GENERAL INTEREST Quick Takes
Johan Castberg partners increase project cost by $1.2 billion
The Johan Castberg partnership increased the project’s investment estimate by almost NOK 13 billion ($1.2 billion) since last year but plans for fourth-quarter 2024 production start from the Barents Sea project remain unchanged, operator Equinor Energy AS said in a release Sept. 19.
The updated project cost estimate is now NOK 80 billion, up from NOK 57 billion when the original plan for development and operation (PDO) was submitted in 2017.
A tighter supplier market and an increased work scope in Norway following the FPSO hull mobilization from Singapore to Stord last year are cited as reasons for the increase.
Johan Castberg field lies about 100 km north of Snøhvit field in 370 m of water. The resource base for developing the field consists of the three oil discoveries—Skrugard, Havis, and Drivis, all in production license 532, and all of which will be developed through an FPSO designed to produce about 190,000 b/d. Additional subsea solutions include 18 horizontal production wells and 12 injection wells. Recoverable resources are estimated at 450-650 MMboe.
Equinor is operator of the project with 50% interest. License partners are Vår Energi (30%) and Petoro (20%).
Petrobras stops divestment process for certain exploration, production assets
Petróleo Brasileiro SA (Petrobras) has stopped the divestment processes for certain assets following adoption of a new plan to maximize the value of the company’s portfolio.
In the exploration and production segment, the company plans to focus on profitable assets, restoring oil and gas reserves, including “by exploring new frontiers, increasing the supply of natural gas and promoting the decarbonization of operations,” the company said in a release Sept. 4.
With this, “considering their strategic adherence to the portfolio, as well as their profitability profile,” the operator is terminating the divestment processes for Urucu cluster, Bahia Terra cluster, Manati field, and Petrobras Operaciones SA.
As for other assets, the company will periodically reassess their “permanence in the portfolio” based on “updated assumptions of profitability, strategic adherence, decarbonization opportunities, and the stage of their productive life.”
Petrobras will continue with divestment of 20% stake in Brasympe, owner of the Termocabo thermoelectric unit (UTE); 20% stake in UTE Suape II; and 18.8% stake in UEG Araucária SA.
Equinor acquires stake in Bayou Bend CCS project from Carbonvert
Equinor Energy AS has acquired Carbonvert Inc.’s 25% interest in Bayou Bend CCS LLC, a carbon capture and sequestration project sited along the Texas Gulf Coast, through the purchase of Texas Carbon 1 LLC, a Carbonvert subsidiary.
Bayou Bend is positioned to be one of the largest CCS solutions in the US for industrial emitters, with nearly 140,000 gross acres of pore space for permanent CO2 sequestration and gross potential storage resources of more than 1 billion metric tons. The Bayou Bend total acreage includes nearly 100,000 gross acres onshore in Chambers and Jefferson Counties, Tex., and about 40,000 gross acres offshore Beaumont and Port Arthur, Tex. (OGJ Online, Mar. 6, 2023).
Bayou Bend is a joint venture of Chevron USA Inc. (operator, 50%), through its Chevron New Energies division, Talos Energy Inc. (25%), through its Talos Low Carbon Solutions division, and Equinor.
Exploration & Development Quick Takes
Equinor submits PDO for Eirin gas field development
Equinor ASA has submitted a plan for development and operation (PDO) of Eirin gas field in the Norwegian North Sea to the Ministry of Petroleum and Energy.
Recoverable reserves in the field, which lies 250 km west of Stavanger in water depth of 120 m, are estimated at 27.6 MMboe, most of which is gas, the company said in a release Sept. 15. Eirin field, which was discovered in 1978, will be developed as a subsea tieback to the Gina Krog platform in the North Sea. Total investments are estimated at just over NOK 4 billion.
Using Gina Krog’s infrastructure will enable Eirin to bring new gas to Europe quickly and will extend Gina Krog’s productive life to 2036 from 2029, said Camilla Salthe, Equinor’s senior vice-president for field life extension (FLX).
In June, Equinor issued a letter of award to Aker Solutions ASA to supply the subsea production system and control umbilical for Eirin field development. Production start-up is expected as early as 2025.
Equinor is operator of license PL 11774S with 78.2%. Kuwait Foreign Petroleum Exploration Co. (KUFPEC), through Norwegian subsidiary KUFPEC Norway AS, holds the remaining 21.8%.
Eni lets Baleine Phase 2 contract to Saipem
Eni has let a subsea umbilicals, risers, and flowlines (SURF) contract to Saipem for development of the Baleine Phase 2 project offshore Ivory Coast.
Work scope encompasses the engineering, procurement, construction, and installation (EPCI) of about 20 km of rigid lines, 10 km of flexible risers and jumpers, and 15 km of umbilicals connected to a dedicated floating unit. Installation works will be carried out by Saipem’s offshore construction vessels and will take place in 2024.
