GENERAL INTEREST Quick Takes
Santos takes FID on Moomba carbon capture storage project
Santos Ltd. and joint venture partner Beach Energy Ltd. have reached a final investment decision on the $165-million carbon capture storage (CCS) project at Moomba in South Australia. Start-up is expected in 2024.
Santos registered the project with Australia’s Clean Energy Regulator which provides a crediting period of 25 years. During this period the Moomba CCS project will qualify for Australian Carbon credit units for emissions reduction.
Moomba CCS is designed to capture and store 1.7 million tonnes/year (tpy) of CO2 using depleted Cooper basin reservoirs. The project has the potential to store 20 million tpy in future development phases.
Santos is operator of Moomba CCS with 66.7% interest. Beach holds the remaining interest.
Lundin acquires additional 25% interest in Wisting development
Lundin Energy Norway AS has agreement to acquire OMV (Norge) AS’s entire 25% working interest in the Wisting development in the southern Barents Sea for $320 million. A contingent payment of up to $20 million depends on final project CAPEX.
The deal takes Lundin Energy’s working interest to 35% from 10% in the 500 million bbl oil development and adds net 130 MMboe fully appraised contingent resources.
Wisting oil field is in the Hoop area of the Barents Sea in PL 537 and 537B, about 310 km from the mainland of Norway. Six wells are drilled to date. The sixth and latest appraisal well (Wisting Central III) was drilled in 2017. Planned start of Wisting production is 2028.
Concept selection is anticipated shortly and submission of the plan for development and operation is targeted by end 2022 to qualify for temporary tax incentives established by the Norwegian Government in June 2020.
In addition to the stake in Wisting, Lundin holds surrounding acreage estimated to hold gross unrisked prospective resources of a further 500 million bbl of oil, the company said.
The transaction is subject to customary Norwegian regulatory approvals and is expected to complete in this year’s fourth quarter.
Wisting partners are Equinor (35%), Petoro (20%), and Idemitsu (10%). Equinor is the operator during the development phase and operatorship is planned to transfer to OMV for the operations phase. Prior to completion of the transaction, the company will work with the Ministry of Petroleum and Energy and license partners, to clarify arrangements for the operations phase, Lundin said.
Woodside unveils plans for Kwinana hydrogen, ammonia plant
Woodside Petroleum Ltd., Perth, plans to establish a world-scale hydrogen and ammonia production plant at a site in Kwinana, just south of Perth, in Western Australia.
The project, named H2Perth, has the support of the Western Australian Government. It will be developed on 130 hectares of vacant industrial land to be leased from the state government in the Kwinana Strategic Industrial Area and Rockingham Industry Zone. The land is close to existing gas, power, water, and port infrastructure, as well as a skilled resident workforce, the company said.
Full production potential of the phased development is up to 1,500 tonnes/day of hydrogen for export in the form of ammonia and liquid hydrogen.
Chief Executive Officer Meg O’Neill said the building in the Kwinana location is about more than hydrogen. H2Perth also will facilitate growth of renewables in Western Australia by providing the grid with a flexible and stabilizing load that benefits uptake of intermittent renewable electricity by households and local industry, she said.
The project will stimulate local hydrogen demand, particularly in the transport sector and among local heavy industry. Local refueling stations can be built independently of the export project timelines and could be in operation as early as 2023, subject to approvals and consumer demand.
O’Neill said H2Perth is designed to be a net-zero emissions project for both Woodside and its customers.
Woodside will now begin community engagement along with detailed progress with customers. Subject to commercial and regulatory approvals and a final investment decision, construction of H2Perth is expected to begin in 2024.
Exploration & Development Quick Takes
Eni discovers hydrocarbons in Egypt’s Western Desert
Eni SPA discovered hydrocarbons in Meleiha and South West Meleiha concessions in Egypt’s Western Desert.
The Meleiha discovery came from Jasmine W-1X and MWD-21 wells, and the South West Meleiha discovery came from the SWM-4X wells, 35 km south of Meleiha oil center.
Jasmine W-1X encountered 113 ft net hydrocarbon pay in Jurassic sandstones of the Khatatba formation with good petrophysical properties. The production test rate was 2,000 b/d of light oil (49°API) and 7 MMscfd of associated gas. Jasmine MWD-21 well encountered 51 ft net oil column in Cretaceous sandstones of the Alam El Bueib formation, with excellent petrophysical properties. It is already tied-in to production, with a stabilized rate of 2,500 b/d.
