GENERAL INTEREST Quick Takes
Gulf of Mexico oil, gas Lease Sale 261 set for Dec. 20
Lease Sale 261 for oil and gas exploration tracts in the Gulf of Mexico is now set for Dec. 20, the Bureau of Ocean Energy Management (BOEM) announced Nov. 16.
A Final Notice of Sale will be available for public inspection Nov. 17 and will be published Nov. 20 in the Federal Register, the agency said. If BOEM follows standard form, the deadline for bids will be the day before the sale date. BOEM will live stream the opening of bids at 9 a.m. Central time Dec. 20.
BOEM was bowing to a Nov. 14 order of the US Court of Appeals for the Fifth Circuit. The order required the agency to go ahead with the sale and to do so without the additional restrictions announced in August that excluded about 6 million acres from the sale acreage and imposed limits on oil and gas ship movements (OGJ Online, Nov. 15, 2023).
“Pursuant to direction from the court, BOEM will include lease blocks that were previously excluded due to concerns regarding potential impacts to the Rice’s whale population in the Gulf of Mexico,” the agency said. “BOEM will also remove portions of a related stipulation meant to address those potential impacts from the lease terms for any leases that may result from Lease Sale 261.”
The “related stipulation” concerned sharply limiting ship speeds and restricting nighttime ship movements, but only for craft involved in oil and gas work.
The court of appeals ruling had the effect of upholding a preliminary injunction issued by the US District Court for the Western District of Louisiana that struck down the acreage exclusions and ship movement stipulations.
The district court found that an injunction was warranted because the industry plaintiffs and the state of Louisiana were likely to succeed at trial in their charges that BOEM violated the Outer Continental Shelf Lands Act and the Administrative Procedure Act in the way BOEM tacked on acreage restrictions and ship restrictions without adequate justification.
ExxonMobil Guyana takes ownership of Liza Unity FPSO
ExxonMobil Corp. affiliate ExxonMobil Guyana Ltd. has completed a deal to purchase the Liza Unity floating production, storage, and offloading (FPSO) vessel from SBM Offshore NV for $1.26 billion.
The deal was completed a few months ahead of the end of the maximum lease term, in February 2024, SBM Offshore said in a release Nov. 9.
The purchase allows ExxonMobil Guyana to assume ownership of the unit while SBM Offshore will continue to operate and maintain the FPSO up to 2033.
ExxonMobil started production at Liza Phase 2, Guyana’s second offshore oil development on Stabroek block, in February 2022 (OGJ Online, Feb. 14, 2022).
The FPSO is designed to produce about 220,000 b/d of oil, to have associated gas treatment capacity of 400 MMcfd, and water injection capacity of 250,000 b/d. It is spread moored in water depth of about 1,650 m. It can store around 2 million bbl of crude oil.
Wintershall acquires 10% stake in UK Poseidon CCS project
Wintershall Dea has entered a second carbon capture and storage (CCS) project in the United Kingdom, joining the Perenco-operated Poseidon CCS project after acquiring a 10% stake in the license from Carbon Catalyst Ltd.
The license was awarded to Perenco and Carbon Catalyst as part of the UK’s first CO2 storage licensing round (OGJ Online, Aug. 14, 2023).
The project, which has the potential to help decarbonize East Anglia, Greater London, and the wider southeast UK, is due to come online by 2029. Initial CO2 injection rates will be about 1.5 million tonnes/year (tpy), ramping up to 10 million tpy by 2030, and peaking at 40 million tpy by 2040.
The carbon storage license lies in the UK Southern North Sea, about 65 km off the coast from Bacton in the county of Norfolk. It covers the geological structures of Leman gas field and offers a combination of depleted reservoirs and saline aquifers suitable for safe and permanent carbon storage, Wintershall said.
The field is connected to the Perenco-operated Bacton Gas Terminal, which will receive and process CO2 offshore.
A final investment decision for the project is expected in 2026.
In total, Wintershall Dea has stakes in five offshore CCS licenses in three North Sea countries, including the Greensands CCS project in the Danish North Sea where earlier this year the first cross-border CO2 injectivity test was performed (OGJ Online, Feb. 20, 2023). The project aims to store up to 1.5 million tpy of CO2 in 2025-26, and as much as 8 million tpy by 2030.
Poseidon is the second UK CCS project for Wintershall, following the Synergia Energy-operated Camelot license award where CO2 storage potential is estimated to be up to 6 million tpy (OGJ Online, Aug. 15, 2023).
Exploration & Development Quick Takes
ConocoPhillips to explore Otway basin
ConocoPhillips Australia Pty Ltd. will undertake exploration activities in offshore permits VIC/P79 and T/49P in Commonwealth waters of Otway basin, 19 km offshore Victoria and 28 km offshore King Island, Tasmania.
