GENERAL INTEREST Quick Takes
Australian government to permit fracturing in Beetaloo
The government of Australia’s Northern Territory has given the green light to hydraulic fracturing operations in the Beetaloo basin gas reservoirs, clearing the way for an expansion of exploration, appraisal, and development drilling to unlock potential gas production from the region.
The Territory’s Chief Minister Natasha Fyles said that it has satisfied all 135 recommendations of a scientific report arising from the independent Pepper inquiry into fracturing that was commissioned following a lifting of the government’s fracturing moratorium in 2018 (OGJ Online, Apr. 23, 2018).
The inquiry found that industry risks could be managed if its recommendations were implemented in full.
Fyles said that the ambition to be a net-zero emission economy as soon as possible has not wavered, but an energy source is still required as the Territory and Australia move towards that goal.
She said the Northern Territory has strengthened government agencies as well as legislation to rigorously assess environmental management plans. A new petroleum operations unit has been formed to ensure compliance.
Gas developers can now apply for development licenses in the Beetaloo acreage.
Nevertheless, the controversial decision has raised the ire of environmental and indigenous groups who still oppose any development.
Mitsui E&P acquires south Texas unconventional asset
Mitsui E&P USA LLC, a wholly owned subsidiary of Mitsui & Co. Ltd., completed acquisition of about 92% working interest in an unconventional gas asset in south Texas from operator Silver Hill Eagle Ford E&P LLC, a subsidiary of Silver Hill Energy Partners LP.
This asset, part of the 8,500-acre Hawkville field, has access to the Gulf Coast industrial area, which includes LNG export terminals and ammonia plants. With further development, gas production from this asset is expected to produce over 200 MMscfd, according to Mitsui.
Mitsui E&P will be operator of the asset.
Operators report no major damage from Alberta fires to oil, gas infrastructure
Wildfires in and around Alberta forced community evacuations throughout the region. Oil and gas operators took precautions, but there were no reports of major damage to energy infrastructure as of May 10.
On May 10, Crescent Point Energy Corp. said it had restored about 75% of the production previously shut in due to the wildfire risk. No damage to its assets was reported. Days earlier, on May 8, Crescent Point said it had temporarily shut in about 45,000 boe/d of Kaybob Duvernay production.
Also on May 8, Vermilion Energy Inc. said it was monitoring operations in West Central Alberta and temporarily shut-in some 30,000 boe/d of production while it assessed the risk to operations. The company’s assessment at the time indicated minimal damage to “key,” unspecified infrastructure.
NuVista Energy Ltd. temporarily shut in and depressured all operations in proximity to fires in the Grande Prairie region as a precautionary measure, it said in a release May 8.
The shut-ins began partially on May 5, and were then broadened by the shut-in of third-party infrastructure which serves its production, it said. NuVista said the temporary production impact was about 40,000 boe/d. The company said it was not aware of damage to any company or third-party assets and infrastructure.
Also curtailing Grande Prairie operations was Pipestone Energy Corp. The wildfires resulted in the precautionary shut-in of about 20,000 boe/d of production since the evening of May 5, the company said in a release May 8. Pipestone, too, said it was not aware of any significant damage or loss to its owned or third-party infrastructure.
Cenovus Energy Inc. began shutting in some of its conventional production operations and processing plants on May 4 due to the wildfire activity.
About 85,000 boe/d of production, primarily dry gas, was impacted in the company’s Rainbow Lake, Kaybob-Edson, Elmworth-Wapiti, and Clearwater operating areas, the company said in a release May 8.
The company’s other assets, including its oil sands assets and Lloydminster complex, had not been impacted, Cenovus said at the time.
Exploration & Development Quick Takes
Equinor sanctions BM-C-33 development offshore Brazil, awards contracts
Equinor has taken final investment decision to develop the BM-C-33 project in the Campos basin offshore Brazil.
The project comprises three different pre-salt discoveries—Pão de Açúcar, Gávea, and Seat—containing natural gas and oil/condensate recoverable reserves over 1 billion boe, the operator said in a release May 8.
