OGJ Newsletter

Dec. 18, 2023
A roundup of General Interest, Exploration & Development, Drilling & Production, Processing, and Transportation news from around the industry.


Talos expects ‘immaterial’ Q4 impacts from GoM oil leak

Talos Energy Inc., Houston, has reaffirmed its fourth-quarter 2023 operational guidance as it expects the impact related to the Main Pass Oil Gathering pipeline shut-in to be immaterial.

Talos is among seven oil producers whose production has been shut-in since mid-November 2023 in the US Gulf of Mexico following the pipeline’s closure after reports of an oil leak near Plaquemines Parish, southeast of New Orleans, the company said in a release Dec. 7. 

The cause and source of the incident remain under investigation, the United States Coast Guard said in an update Dec. 5. At that time, the entire length of the main pipeline had been assessed, along with 22.16 miles of surrounding pipelines, with no damage or indications of a leak identified.

For fourth-quarter 2023, Talos expects average daily production of 66,500-68,500 boe/d.

Ahead of yearend 2023, Talos anticipates first production from Gulf of Mexico discoveries Venice and Lime Rock. Previously anticipated online in first-quarter 2024, the wells will be tied-back to the Talos-owned and operated Ram Powell platform (OGJ Online, Jan. 4, 2023). Talos owns a 60% working interest in both wells.

Expected combined gross production rates are 15,000-20,000 bo/d, in line with pre-drill estimates. Combined gross recoverable resources are 20-30 MMboe, averaging 40% oil and 60% liquids.

Elsewhere in the Gulf of Mexico, Talos expects a second-half 2024 spud date for the subsalt Daenerys prospect, which will evaluate the Miocene section at a target depth of 26,000-31,000 ft TVDSS, the company noted in a Dec. 5 investor presentation.

Talos is operator of the project through an early 2023 Walker Ridge area farm-in combining 23,000 gross acres with partners Red Willow Offshore LLC, Houston Energy, and Cathexis. Resources are estimated as 100–300 MMboe (gross).

Viking CCS onshore pipeline enters UK government assessment

Harbour Energy’s application to build a 55-km onshore pipeline for its Humber-based 10-million tonne/year Viking Carbon Capture and Storage (CCS) CO2 transportation and storage network in eastern England, is under assessment by the UK’s Planning Inspectorate.

The pipeline would transport CO2 captured in the Immingham industrial area to the former Theddlethorpe gas terminal site on the Lincolnshire coast. From there, the CO2 would be piped 140 km offshore to the depleted Viking gas fields, 2.7 km beneath the seabed, for permanent storage.

The Inspectorate’s assessment is the next stage in Harbour acquiring a development consent order for the pipeline, following consultation and engagement with relevant parties.

Harbour earlier this year won Track 2 status for both Viking and the Acorn CCS project in northeast Scotland as part of the UK Government’s CCS cluster sequencing process, allowing both projects to move into front-end engineering and design discussions with the government ahead of final investment decisions (OGJ Online, July 31, 2023).

Viking would be expandable to 15-million tpy by 2035 and has verified storage capacity of 300 million tonnes.

Inpex granted approval for revised Abadi LNG project with CCS component

Inpex Masela Ltd., an Inpex Corp. subsidiary, received official approval from Indonesian government authorities for its revised plan of development (POD) for the 9.5-million tonne/year (tpy) Abadi LNG liquefaction project in Masela block, Indonesia, incorporating a carbon capture and storage (CCS) component.

INPEX submitted the plan aimed at neutralizing CO2 emitted from natural gas production at Abadi gas field through the introduction of CCS (OGJ Online, Apr. 6, 2023). The field contains an estimated 10.7 tcf of gas.

The project is a joint venture comprised of Inpex Masela (operator, 65%), PT Pertamina Hulu Energi Masela (PHE Masela, 20%), and Petronas Masela Sdn. Bhd. (15%). 

Approval paves the way for the partners to “fully mobilize the project as a clean project in support of the energy transition,” Inpex said in a release Dec. 6.

Going forward, Inpex and its partners will pursue the revision of the production sharing contract to incorporate CCS into the contractual scope of work and resume project operations including on-site activities and prepare for FEED work.