In South West Meleiha, the SWM-4X well encountered 36 ft of net oil sand in Cretaceous sandstones of the Bahariya formation, with excellent petrophysical properties. The production test rate was 1,800 b/d with 0.3 MMscfd.
Preliminary resource estimates associated with these new discoveries are 50 MMboe hydrocarbons in place.
Eni is continuing to pursue near field and infrastructure-led exploration in the Egyptian Western Desert through Agiba, a joint venture between Eni and Egyptian General Petroleum Corp. (EGPC). The new discoveries add more than 6,000 boe/d to Eni’s gross production and can potentially add appraisal and production wells to sustain Agiba’s production plateau.
Eni, through its subsidiary IEOC, holds 76% participating interest in the Meleiha concession while LUKOIL holds the remaining 24%. Both companies are parties in this concession with EGPC and the Government of Egypt.
In the South West Meleiha concession, Eni, through its subsidiary IEOC, holds 100% participating interest. IEOC, EGPC and the Government of Egypt participate in the concession as parties.
ExxonMobil drills dry hole on Canje block, offshore Guyana
ExxonMobil drilled a dry hole in the Sapote-1 well on Canje block, offshore Guyana, according to Westmount Energy Ltd. through a shareholder communication from investee company JHI Associates (BVI) Inc.
The well is in the southeastern section of Canje, some 50 km north of the Haimara discovery in Stabroek block (OGJ Online, Aug. 31, 2021). It was drilled by the Stena DrillMAX drillship in 2,549 m of water to a total depth of 6,758 m and encountered non-commercial hydrocarbons in one of the deeper exploration targets.
The immediate focus of the Canje joint venture group “now switches to synthesis, analysis and regional integration and modelling of the extensive multi-play data suite acquired during the 2021 drilling campaign with a view to high grading and selection of the potential follow-on drilling targets on the block,” said Gerard Walsh, executive chairman, Westmount. ExxonMobil subsidiary Esso Exploraiton & Production Guyana Ltd. has submitted to the Guyanese Environmental Protection Agency an application for environmental authorization with respect to a new 12-well drilling program on the block from 2022, he continued.
Esso is operator at Canje block with 35% interest. Partners are Total (35%), JHI (17.5%), and Mid-Atlantic Oil & Gas Inc. (12.5%).
Aker BP makes minor discovery in Mugnetind, Southern North Sea
Aker BP and partners made a minor discovery in the Mugnetind well in production license (PL) 906 in the southern North Sea. Based on preliminary estimates, the discovery contains recoverable resources of 5-11 MMboe, which is not considered to be commercial in isolation. The well will
be plugged.
Mugnetind was drilled on a seismic anomaly, which had been identified predrill as either a hydrocarbon filled reservoir or coal. Exploration well 7/11-14 S encountered hydrocarbons in the Upper Jurassic Ula formation which was reached at a vertical depth of 3,985 m below sea level and consisted of a 28 m gross section with 14 m net sandstone of moderate to good quality. The reservoir section in Mugnetind is thinner than predicted with a thick coal layer immediately under the reservoir.
Helge Hammer, chief executive of license partner Longboat Energy Norge AS, said that while the company is disappointed the prospect has come in below pre-drill expectations, it will continue to “review opportunities in the area and the potential for finding a commercial development solution.”
Longboat plans to continue a fully funded well program with Ginny-Hermine expected later in 2021 and the Kveikje and Cambozola wells spudding in spring 2022.
Aker BP ASA is operator at PL906 (60%) with partners DNO Norge AS (20%) and Longboat Energy (20%).
Drilling & Production Quick Takes
Aker BP starts production from Aerfugl Phase 2
Aker BP ASA started Phase 2 production at Aerfugl field in the Norwegian Sea. The Aerfugl reservoir (formerly Snadd) was discovered in 2000 and lies just west of Skarv field, about 210 km west of Sandnessjøen in 350-450 m of water. It is Aker BP’s northernmost producing field in the Norwegian Sea.
The Aerfugl development consists of subsea installations and is tied into the existing FPSO production vessel on Skarv. Aerfugl has been developed in two phases, with three wells in Phase 1 in the southern part and another three wells in Phase 2 in the northern part. The remaining Phase 2 wells are scheduled to come on stream in fourth-quarter 2021. Aker BP plans to tie-in future developments in the area.
The reservoir—2,800 m below the seabed—contains gas and condensate in sandstone of Cretaceous age in the Lysing formation. Oil precipitates when it is produced up to atmospheric pressure, and gas producers on Aerfugl are also the largest oil producers at Skarv.