The license, which lies about 200 km from shore in water depths up to 2,900 m, will be developed through a floating production, storage, and offloading (FPSO) vessel with processing capacity of 16 million cu m/d of gas and average natural gas export flow of about 14 million cu m/day.
Start-up is expected in 2028. Oil and gas reserves of over 1 billion boe are expected to be recovered.
The FPSO will be Equinor’s second in Brazil using combined cycle gas turbines, reducing carbon emissions during operations. The average CO2 intensity of BM-C-33 over its lifetime is expected to be lower than 6 kg/boe, the operator said.
BM-C-33 will be the first project in Brazil to treat gas offshore and be connected to the national grid without further onshore processing. Gas is expected to be exported through a 200-km offshore gas pipeline from the FPSO to Cabiúnas, in Macaé, Rio de Janeiro. Liquids will be offloaded by shuttle tankers.
Gas exported from the project could represent 15% of the total Brazilian gas demand at start-up.
Equinor awarded a contract for subsea umbilicals, risers and flowlines (SURF) to TechnipFMC. The award includes delivery of subsea tree systems, manifolds, jumpers, pipeline end terminations, and subsea distribution and topside control equipment.
An agreement was signed with MODEC Inc. for the 2027 delivery of the FPSO. MODEC will provide FPSO operations and maintenance service for the first year from start-up, after which Equinor expects to operate the unit.
Equinor is operator of BM-C-33 with 35% interest. Partners are Repsol Sinopec Brasil (35%), and Petrobras (30%).
TPAO discovers large field onshore Turkey
State-owned Turkish Petroleum Corp. (TPAO) made a large discovery in exploration well S,ehit Aybüke Yalçın-1 in the frontier Cudi-Gabar area, 20 km northwest of Cizre and 7 km northeast of S,ehit Esma Çevik field, onshore Turkey.
The well was drilled to 2,771 m TD and encountered more than 162 m of light oil-bearing reservoir (41° API) in Cretaceous carbonates. The well is flowing at 10,000 b/d.
The new discovery has 1-billion bbl estimated OIP and is the largest oil discovery onshore in Turkey with further prospects to be explored in the frontier Cudi-Gabar area.
TPAO will drill back-to-back appraisal wells and conduct well tests until end 2023 to construct a full-field development plan. Field test production has begun, and the field is expected to produce 100,000 b/d, doubling Turkey’s oil production.
A front-end engineering and design agreement has already been signed for the pipeline.
TPAO holds 100% interest in blocks AR/TPO/K/M48-D2, D3, D4 and AR/TPO/K/N48-A1, A3, A4 in Cudi-Gabar.
LLOG awards Gulf of Mexico project development contract to Subsea 7
LLOG Exploration Offshore LLC has let a contract to Subsea 7 SA to serve as project manager for Salamanca development, which includes Leon and Castile fields, in the US Gulf of Mexico. The service provider values the contract at $50-150 million.
Contract scope includes the installation of three infield subsea pipeline systems, as well as the design and fabrication of subsea structures. Subsea development will consist of two pipeline systems for Leon field in Keathley Canyon 686, and one pipeline system for Castile field in Keathley Canyon 736. The infield pipelines will produce and flow from wellsite PLETs to the Salamanca floating production system (FPS) in water depths of 1,800-2,000 m.
The work scope also includes installation of oil and gas export pipelines which depart from the Salamanca FPS and tie into existing pipeline transport systems about 48 km away, the service provider said.
Project management and engineering will begin immediately at Subsea7’s office in Houston, Tex., with offshore activity expected to begin in 2024.
Drilling & Production Quick Takes
Neptune Energy begins production from Fenja field
Neptune Energy has started production from Fenja oil and gas field in the Norwegian Sea.
The field, which lies 120 km north of Kristiansund at water depth of 325 m, is expected to produce 35,000 boe/d gross, via two oil producers, with pressure support from one water injector and one gas injector.