Thereafter, the joint venture aims to reach a final investment decision (FID).

PHE Masela and Petronas Masela became official partners of the project on Oct. 18, 2023, following completion the transfer of Shell’s participating interest (OGJ Online, July 25, 2023; July 8, 2020).

Exploration & Development   Quick Takes

Neptune Energy discovers gas near North Sea Gjøa field

Neptune Energy Norge AS discovered gas at the Kyrre prospect and confirmed volumes for the Ofelia appraisal well, both in the PL 929 license close to Gjøa field in the Norwegian sector of the North Sea.

Neptune completed Ofelia appraisal well 35/6-4 ST2 in the Agat formation. Estimated recoverable volume is 16-33 MMboe.

Additionally, the 35/6-4 A sidetrack was drilled into the overlying Kyrre prospect, resulting in a new gas discovery. Estimated recoverable resources are 11-19 MMboe of gas, bringing the total recoverable volume from both discoveries to about 27-52 MMboe.

Ofelia/Kyrre is a candidate for a fast track, low-cost development tie-back to the Gjøa platform 23 km to the south. Neptune will also evaluate if the company’s Gjøa Nord (Hamlet) oil and gas discovery, with estimated recoverable volumes of 8-24 MMboe, can be jointly developed.

The Gjøa platform is electrified with power from shore.

Wells 35/6-4 ST2 and 35/6-4 A were drilled by the Deepsea Yantai semi-submersible rig, owned by CIMC and operated by Odfjell Drilling.

Neptune Energy is operator at PL 929 (40%) with partners Wintershall Dea Norge AS (20%), Pandion Energy AS (20%), Aker BP ASA (10%), and DNO Norge AS (10%).

PTTEP discovers oil, gas offshore Malaysia

PTT Exploration and Production Public Co. Ltd. (PTTEP) subsidiaries PTTEP HK Offshore Ltd. (PTTEP HKO) and PTTEP Sarawak Oil Ltd. (PTTEP SKO) made oil and gas discoveries in three fields offshore Sarawak, Malaysia.

The discoveries include exploration wells Chenda-1 in Block SK405B, Bangsawan-1 and Babadon-1 in Block SK438, and Sirung-2 appraisal well in Block SK405B. These fields are adjacent to previously discovered areas. All have proven to be high-quality oil and gas reservoirs, especially Babadon-1, revealing massive sweet gas sandstone reservoirs with thickness up to 200 m.

The Sirung-2 appraisal success follows the prior discovery of oil and gas in the Sirung-1 exploration well in 2021. The project is now moving towards engineering study. 

PTTEP’s portfolio in Malaysia consists of Blocks SK405B, SK438, SK314A, SK417, PM407, SB412, and SK325 all of which are in the exploration phase. Lang Lebah and Paprika gas fields in Block SK410B are under development. Block K, SK309, SK311, Block H, and the Malaysia–Thailand Joint Development Area (MTJDA) are in production.

Woodside Trion FPU project adds commissioning contract

Woodside contractor HD Hyundai Heavy Industries Co. Ltd. (HHI) has signed GATE Energy for commissioning of the 100,000 b/d Trion floating production unit (FPU) offshore Mexico.

GATE’s scope includes pre-commissioning and commissioning planning and execution at HHI’s fabrication yard in Ulsan, South Korea.

Woodside took final investment decision (FID) on Trion earlier this year and subsequently received approval for the project from Mexico’s Comision Nacional de Hidrocarburos (OGJ Online, Aug. 30, 2023; June 20, 2023). Trion is in the Perdido fold belt, Gulf of Mexico, 180 km off the Mexican coastline and 30 km south of the Mexico-US maritime border in water depths up to 8,200 ft.   

Trion will be developed with 18 wells (nine producers, seven water injectors, and two gas injectors) drilled in the initial phase and a total of 24 wells drilled over the life of the project. The FPU will connect to a floating storage and offloading (FSO) vessel with a capacity of 950,000 bbl of oil.

Its development is targeting 479 MMboe of best estimate (2C) contingent oil and gas and being undertaken with Pemex Exploración y Producción (40%).  

First oil is targeted for 2028.