The proposed Otway exploration drilling program involves seabed surveys at up to a maximum of nine locations, and drilling up to a maximum of six exploration wells in water depths of 53-500 m.
Activity is scheduled to commence no earlier than Apr. 1, 2024, and will be completed no later than Dec. 31, 2028, with the exact timing dependent on the receipt of environmental approvals and the availability of a mobile offshore drilling unit (MODU).
In July, ConocoPhillips secured the Transocean Equinox rig to drill two firm wells in the permits (OGJ Online, July 12, 2023).
ConocoPhillips Australia is operator of the permits with 80% interest. 3D Oil holds the remaining 20%.
Beach Energy discovers gas onshore Perth basin
Beach Energy Ltd., Adelaide, made a natural gas discovery at Tarantula Deep 1 in October. The well, drilled with the Ventia 106 rig onshore North Perth basin in Western Australia, reached total depth of 4,121 m on Oct. 14, 2023.
The well intersected a 63-m gross section of high quality Kingia Sandstone reservoir comparable to the offset well Beharra Springs Deep 1, the company said in an October release.
“Two gas discoveries from our first three operated exploration wells is a great start to the campaign,” said interim chief executive officer Bruce Clement in a mid-October release. In August, Beach Energy discovered gas the Trigg Northwest 1 well in exploration license EP 320 in the onshore basin (OGJ Online, Aug. 21, 2023).
Tarantula Deep 1 intersected a gas water contact within the Kingia reservoir, with net gas pay of 10 m above the contact confirmed by gas sampling. The well was drilled down-dip to identify the depth of gas water contact, provide greater certainty of recoverable gas in place, and facilitate optimal development planning, the operator continued.
The well will be suspended to allow for future development.
“The results at Tarantula Deep 1 have improved our understanding of the Kingia reservoir extent in the Beharra Springs area and give us greater confidence in future development and near field exploration within the immediate region,” Clement said.
Drilling & Production Quick Takes
Aramco starts South Ghawar unconventional production
Saudi Aramco produced the first unconventional tight gas from its South Ghawar operational area in Saudi Arabia. Production is 2 months ahead of schedule.
Commissioned facilities at South Ghawar have 300 MMscfd of raw gas processing capacity and 38,000 b/d of condensate processing capacity. In response to growing demand for gas, the company will increase overall processing capacity to deliver 750 MMscfd of raw gas in the near future.
Saudi Arabia’s Unconventional Resources Program, launched in 2013, aims to boost gas production to meet domestic needs, displace crude oil in power generation, supply feedstock for petrochemicals, and stimulate regional economies (OGJ Online, May 29, 2018)
Ghawar is Aramco’s second unconventional gas stream after production commenced at North Arabia field in 2018 with the delivery of 240 MMscfd to customers in Wa’ad Al-Shamal. Work is simultaneously progressing at Jafurah unconventional gas field, which is the largest liquid-rich shale gas play in the Middle East.
Wellesley to drill Toppand East prospect in first-half 2024
Wellesley Petroleum expects to drill the Toppand East prospect offshore Norway in production license (PL) 248 C in first-half 2024.
The license partners signed a rig assignment agreement for the COSL Promoter rig earlier this month, Wellesley said in a release Nov. 9.
Wellesley will operate drilling of the prospect on behalf of license partners, it said. Equinor is operator of the license with 30% interest. Wellesley holds 30% and Petoro holds the remaining 40%.
Toppand East is “an attractive ILX target that has the potential to add significant volumes to Toppand and to the Ringvei Vest area development,” said Chris Elliott, chief executive officer of Wellesley, noting Equinor’s help to secure the rig slot, aiding in acceleration of exploration drilling activity in the area.
Toppand East is considered a low-risk appraisal target in the Middle Jurassic Brent/Oseberg structural trap charged from the Toppand structure. Toppand, a four-way structure in the Brent reservoir fairway in PL 630, was discovered in January 2022 by the 35/10-7 S and A wells, which found oil-filled, stacked reservoirs and an oil-water contact (OGJ Online, Jan. 7. 2022).
Equinor is operator of Toppand with 95% interest. Wellesley holds 5% (OGJ Online, Mar. 1, 2023).
Toppand will be developed with two oil producers and a water injector as part of the Fram and North Troll area (FANTA) project, which encompasses development of the Equinor-operated Grosbeak, Swisher, and Toppand discoveries.
FANTA will tie back to the Equinor-operated Troll B / C platforms, which are expected to be electrified in time for first production. Both platforms will be powered by hydroelectric power from shore and are expected to have zero CO2 emissions associated with their oil production.