Development consists of two subsea templates tied back to Equinor-operated Njord A platform. A 36-km electrically trace-heated (ETH) pipe-in-pipe solution transports oil from Fenja to Njord A for processing and transport. Due to the high wax content of the oil, the pipeline contents must be warmed up above 28° Celsius before starting flow after a shut down. During normal production, the temperature in the pipeline is well above 28° Celsius.
The tie-back to Njord A is the world’s longest ETH subsea production pipeline, Neptune said.
Total reserves are estimated at 50-75 MMboe, of which 75% is oil and 25% is gas.
Neptune Energy is operator of the license with 30% interest. Partners are Vår Energi ASA (45%), Sval Energi AS (17.5%), and DNO (7.5%).
Petrobras starts FPSO as part of Campos basin revitalization plan
Petróleo Brasileiro SA (Petrobras) began recovery of mature assets offshore Brazil with the start of production from the Anna Nery floating production, storage, and offloading (FPSO) vessel on May 7, 2023.
The FPSO is part of a $16-billion project to revitalize Marlim and Voador oil and gas fields, which will produce postsalt reservoirs, and Brava, in the presalt of the two fields, the company said.
The FPSO is anchored in a water depth of 927 m and interconnected to 32 wells. It can produce up to 70,000 b/d of oil and process 4 million cu m of gas. Peak production is scheduled for 2025.
The Anna Nery FPSO, together with the Anita Garibaldi FPSO, make up the first major revitalization project for mature fields in Brazil’s Campos basin. Deployment of the two new production systems provides operational continuity to Marlim and Voador fields, increasing production to an average 150,000 boe/d, and contributing to a projected increase in Campos basin production recovery to 900,000 boe/d in 2027 from the current 560,000 boe/d, Petrobras said.
EnQuest to supply additional gas to Malaysia
EnQuest will provide additional gas from Seligi field, a shallow water field offshore Malaysia, until end-2025 through existing infrastructure in support of Peninsular Malaysia’s gas demand.
The agreement, signed with Petronas, is expected to increase EnQuest’s gas production by about 25 MMscfd (50 MMscfd gross), initially from associated gas. The partnership is considering drilling additional gas-producing wells over time, EnQuest said in a release May 9.
Seligi, a producing conventional oil field in Block PM 8 in water depth of 164 ft, is expected to recover 12.49 MMboe comprised of crude oil and condensate.
EnQuest is operator at Seligi with 50% interest. Petronas holds the other 50%.
PROCESSING Quick Takes
PBF Energy, Eni complete unit for Louisiana renewable fuels project
PBF Energy Inc. and partner Eni SPA subsidiary Eni Sustainable Mobility SPA (ESM) have completed construction on the main production unit of 50-50 joint venture St. Bernard Renewables LLC’s (SBR) new biorefinery co-located and still partially under development at PBF Energy subsidiary Chalmette Refining LLC’s 185,000-b/d dual-train coking refinery in Chalmette, St. Bernard Parish, La.
After reaching mechanical completion during first-quarter 2023, the SBR project’s renewable diesel production unit has been turned over to operations, with the first feedstocks scheduled for introduction to the unit this month, PBF Energy told investors in its latest earnings release on May 5.
Construction remains under way on a pretreatment unit at the manufacturing site that, once online, will allow SBR to process renewable materials such as soybean oil, corn oil, and other biogenically derived fats and oils into feedstocks for the production unit.
With the pretreatment anticipated to reach mechanical completion in June, PBF Energy said in its regulatory filing for first-quarter 2023 that it expects SBR’s Chalmette plant to be producing renewable diesel and other products sometime during first-half 2023.
At a total projected cost of $650-700 million, the SBR renewables plant and related project infrastructure comes as part of PBF Energy’s proposed JV with ESM that, formed in February, is scheduled to be finalized during third-quarter 2023, subject to customary closing conditions, including regulatory approvals (OGJ Online, Apr. 3, 2023).
Once fully operational, SBR’s on site pretreatment unit will enable upgrading of about 1.1 million tonnes/year (tpy) of renewable materials into feedstocks for an idled, conventional hydrocracking unit that has been retrofitted with the Eni-Honeywell UOP LLC codeveloped proprietary Ecofining process technology to produce 20,000 b/d of renewable diesel (OGJ Online, Aug. 23, 2021).