Drilling & Production   Quick Takes

Shell takes FID for campaign to boost production at Perdido spar

Shell Offshore Inc., a subsidiary of Shell plc, has taken final investment decision (FID) for a phased campaign to deliver three wells in Great White oil field designed to boost production at the Shell-operated Perdido spar in the US Gulf of Mexico.

After completion of the campaign in April 2025, the wells collectively are expected to produce up to 22,000 boe/d at peak rates, the company said in a release Dec. 12.

Shell is operator at Great White in the southern Alaminos Canyon area with 33.34% interest. Partners are Chevron USA Inc. (33.33%) and BP Exploration & Production Inc. (33.33%).

Perdido, which began production in 2010, lies about 200 miles south of Galveston, Tex., in about 8,000 ft of water. Its production capacity is 125,000 boe/d at peak rates.

Shell is operator of the Perdido regional host with 35% interest. Chevron USA holds 37.5%, 3C Perdido Holdings LLC holds 26.5%, and BP Exploration & Production holds 1%.

bp spuds first ACE platform well

bp PLC spudded the first production well from the new Azeri Central East (ACE) platform for the Azeri-Chirag-Deepwater Gunashli (ACG) field development project in the Azerbaijan sector of the Caspian Sea.

Well spud follows safe completion of all offshore hook up, installation, and commissioning of the ACE topsides unit, which sailed away from the Bayil fabrication yard in August 2023. The well is planned to reach a total depth of as much as 3,188 m in about 3 months.

ACE is a 48-slot production, drilling, and quarters platform mid-way between the existing Central Azeri and East Azeri platforms in 137 m of water. The project also includes new infield pipelines to transfer oil and gas from the ACE platform to the existing ACG Phase 2 oil and gas export pipelines for transportation to the onshore Sangachal terminal.

In addition, there is a water injection pipeline between the East Azeri and ACE platforms to supply injection water from the Central Azeri compression and water injection platform to ACE.

The ACE platform and infrastructure are designed to process up to 100,000 bo/d. The project is expected to produce as much as 300 million bbl over its lifetime.

bp is operator of ACG field.

Suncor expects 2024 production increase of 7%

Suncor Energy Inc. expects its 2024 upstream production to reach 770,000-810,000 b/d, a 7% increase from 2023.

The production increase reflects continued strong existing asset performance, 100% ownership of Fort Hills, changes to the makeup of its exploration and production portfolio—including the sale of its UK North Sea assets—and a full year of production from Terra Nova, the company said in a release earlier this month.

In October, Suncor agreed to purchase TotalEnergies EP Canada Ltd., which holds a 31.23% working interest in the Fort Hills oil sands mining project in Alberta’s Athabasca region for $1.468 billion (Can.) (US$1.1 billion) (OGJ Online, Oct. 4, 2023). The acquisition adds 61,000 b/d of net bitumen production capacity and 675 million bbl of proved and probable reserves to Suncor’s existing oil sands portfolio.

In November, Suncor restarted the Terra Nova floating production, storage, and offloading (FPSO) following completion of the Terra Nova Asset Life Extension project offshore Newfoundland and Labrador (OGJ Online, Nov. 27, 2023). Production is expected to ramp up over the coming months.

In March, Suncor agreed to sell Suncor Energy UK Ltd., which includes Suncor’s non-operated offshore interests in the North Sea, to Equinor UK Ltd. in a deal valued at $1.2 billion (Can.) (OGJ Online, Mar. 3, 2023).

For 2024, Suncor expects refining utilization of 92-96%.

Suncor’s 2024 capital program of $6.3-6.5 billion (Can.) reflects both sustaining and economic capital, including capital for mining fleet upgrades at both Fort Hills and Base Mine, the replacement of the Upgrader 1 coke drums at Base Plant, completion of the Base Plant co-generation project, the continued development of the West White Rose and Syncrude Mildred Lake West Mine Extension projects, the company said.

PROCESSING   Quick Takes

DG Fuels selects process design, technology for Louisiana SAF complex

DG Fuels LLC has let a contract to a subsidiary of Maire SPA’s Rome-based NextChem SPA to deliver a process design package for units at the operator’s sustainable aviation fuel (SAF) production complex under development in St. James Parish, La.