Initial production from Baleine field, in water depth of 1,200 m, began in August though the Baleine floating production storage and offloading (FPSO) vessel, a refurbished and upgraded unit capable of handling up to 15,000 b/d of oil and around 25 MMscfd of associated gas.
The start of Phase 2 production is expected by end-2024, also through a renovated FPSO. This second phase is expected to increase field production to 50,000 b/d of oil and about 70 MMscfd of associated gas. The third development phase aims to elevate field production up to 150,000 b/d of oil and 200 MMscfd of gas.
Saipem contributed to Phase 1 drilling activities by deploying the Saipem 10000 and Saipem 12000 vessels, followed up by the execution of two contracts for Baleine Phase 1 in fast-track mode.
Drilling & Production Quick Takes
Tamboran observes strong gas shows in Beetaloo sub-basin well
Tamboran (B2) Pty Ltd. observed strong dry gas shows in the Shenandoah South 1H (SS1H) pilot hole in exploration permit 117 in the Beetaloo sub-basin, Northern Territory, Australia, partner Falcon Oil & Gas Ltd. said in a release Aug. 30.
The well, the first of two horizontal wells to be drilled in 2023, is about 60 km south of the A2H well site. The Helmerich & Payne rig reached 3,300 m TVD in 21.5 days, drilling at 153 m/d, setting a record for wells drilled below 3,000 m in the sub-basin.
The well intersected 90 m of the Amungee Member B-shale, which is the thickest section seen in the Beetaloo sub-basin depocenter to date. Logging of the formation indicates potentially higher porosity and gas saturation relative to offset wells.
Initial evaluation confirms reservoir continuity of the Amungee Member B-shale over 150 km between Amungee NW-2H and Beetaloo W-1 wells. This includes a target development area of about 1 million acres where the shale depth exceeds 2,700 m.
Tamboran will commence a 1,000-m horizontal section within the shale formation ahead of a stimulation program of up to 10 stages over a 500-m section, which is planned for fourth-quarter 2023.
Tamboran is operator of EP117 (77.5%). Falcon Oil & Gas holds the remaining 22.5%.
Arena Energy, White Fleet mobilize Gulf of Mexico drilling rig
Arena Energy LLC and rig services provider White Fleet Drilling LLC have mobilized the White Fleet Drilling (WFD) 400 refurbished jack-up drilling rig for work in the US Gulf of Mexico.
WFD 400 will support drilling and development activities for Arena and plugging and abandonment operations for third-party operators in the Gulf of Mexico for the next 15-20 years, the company said in a release Sept. 7.
White Fleet—Arena’s strategic partner created in 2017 as a jack-up rig services provider and Arena’s preferred drilling contractor—acquired the out-of-service rig in 2022 and subsequently moved it to Gulf Copper’s shipyard in Galveston, Tex., in July 2022. Enterprise Offshore Drilling provided project management for an extensive refurbishment to bring the rig to operational standards, including equipment installation, improved safety features, and an overhaul of the rig’s mechanical systems.
“Just 10 years ago, there were 36 six active jack-up drilling rigs in the US Gulf of Mexico. With the addition of the WFD 400, there are now six active jack-up rigs in the [Gulf of Mexico], and the WFD 400 fills a void for jack-up rigs capable of working in 400 ft of water,” said Mike Minarovic, Arena co-founder and chief executive officer.
The rig is under contract and on location performing plugging and abandonment work for an unnamed operator in the gulf’s shallow waters, the company said.
Jadestone plans Montara production restart
Jadestone Energy PLC restarted production at Montara in the Timor Sea offshore northern Australia on Sept. 1, 2023, following an investigation and assurance review into the 4S-5C tank defects on the Montara Venture floating production, storage, and offtake vessel (FPSO).
A gas alarm was triggered within tank 4S on July 29.
Ballast water tank 4P has been returned to service following final inspections and repairs. Preparations for repair of the reported defect between oil cargo tank 5C and ballast water tank 4S are under way and additional inspections in tank 4S are ongoing.
Initial production averaged 1,000 b/d from one well while the FPSO’s oil production and gas compression systems were recommissioned. Further wells are being brought back online, and production had increased to 8,000 b/d by Sept. 7, which included some flush production. Pre-shutdown levels are about 6,000 b/.
The company will continue to utilize a shuttle tanker to provide additional storage during this period of constrained FPSO storage capacity.
The Montara project is in production licenses AC/L7 and AC/L8 about 690 km west of Darwin, 630 km north of Broome, and 250 km north-west from the Kimberley coastline of Western Australia in 77 m of water.
Montara produces oil using platform production wells for Montara field and subsea wells for Swift, Skua, and Swallow fields. Oil from the subsea wells is piped via subsea flowlines to an unmanned wellhead platform and then to the FPSO.