The FANTA project is expected to achieve PDO in 2024, with first production from all fields expected in 2028-29.
Equinor to extend Breidablikk drilling
Equinor Energy AS has exercised options for drilling an additional seven wells on Breidablikk field in the North Sea, extending its contract with Odfjell Drilling Ltd. for use of the Deepsea Aberdeen rig.
The options are planned to start in mid-first-quarter 2025 in direct continuation of the current firm period and extend the firm backlog on the Deepsea Aberdeen to end-fourth-quarter 2025. The options have a value of about $138 million, excluding integrated services, performance, and fuel incentives.
In addition to the exercised wells, the contract now includes further optional periods which, if exercised, could keep the Deepsea Aberdeen contracted to 2029. Such optional periods consist of six optional wells followed by three further optional periods of eight wells each, or about three times one-year. Rates would be mutually agreed prior to exercising.
Breidablikk is tied back to the Grane platform and oil is sent ashore by pipeline to the Sture terminal in Øygarden. The subsea field holds almost 200 million bbl of recoverable oil.
Equinor is operator of the field with 39% interest. Partners are Vår Energi ASA (34.4%), Petoro (22.2%), and ConocoPhillips Skandinavia AS (4.4%).
PROCESSING Quick Takes
ONGC proposes grassroots petrochemical complexes
Oil and Natural Gas Corp. Ltd.’s (ONGC) board has approved an investment of more than $1 billion to build new petrochemical complexes in India as part of the operator’s plan to increase production capacity of its existing petrochemicals portfolio.
Amid projections of a continued waning demand for crude-oil based transportation fuels, ONGC’s board has greenlighted a plan to invest about 1 trillion rupees ($1.2 billion) by 2028 or 2030 on two projects involving construction of two grassroots petrochemical complexes, each of which would be sited in separate Indian states, the operator said in its Nov. 15 quarterly earnings call with investors.
The new projects are intended to boost ONGC’s current petrochemical production capacity of about 3.4 million tonnes/year (tpy) to at least somewhere between 8.5-9 million tpy by 2030, the company said.
ONGC said that while its board has approved moving forward with the planned investment projects—at least one of which would likely involve some type of a joint-venture partnership—both projects still remain subject to necessary approvals and support by India’s applicable regulatory bodies, including the country’s Ministry of Petroleum and Natural Gas and Cabinet Committee on Economic Affairs.
ONGC declined to reveal in which of India’s states the proposed complexes would be located and disclosed no additional details about either project.
Announcement of the newly proposed petrochemical projects follows ONGC’s disclosure in its 2022-23 annual report that the company is examining multiple brownfield and greenfield options for increasing its current petrochemical production capacity based on the International Energy Agency’s the petrochemical industry will become the primary driver of oil consumption, contributing to more than a third of growth in oil demand by 2030.
The petrochemical focus comes as part of ONGC’s Energy Strategy 2040, under which it plans to gradually diversify its business from the oil to petrochemical sector as part of its transformation strategy to balance current energy needs on its journey to a lower-carbon future in line with the global energy transition, according to the operator’s annual report.
During its Aug. 29 annual general meeting, ONGC also revealed it is also collaborating with “other entities” to explore opportunities for setting up two oil-to-chemical (O2C) grassroots plants within India that would use O2C technology to enable transforming 40-60% of crude oil feedstock directly into chemicals.
The proposed O2C plants seemingly will come in addition to the planned petrochemical projects announced on Nov. 15.
ONGC currently produces petrochemicals through subsidiaries Mangalore Refinery & Petrochemicals Ltd. (MRPL) and ONGC Petro additions Ltd. (OPaL).
At its 15-million tpy integrated refining and petrochemical complex in Karnataka, Mangalore, , MRPL houses a gas-phase polypropylene plant capable of producing a complete range of homopolymer grades.
Located along the longest coastline of India’s Gujarat state at Dahej, OPaL’s petrochemical complex includes the following unit capacities:
- 340,000 tpy; high-density polyethylene (HDPE).
- 720,000 tpy; swing HDPE, linear-low density polyethylene (LLDPE).
- 340,000 tpy; polypropylene.
- 150,000 tpy; benzene.
- 115,000 tpy; butadiene.
- 70,000 tpy; carbon black.
- 165,000 tpy; hydrogenated pyrolysis gasoline.
CVR Energy lets contract for proposed Kansas renewable fuels plant
CVR Energy Inc. subsidiary CVR Renewables CVL LLC has let a contract to Honeywell International Inc.’s Honeywell UOP LLC to license technology for a potential renewable fuels production project at or near fellow subsidiary Coffeyville Resources Refining & Marketing LLC’s (CRRM) 132,000-b/d refinery in Coffeyville, Kan.