Under the contract, the waste-to-chemical segment of NextChem’s MyRechemical SRL will provide process design and serve as technology licensor of the proposed complex’s gasification and gas treatment units that, together, will be able to process 1 million tonnes/year (tpy) of the complex’s locally sourced agricultural waste as a first step in the site’s SAF manufacturing process, Maire said.

MyRechemical’s gasification and purification technologies will enable the units to specifically process bagasse—the matted, cellulose fiber residue byproduct of post-processed sugarcane stalks—as well as other sugarcane waste and pulp material into suitable feedstock for DG Fuels’ production of zero-carbon SAF, according to the service provider.

DG Fuels’ proposed $4.2-billion Louisiana investment project would involve construction of a very low CO2 lifecycle-emissions complex equipped to produce up to 180 million gal/year of SAF from a feedstock of agricultural and timber waste using the operator’s proprietary high-carbon conversion technology.

DG Fuels said it expects to reach final investment decision (FID) on the Louisiana project in early 2024.

If approved, the plant could be operational in 2028.

The contract follows DG Fuels’ recent contract to Emerson Electric Co. to deliver comprehensive automation and project engineering services for the project, including a suite of advanced sensing, control, systems, equipment monitoring, and production optimization technologies.

Dow lets contracts for proposed Alberta net-zero petrochemicals complex

Dow Inc. has let two contracts to Fluor Corp. to deliver construction-related services for Dow Chemical Canada ULC’s (Dow Canada) petrochemicals manufacturing site under development just north of Fort Saskatchewan, Alta., that will house what the companies describe as the world’s first net-zero carbon emissions ethylene and derivatives complex.

Fluor’s scope of work will cover engineering, procurement, and construction management (EPCM) services for a new ethylene cracker and associated utilities, power, and infrastructure (UPI), the service provider said.

The two reimbursable EPCM services contracts represent a total investment cost (TIC) value of more than $3 billion, Flour said.

Fluor also confirmed Dow’s earlier announcement that the overall program of the Fort Saskatchewan project will involve expansion and retrofit of Dow’s current manufacturing installations at the site which, alongside new construction, would include retrofitting existing units to zero-CO2 emissions as defined by Scope 1 and Scope 2 of the Greenhouse Gas (GHG) Protocol Corporate Accounting and Reporting Standard.

This latest contract follows the operator’s November 2023 positive final investment decision (FID) to advance the development, as well as its contract award to Fluor in February 2023 for front-end engineering and design (FEED) on the project.

Dow has estimated that the complex will decarbonize about 20% of its global ethylene capacity and grow its supply of polyethylene by about 15%, or 2 million tonnes/year (tpy).

Combined with a new cracker that will add about 1.8 million tpy of ethylene capacity in a phased manner through 2030, the overall project will enable Dow to produce and supply about 3.2 million tpy overall of certified low- to zero-carbon emissions polyethylene and ethylene derivatives for global customers and joint venture partners, the operator said.

In 2021, Dow said notable retrofits to Fort Saskatchewan’s current operations would entail upgrading existing infrastructure to accommodate installation of a new autothermal reformer that will convert cracker offgas into clean, circular hydrogen the complex can use to fuel its production processes. The retrofits will also enable introduction of a carbon capture and storage (CCS) component that would allow CO2 from the cracker to be captured on site and transported for storage by an adjacent third party.

With construction on early works having begun in July 2023, startup of Phase 1 of the Fort Saskatchewan growth project is scheduled for 2027, with Phase 2 slated to come online in 2029, Fluor confirmed.


Bulgaria-Serbia natural gas interconnector reaches completion

The 1.8-billion cu m/year (bcmy) Interconnector Bulgaria-Serbia (IBS) natural gas pipeline has been completed. The pipeline will reduce the proportion of Russian gas Serbia consumes, replacing it with supplies from Azerbaijan and Gastrade AE’s 5.5-bcmy LNG terminal in Alexandroupolis, Greece.

Serbia will purchase 0.4 bcmy from Azerbaijan starting in 2024. Azerbaijan exported 8 bcmy to Europe in 2021 and is targeting sales of 20 bcmy there by 2027. The country expects 2023 European exports to be near 12 bcmy. 