Jadestone is 100% owner and operator of the project.
Hammerhead Energy increases 2023 production guidance
Hammerhead Energy Inc., Calgary, has increased its 2023 annual average production guidance based on costs and performance, the company said in a release Sept. 6.
Annual average production for the year is now guided to 41,500 boe/d from the previous estimate of 40,200 boed. Crude oil production is estimated to be 35% of production from a prior estimate of 33%.
Since the start of production Aug. 6, performance on the 12-well North Karr 10-14 pad in Alberta has exceeded the company’s internal forecast, with peak pad production surpassing 17,800 boe/d (over 50% crude oil). Field estimates of Hammerhead’s corporate production volumes for August averaged 48,500 boe/d, with upside as North Karr total production capability exceeds infrastructure capacity, the company said.
Overall, well performance has exceeded type curves while capital costs have come in lower than forecast. Thus, Hammerhead is reducing its 2023 capital expenditures guidance to $500 million from $525 million.
Updated 2023 production guidance continues to assume that the new South Karr 5-11 nine-well pad does not begin production until January 2024, although drilling operations have been completed ahead of planned timing while expansion of infrastructure at South Karr is still expected to be completed before end-2024, the company said.
The company is developing a 107,000 net acre resource base within the Montney light oil window in Alberta. It holds an undeveloped inventory of over 1,500 gross well locations targeting the Upper and Lower Montney within its core development areas of Gold Creek, South Karr, and North Karr near Grande Prairie, Alta.
PROCESSING Quick Takes
Pertamina lets contract for new unit at Cilacap refinery
Indonesia’s state-owned PT Pertamina has let a contract to Topsoe AS to deliver process technology for a grassroots renewable fuels production unit to be installed at subsidiary PT Kilang Pertamina Internasional’s (PT KPI) 348,000-b/d Cilacap integrated refining and petrochemical complex in Central Java.
As part of the contract, Topsoe will license its proprietary HydroFlex technology for a new unit designed to convert renewable feedstocks into 6,000 b/d of sustainable aviation fuel (SAF) and renewable diesel for distribution to markets in the Asia Pacific, the service provider said in a release.
While Topsoe disclosed no further details regarding the contract award, the proposed renewable fuels unit at Cilacap comes as part of the refinery’s second phase of its Cilacap Green Refinery Cilacap (CGR) project, according to a series of 2023 official releases from PT KPI.
Completed in February 2022 and commercially operable as of June 2022, CGR Phase 1 has enabled the Cilacap refinery to produce 2,500-3,000 b/d of renewable diesel with a maximum sulfur content of 5 ppm from a feedstock of refined bleached deodorized palm oil, PT KPI confirmed in its 2022 annual report to investors.
The same renewable fuels production unit commissioned as part of CGR Phase 1 has also enabled the refinery to produce an unidentified volume of SAF, the operator said on Aug. 18.
To be based on a feedstock of used cooking oil, CGR Phase 2 is scheduled for startup in 2026.
Eni, LG Chem weigh joint biorefining project in South Korea
Eni SPA subsidiary Eni Sustainable Mobility SPA (ESM) and LG Chem Ltd. have launched preliminary studies to evaluate the potential for jointly developing and operating a grassroots biorefinery to be built at LG Chem’s integrated petrochemical complex in Daesan, Chungcheong Province, South Korea.
Aligned with both companies’ shared objective to meet growing demand for sustainable, low-carbon fuels and plastics, the proposed Daesan biorefinery would use the Eni-Honeywell UOP LLC codeveloped proprietary Ecofining technology for flexible processing of about 400,000 tonnes/year of renewable materials for production of sustainable aviation fuel (SAF), hydrotreated vegetable oil (HVO, or renewable diesel), and bionaphtha, the companies said on Sept. 14.
As part of the potential project, Eni said it would use its existing global supply chain to provide the proposed biorefinery with sustainable feedstock that includes mainly waste and residues from the processing of vegetable oils, and used cooking oil, but also vegetable oils derived from drought-resistant crops in degraded, semi-arid, or abandoned soils not in competition with the food chain.
With technical and economic feasibility assessments for the joint development already under way, the companies said they expect
to take final investment decision on the possible project by 2024.
If approved, ESM and LG Chem said the proposed biorefinery—which would leverage the Daesan complex’s integrated value chain, including existing utilities and logistics infrastructure—would be completed by 2026.
Montana Renewables’ biorefinery expands feedstock options
Calumet Specialty Products Partners LP subsidiary Montana Renewables LLC (MRL) is adding camelina oil as a new feedstock for production of renewable fuels at the operator’s manufacturing plant in Great Falls, Mont.
On Sept. 18, MRL’s Great Falls renewable fuels plant received its first receipts of camelina oil, which the site will add to its current feedstock of more than 1.5 billion lb/year of rendering wastes and seed oil that it uses to produce renewable diesel and sustainable aviation fuel (SAF), Calumet said in a release.