As part of the contract, UOP will deliver CVR Renewables licensing of the UOP-Eni SPA codeveloped proprietary Ecofining process for evaluation of a plant that would convert 30,000 b/d of 100% renewable waste feedstocks such as distillers corn oil into sustainable aviation fuel (SAF), renewable diesel, and other products, Honeywell said.
The contract award follows CVR Energy’s confirmation in its third-quarter 2023 earnings report that the Coffeyville renewables project remains subject to approval by the company’s board, regulators, and other potential third-party partners. If approved and pursued, the Coffeyville renewables project would enable CVR Renewables to capture benefits from proximity to the existing Coffeyville refinery, including the site’s excess hydrogen capacity and access to carbon capture utilization and storage, CVR Energy said.
In a Sept. 6 presentation to investors, CVR Energy said the Coffeyville renewables plant would have an overall production capacity of up to 500 million gal/year of biofuels, of which up to 250 million gal/year could be SAF.
Previously planned as a revamp of an existing hydrotreater at CCRM’s refinery, the newly proposed Coffeyville renewables project would form the third phase of the operator’s increased focus on production of renewable biofuels.
Phase 1 involved conversion of a 19,000-b/d hydrocracker at subsidiary Wynnewood Refining Co. LLC’s 74,500-b/d refinery in Wynnewood, Okla., to enable processing of a 100-million gal/year low-carbon intensity refined and bleached soybean oil into renewable diesel and renewable naphtha. The $179-million Wynnewood renewable diesel unit (RDU) in third-quarter 2023 processed 23.8 million gal of vegetable oil, up from 17.7 million gal in third-quarter 2022, CVR Energy said.
Scheduled to be completed by yearend 2023, Phase 2 of the renewables initiative entails a $95-million project involving installation of a renewable feedstock pretreating unit at Wynnewood that will allow the RDU flexibility to process a wider slate of biofeedstocks, including inedible corn oil, animal fats, and used cooking oils.
A timeframe for final investment decision on the proposed Phase 3 renewables project was not disclosed.
TRANSPORTATION Quick Takes
Court vacates Port Arthur LNG emissions permit
The US Court of Appeals for the Fifth Circuit has vacated an emissions permit for the 13.5-million tonne/year first phase of Sempra Infrastructure’s Port Arthur LNG plant under development in Texas. The company said it will continue to build at the site while it works with the Texas Commission on Environmental Quality (TCEQ) on resolving the issue.
In its opinion, the court said that TCEQ had not imposed the same emissions limits at Port Arthur LNG as it had for other similar projects in the state and had not explained its reasons for doing so, which is legally required. The petitioner in the case, Port Arthur Community Action Network, had noted in its filing that Port Arthur LNG planned to use the same refrigeration compression (General Electric Frame 7EA turbines with Dry-Low NOx combustors) as NextDecade Corp.’s Rio Grande LNG project, but had been granted higher limits.
TCEQ acknowledged that lower emissions limits had been imposed at Rio Grande LNG but noted that since the plant was not in operation no operational data could prove that its limits were achievable and therefore it was not obligated to apply them elsewhere. The court disagreed, citing both state and federal guidelines.
Sempra earlier this year received Federal Energy Regulatory Commission authorization to proceed with Port Arthur LNG Phase 2, adding two trains to the plant and roughly doubling its capacity. At the time, Port Arthur Trains 1 and 2 (Phase 1) were expected to be completed in 2027 and 2028, respectively.
Cedar LNG secures FLNG shipyard capacity
Pembina Pipeline Corp. and the Haisla Nation, partners in development of the proposed 3-million tonne/year (tpy) Cedar LNG project in Kitimat, BC, have signed a heads of agreement with Samsung Heavy Industries Co. Ltd. and Black & Veatch Corp., providing Cedar with secure access to the shipyard capacity required to meet its early 2028 target commercial operations date. The parties expect to finalize a lump sum engineering, procurement, and construction agreement in December 2023.
Cedar LNG will use a floating LNG plant for the project. It plans to power the site with renewable electricity supplied by British Columbia Hydro and Power Authority.
All major regulatory approvals have been granted and MoU are in place for 100% of Cedar LNG’s output. ARC Resources Ltd., a gas producer in Montney shale, earlier this year signed an MOU with Cedar towards a 20-year, 1.5 million tpy liquefaction services agreement. ARC would supply roughly 200 MMcfd of gas to the plant.
Cedar LNG plans to take final investment decision by end-2023 but acknowledges that this could slip to early 2024 depending on the alignment of multiple work streams (OGJ Online, Aug. 4, 2023).