Vertex Energy’s Mobile refinery begins renewable diesel production
Houston-based Vertex Energy Inc. has commissioned the first phase of its renewable diesel conversion project at Vertex Refining Alabama LLC’s 75,000-b/d refining and petrochemical complex in Mobile, Ala.
With a planned production capacity of 8,000-10,000 b/d, Phase 1 of the project—which reached mechanical completion on Mar. 31—is now producing renewable diesel from a primary feedstock of locally sourced soybean oil, Vertex said on May 1.
The first $115-million phase of the project involved the conversion of a standalone hydrocracking unit at the refinery that previously produced olefins as feedstock for petrochemical manufacturers.
While soybean oil serves as Phase 1’s initial feedstock, the plant’s design will enable production of renewable diesel from a range of organic, pretreated feedstocks that—alongside soybean oil—includes corn oil, meat tallow, and waste vegetable oils, among others, much of which Vertex plans to secure from local farmers and suppliers.
Formal startup of the project’s Phase 1 production follows Vertex’s mid-April confirmation that it had increased its first-quarter 2023 capital expenditure guidance to $65-70 million from $30-35 million, the result of moving $35 million of planned second-quarter spending to accommodate some items related to Phase 2 of the renewable diesel project.
Vertex said additional hydrogen production infrastructure and equipment had already arrived on site in preparation for Phase 2 development.
Designed to expand renewable diesel production to 14,000 b/d, Phase 2 involves the addition of a new hydrogen plant that is slated for startup by yearend 2023.
In February 2022, Idemitsu Apollo Renewable Corp. entered a master offtake agreement with Vertex to purchase all of the Mobile refinery’s renewable diesel production up to a maximum volume of 14,000 b/d, provided it meets certain specifications, according to Vertex’s 2022 annual report.
Marathon reports on conventional, renewables refining projects
Marathon Petroleum Corp. (MPC) dedicated the bulk of its first-quarter 2023 capex to advancing its balanced approach of optimizing traditional crude oil refining operations while furthering projects in preparation for a low-carbon future.
Of the total $430 million in capital expenditures and investments during the first quarter, MPC dedicated $421 million—up $177 million compared with first-quarter 2022—to ongoing traditional and renewables refining projects, the operator said on May 2.
In its quarterly earnings report to investors, MPC confirmed that it has completed its South Texas Asset Repositioning (STAR) program at the 593,000-b/d Galveston Bay refinery in Texas City, Tex., which included works to further integrate the operator’s former Texas City refinery into the adjacent Galveston Bay refinery to improve the site’s efficiency and reliability by increasing residual oil processing capabilities, upgrading the crude unit, and integrating logistics.
Officially started up in April and scheduled to ramp up throughout second-quarter 2023, the Galveston Bay STAR project, upon reaching full operation, aims to add 40,000 b/d and 17,000 b/d of incremental crude and resid processing capacity, respectively, at the site, MPC said.
Alongside unidentified projects designed to help reduce future operating costs and improve the competitive position across the operator’s US refining assets, MPC said other first-quarter capex covered expenses related to an emissions-reduction program are under way at the 363,000-b/d Los Angeles refinery, as well as furthering second-phase works for the conversion of the former Martinez, Calif., conventional crude refinery into a renewable fuels production site.
Part of its Martinez Renewables LLC 50-50 joint venture with Neste Corp., MPC confirmed Phase 1 of the Martinez conversion project reached its full production capacity for renewable diesel of 260 million gal/year during the first quarter, as planned.
With construction activities currently on schedule for Phase 2 and pretreatment capabilities for renewable feedstocks at the site due online during second-half 2023, MPC said it expects Martinez Renewables to reach full nameplate production capacity of 730 million gal/year by yearend.