“We are pleased to add 2023 USA-produced camelina oil to our existing feeds which already include canola oil, corn oil, and tallow,” said Bruce Fleming, MRL’s chief executive officer.
Fleming noted addition of the new biofeedstock further attests to MRL’s broader feedstock advantage, which recently increased following the plant’s startup of a first-ever commercial 10,000-b/d Hydrothermal Cleanup (HCU) renewable feedstock pretreatment unit (PTU) from Applied Research Associates Inc. (ARA).
“While our ARA [HCU PTU] technology provides the ability to run feed from anywhere in the world, camelina is indigenous to Montana…[a]nd by providing a market in Montana, we are creating long-term benefits for Montana farm and ranch producers who grow most of the country’s camelina today,” Fleming said.
While MRL already supports 1-2 million acres of farm and ranch activity in canola, corn, and cattle, Fleming emphasized associated seed crushing and meat packing takes place outside of Montana.
“Our vision is to attract seed crushing and meat packing facilities to Montana to further spread the benefits of lower carbon emissions, lower freight costs, and higher agricultural activity,” Fleming said.
Commissioned in late 2022 and co-located at fellow subsidiary Calumet Montana Refining LLC’s (CMRL) Great Falls conventional refinery and specialty asphalt plant, MRL’s biorefinery reached its design processing capacity for renewable feedstocks of 15,000 b/sd in mid-April 2023 following commissioning of the operator’s new renewable hydrogen plant in early March (OGJ Online, Apr. 18, 2023).
TRANSPORTATION Quick Takes
DT Midstream completes first LEAP expansion
DT Midstream Inc. has commissioned its Louisiana Energy Access (LEAP) Phase 1 expansion, increasing its capacity to 1.3 bcfd from 1.0 bcfd. The completion comes ahead of the original expected in-service date of fourth-quarter 2023.
Second- and third-phase expansions remain on track for in-service dates of first-quarter 2024 and third-quarter 2024, respectively, the company said in an Aug. 30 update. 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.
LEAP currently provides interconnectivity between Haynesville production and Gulf Coast markets. Customers 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, Texas Eastern, and Transco, the company said.
Novatek completes Train 1 maritime towing, installation for Arctic LNG 2
PAO Novatek is preparing to hook up Train 1 of its 19.8 million tonne/year (tpy) Arctic LNG 2 liquefaction plant on Russia’s Gydan Peninsula to complete commissioning activities and begin liquefaction operations, the operator said in a late August release.
The 6.6-million tpy liquefaction train was towed by sea atop its gravity-based structure (GBS) from the LNG construction center in the Murmansk region to the Gydan Peninsula and was installed on the underbase foundation built on the seabed at the Utrenniy terminal near shore. The marine towing operation took 22 days to complete.
The train consists of topside modules with equipment to produce and offload LNG and stable gas condensate and was installed on a GBS, which accommodates LNG and condensate storage tanks. The 330-m long, 152-m wide and 90-m high platform weighs 640,000 tonnes, Novatek said.
“The innovative GBS-based construction concept allows us to put new LNG facilities into operation faster and with lower capital expenditures,” said Leonid Mikhelson, Novatek’s chairman of the management board.
The operator is now at “an advanced stage” of building the project’s second train, and is starting work on the third train’s GBS, he said.
Tellurian signs deal for Driftwood LNG liquefaction equipment
Tellurian Inc. signed an equipment deal with Baker Hughes for the proposed Driftwood LNG liquefaction plant near Lake Charles, La.
The service company agreed to supply eight main refrigerant compression packages (eight LM6000PF+ gas turbines, main refrigerant compressors, and control units) required for Phase 1 of the proposed 27.6-million tonnes/year (tpy) plant.
Baker Hughes is also on schedule to complete, by early 2024, fabrication of the electric-powered, zero-emissions Integrated Compressor Line packages and other turbomachinery equipment for Driftwood Pipeline 200 to supply the LNG plant, following the award in 2022 (OGJ Online, July 1, 2022).
Tellurian’s multiphase proposed pipeline project, Line 200 and Line 300, is a $1.28-billion, 37-mile, dual 42-in. OD interstate natural gas pipeline system to originate near Ragley in Beauregard Parish and end near Carlyss in Calcasieu Parish. Line 200 (Phase 1) envisages one compressor station and 11 interconnects to transport about 2.4 bcfd of flowing gas, according to a Tellurian website.
Initial LNG production from the Driftwood LNG plant is targeted for 2027. Site work is under way, with Bechtel having completed piling and compressor foundations for Driftwood LNG’s first plant.
Despite contractual challenges, the 11-million tpy, 2-plant Phase 1—estimated to reach development costs of $14.5 billion—is progressing, Tellurian said in August.