen to complex (OGJ Online, Oct. 25, 2022; Sept. 6, 2022).

If realized, Strathcona’s renewable diesel complex would become the largest of its kind in Canada.

Part of Imperial’s commitment to supporting Canada’s Clean Fuel Regulation and the country’s ambition to achieve net-zero emissions by 2050, ExxonMobil said the Strathcona renewables complex also supports its proposed corporatewide plan to invest about $17 billion through 2023 on lower-emission initiatives, particularly in regions with clear regulatory policies aligned with a lower-carbon economy.

Upon first announcing the proposed project in August 2021, Imperial Oil confirmed the government of British Columbia would support the project in the form of credits under its provincial low carbon fuel standard (BC LCFS).

Renewable SAF project progresses in South Dakota

Gevo Inc. is progressing with development of its planned Net-Zero 1 (NZ1) project for production of sustainable aviation fuel (SAF) on a 245-acre site near Lake Preston, SD.

Since breaking ground on the project in September 2022, Gevo, by mid-January 2023, has substantially completed front-end engineering and design (FEED) on NZ1, with detailed engineering ongoing and equipment procurement set to begin soon, the operator said.

With detailed planning already under way for this year’s construction activities already under way, Gevo confirmed the NZ1 SAF project remains on schedule for operational startup in 2025.

First announced in January 2021 and designed to include carbon capture and storage (CCS) as well as on-site renewable electricity generation via a combined heat and power system, the NZ1 SAF project, if realized, will use a feedstock of renewable materials to produce 55 million gal/year of SAF that—when burned—will have potential to achieve net-zero greenhouse gas (GHG) emissions across the entire lifecycle, Gevo said.

Gevo—which confirmed recent selection of a yet-to-be-identified engineering, procurement, and construction (EPC) contractor for the development—said it plans to finalize the EPC contract and reach final investment decision for NZ1 by yearend 2023.


Uganda approves EACOP, construction to start late 2023

Uganda has approved East African Crude Oil Pipeline (EACOP) Co. Ltd.’s application to build the 300,000-b/d pipeline, with construction expected to start in November 2023. EACOP will be developed jointly by Uganda and Tanzania, with the latter also committing to the project.

EACOP will carry crude 897 miles from Kabaale, Hoima district, Uganda, to the Port of Tanga, Tanzania, for export to the international market. Ugandan rights-of-way are still being acquired.

The buried, heated 24-in. OD pipeline will cost roughly $4 billion. EACOP Co. Ltd. includes affiliates of upstream partners Total Energies E&P Uganda (62%), Uganda National Oil Co. (UNOC, 15%), and China National Offshore Oil Corp. (CNOOC) Uganda (8%), with the remaining 15% held by Tanzania Petroleum Development Corp. (TPDC).

The four companies last year took final investment decision on the Lake Albert development project in Uganda, which includes Tilenga and Kingfisher oil projects and construction of EACOP. Tilenga, operated by TotalEnergies, and Kingfisher, operated by CNOOC, are expected to start producing in 2025 and reach a cumulative plateau production of 230,000 b/d.

Deutsche Ostsee LNG terminal final commissioning under way

Deutsche ReGas GMBH & Co. KGaA’s 5.2-billion cu m/year (bcmy) Deutsche Ostsee LNG terminal has received its operating license and is in the final stages of commissioning. Final commissioning includes TotalEnergies SE’s Neptune floating storage and regasification unit (FSRU), small-scale LNG shuttle vessels, and associated infrastructure.

Deutsche ReGas plans to more than double Deutsche Ostsee’s regasification capacity by 2025. The company also plans to install a second FSRU-based terminal by end-2023 which, alongside a number of potential capacity upgrades, could increase its import capacity to 13.5 bcmy.

Deutsche Ostsee, in Lubmin, Germany, delivered first gas in January. It utilizes existing port and natural gas network infrastructure to minimize direct environmental impact.

The German Government has committed to diversifying its gas-supply options to ensure reliable access to natural gas and last year passed the LNG Acceleration Act to speed deployment of LNG terminals in the country. Germany expects to have 37 bcmy of import capacity in place by 2024. The country’s gas consumption in 2021 was 93.6 bcm.

Macquarie Capital and its 100%-owned portfolio company, WaveCrest Energy LLC, have supported Deutsche Ostsee with two rounds of investment into Deutsche ReGas. 

Port Arthur LNG Phase 1 offtake fully subscribed with latest agreement

Sempra Infrastructure has agreed to supply LNG from its 13.5-million tonnes/year (tpy) Port Arthur LNG Phase 1 project under development in Jefferson County, Tex., to PKN ORLEN SA. With the agreement, the projected LNG offtake capacity for Phase 1 is now fully subscribed under binding long-term agreements, Sempra said in a release Jan. 25.

PKN ORLEN will purchase some 1 million tpy of LNG on a free-on-board basis for 20 years to increase diversification of its import portfolio and secure additional volumes of natural gas, “which will be used both to provide for the needs of the Polish customers and to enhance PKN ORLEN’s presence in the international energy market,” PKN ORLEAN said.

Sempra Infrastructure has existing long-term agreements with ConocoPhillips, INEOS, ENGIE, and RWE for LNG from the proposed Phase 1 project. In aggregate, Port Arthur LNG Phase 1 is now fully subscribed with 10.5 million tpy under binding long-term agreements.

A final investment decision on the project is expected in this year’s first quarter, with first cargo deliveries expected in 2027.

Port Arthur LNG Phase 1 is permitted and expected to include two natural gas liquefaction trains and LNG storage tanks and associated infrastructure. A similarly sized Port Arthur LNG Phase 2 project is under active marketing and development, the company said.