TRANSPORTATION Quick Takes
Sempra’s Energia Costa Azul LNG Phase 1 on track for 2025 operations
Sempra Infrastructure’s 12.4-million tonne/year (tpy) Energía Costa Azul LNG Phase 1 plant remains on track to reach commercial operations by third-quarter 2025. Sempra last year received US Department of Energy permission to increase the amount of LNG it would be allowed to export to countries with which the US did not have a free trade agreement.
Energia Costa Azul is under development at Sempra’s existing LNG import terminal in Ensenada, Baja California, Mexico, along the Pacific Coast. It is also developing the greenfield 4-million tpy Vista Pacifico LNG plant in Topolobampo, Sinaloa, Mexico, from which it expects to begin exports in 2027.
In first-quarter 2023, Sempra’s 6.75-million tpy Cameron LNG Phase 2 project in Hackberry, La., received approval from the Federal Energy Regulatory Commission (FERC) for modifications to its expansion permit. The modifications approved by FERC include using electric-drive motors to replace gas turbine drives, which is expected to lower the overall direct onsite emissions of Phase 2 compared with the previously authorized project and will also allow the tie-in of carbon capture and sequestration equipment into Phase 1 to further reduce overall plant emissions.
The new train being added as part of Phase 2, combined with debottlenecking the three existing 4.5-million tpy trains, will bring Cameron LNG’s total capacity to more than 20.25 million tpy. Sempra’s partners in Cameron LNG are TotalEnergies SE, Mitsui & Co., and Japan LNG Investment LLC.
ADNOC to supply LNG to TotalEnergies Gas and Power
ADNOC Gas PLC has agreed to sell TotalEnergies Gas and Power Ltd. LNG for a 3-year term starting this year. The gas supplied will be used by TotalEnergies to meet its global commitments.
“We are pleased to have signed this 3-year contract with our long-standing strategic partner,” said Thomas Maurisse, senior vice-president LNG at TotalEnergies. “These additional volumes will strengthen our global LNG portfolio, our ability to supply the growing Asian markets, and our ambition to accompany our customers in their energy transition.”
ADNOC estimates the value of the agreement at as much as $1.2 billion. Abu Dhabi National Oil Co. (ADNOC) formed ADNOC Gas earlier this year (OGJ Online, Jan. 10, 2023). The company shipped the first Middle East-sourced LNG cargo to arrive in Germany (OGJ Online, Feb. 22, 2023).
ADNOC LNG, 70% owned by ADNOC, produces 6 million tonnes/year (tpy) at its plant on Das Island offshore Abu Dhabi. ADNOC’s partners in ADNOC LNG are Mitsui & Co. (15%), bp PLC (10%), and TotalEnergies (5%). The company is also developing a second plant, with 9.6-million tpy capacity, at Fujairah, with award of an engineering, procurement, and construction contract expected in 2023 (OGJ Online, May 13, 2022).
Eni starts work on FLNG development offshore Congo
Eni SPA has begun work on its 3-million tonne/year (tpy) Congo LNG development. The company expects it to reach full capacity in 2025. Natural gas for the project will be supplied by Eni’s Marine XII 1.3-billion boe proven and probable reserves concession, 20 km offshore Congo.
Congo LNG will use two floating LNG (FLNG) plants, one each stationed at Nenè and Litchendjili fields. The first plant, 0.6-million tpy Tango FLNG, was acquired by Eni last year following its deployment in Argentina (OGJ Online, Aug. 8, 2022). The second FLNG plant—currently undergoing conversion by Wison Heavy Industries Co. Ltd.—will become operational in 2025 with a capacity of 2.4 million tpy (OGJ Online, Dec. 28, 2022).
Tango FLNG’s development will include an additional platform, a gas pre-treatment plant, and 12 new wells (OGJ Online, Jan. 25, 2023). A total of 29 new wells and eight platforms will be part of the second FLNG development. Borr Drilling Ltd.’s Prospector 5 jackup drilling rig is among the units contracted by Congo’s state oil and gas company to drill at Marine XII, where it is currently stationed.
Eni is operator at Marine XII (65%) with partners PJSC Lukoil (25%) and Societe Nationale des Petroles du Congo (10%).