Construction of the 170-km reversible pipeline began earlier this year, at which point Serbia received roughly 80% of its gas from Russia (OGJ Online, Feb. 6, 2023). At full capacity IBS could meet about 60% of Serbia’s demand. 

KMI’s Permian Highway pipeline expansion in service

Kinder Morgan Inc. (KMI) increased the capacity of its Permian Highway natural gas pipeline by 550 MMcfd effective Dec. 1, 2023, bringing total capacity to 2.65 bcfd. Permian Highway runs from the Waha hub in West Texas to Katy, Tex., west of Houston.

KMI owns interests in more than 7 bcfd of Permian takeaway capacity and expects to reach more than 9 bcfd by 2030. In addition to Permian Highway, these systems include Gulf Coast Express (2 bcfd to South Texas), El Paso Natural Gas (3 bcfd westbound), and Natural Gas Pipeline Co. of America, which includes 375 MMcfd of northbound capacity.

WhiteWater Midstream LLC and MPLX LP at end-September completed a 500-MMcfd expansion of their Whistler pipeline out of the Permian, increasing capacity to 2.5 bcfd by installing three new compressor stations. Whistler runs from Waha to Agua Dulce, Tex.

The companies expect their 2.5-bcfd Matterhorn Express pipeline from Waha to Katy to enter service third-quarter 2024 (OGJ Online, May 19, 2022). 

DT Midstream reaches mechanical completion of LEAP Phase 2 expansion

DT Midstream Inc. has reached early mechanical completion of its Phase 2 LEAP Gathering Lateral Pipeline expansion. The 400-MMcf/d expansion is now expected to be available for firm service on Jan. 1, 2024.

The high-pressure pipeline currently provides interconnectivity between Haynesville production and Gulf Coast markets.

The second expansion follows the Phase 1 expansion project that was completed in August 2023, and will increase the overall capacity of LEAP to 1.7 bcfd (OGJ Online, Aug. 23, 2023).

In a Dec. 7 investor presentation, DT Midstream said the third-phase expansion remains on track for a third-quarter 2024 in-service date with pipeline crossings complete.

Overall, the multi-phased project will bring LEAP’s total capacity to 1.9 bcfd and provide scalability for further expansions up to 3 bcfd.

Customers on LEAP have access to multiple existing or under construction LNG terminals including Sabine Pass, Cameron, Calcasieu Pass, Plaquemines, and Golden Pass via interconnects with Creole Trail, Cameron Interstate Pipeline, Gillis Access, Texas Eastern, and Transco.

EACOP crude pipeline receives first 100 km of line pipe

East African Crude Oil Pipeline (EACOP) Co. Ltd. has taken delivery of the first 100 km of 24-in. OD line pipe at the port of Dar es Salaam, Tanzania, marking the start of the project’s main construction phase. EACOP will transport 246,000 b/d of crude oil 1,443 km from the Lake Albert region of Uganda to the Chongoleani peninsula near Tanga, Tanzania, for export to world markets.

The 18-m pipe lengths will be transported from the coast to a coating plant at the pipeline’s midpoint for installation of thermal insulation and external protective coating. Insulated pipe will then be transported from the coating plant to a piping yard along EACOP’s right-of-way before being strung out for installation. A total of 16 main camps with piping yards will be sited along EACOP’s route at roughly even intervals.

EACOP includes six pumping stations (two in Uganda, four in Tanzania), two pressure reduction stations, and a marine export terminal at Tanga. The waxy, high-viscosity crude it will transport requires heating the pipeline to more than 50° C.

Power for both the pumping stations and heat will come from a hybrid power generation and distribution package, combining solar farms (in Tanzania), battery banks, and connections to the Ugandan and Tanzania grids, backed up by combustion engine power generation. EACOP estimates a 60% reduction in emissions versus traditional power sources.

Lake Albert crude development includes Tilenga and Kingfisher oil projects and construction of EACOP. Tilenga, operated by TotalEnergies E&P Uganda, and Kingfisher, operated by China National Offshore Oil Corp., are expected to start producing in 2025 and reach a cumulative plateau production of 230,000 b/d (OGJ Online, Feb. 1, 2022).