The reservoir holds around 300 MMboe, which will add 5 years to the life of the FPSO. CO2 emissions are expected to be reduced by 30-40% per bbl produced.
Aker BP is operator at Aerfugl (30%) with partners Equinor Energy ASA (30%), Wintershall DEA Norge ASA (25%), and PGNiG Upstream Norway AS (15%).
Neptune begins final well campaign on Fenja
Neptune Energy Norge AS started drilling four production wells for the final development phase of Fenja field, 36 km southwest of Njord A platform in 325 m of water in the Norwegian Sea.
Fenja consists of two subsea templates tied back to Njord A via a production pipeline, water and gas injection pipelines, and an umbilical. The wells are planned as two oil producers, one water injector, and a gas injector. The gas injector will be converted to a gas producer towards the end of field life.
The wells are being drilled by the Deepsea Yantai, a semisubmersible rig operated by Odfjell Drilling. The rig is set to drill into the reservoir sections, install the lower completions, and execute well clean-up activities. Drilling is estimated to take about 160 days.
The field is scheduled to come online in first-half 2023 and will produce about 28,000 boe/d at plateau.
Earlier this year, Neptune announced the installation and testing of electrically trace-heated (ETH) pipe-in-pipe which will transport oil from Fenja field to the Njord A platform. At 37 km, it is the world’s longest ETH subsea production pipeline.
Neptune Energy is operator at Fenja (30%) with partners Vår Energi AS (45%), Suncor Energy Norge AS (17.5%), and DNO Norge AS (7.5%).
Timor Resources spuds first onshore well in East Timor in 50 years
Timor Resources Pty Ltd., Brisbane, has spudded the first onshore exploration well in East Timor in more than 5 decades.
The well, Feto Kmaus, lies in production sharing contract TL-OT-1708 in Suai near the island’s southern coast.
It is also the first well to be drilled onshore since East Timor gained its independence from Indonesia in 2002. Historically, drilling dates back to 1910 with the bulk of wells in the country drilled during the 1960s and early 1970s in an area that is noted for 30 oil and seven gas seeps.
There has been no commercial production, but some seepage oil is used by local villagers.
Timor Resources signed the PSC in 2017 and began its campaign by acquiring new 2D seismic data, interpretation of which has identified two prospects, Feto Kmaus and Liurai, both of which have multiple targets.
Historical data combined with modern technology has delineated structural and stratigraphic plays throughout the PSC, the company has said.
An independent assessment by Netherland Sewell in 2018 suggested the region has potential to yield more than 120 million bbl of recoverable oil.
The Feto Kmaus well will be followed immediately by Liurai.
Eastern Drilling is providing the rig and an operations crew. The rig was landed in East Timor last year, but the drilling program has been delayed by the COVID pandemic.
Timor Resources is operator of the program with 50% interest. East Timor’s state-owned company TimorGAP has the remaining 50%.
PROCESSING Quick Takes
Rosneft inks agreement for new complex at Ryazan refinery
PJSC Rosneft has let a preliminary contract to Maire Tecnimont SPA to provide a series of services for construction of a grassroots vacuum gas oil (VGO) hydrocracking complex at Rosneft subsidiary JSC Ryazan Oil Refining Co.’s (RORC) 17.1-million-tpy refinery in Russia’s Central Federal District, about 200 miles southeast of Moscow
As part of the agreement, Maire Tecnimont’s anticipated scope of work will include design, supply of equipment and materials, construction, startup and commissioning, and project finance services for the proposed VGO hydrocracking complex, the implementation of which will enable RORC to increase conversion of heavy VGO volumes from the refinery’s vacuum distillation unit into Russian Class 5 (Euro 6-quality equivalent) gasoline, kerosine, and diesel fuels, Rosneft and the service provider said on Oct. 28.
To be equipped with energy-efficient, environmentally friendly equipment technologies and equipment that includes an automated control system to help reduce the plant’s carbon footprint, the planned VGO hydrocracking complex will feature hydrocracking units, hydrogen production units, elemental sulfur production units, as well as associated off-site installations, according to the parties.
Without disclosing further details regarding the proposed project, Rosneft and Maire Tecnimont said RORC’s VGO hydrocracking complex comes as part of Rosneft’s broader, ongoing modernization program to upgrade its company-wide refining system to boost production and supply of Class 5-quality fuels for the Russian domestic market.
Rosneft said, to date, it has invested more than 900 billion rubles—or about $13 billion—on modernization works to increase Class 5-quality fuel output of its refineries, which has involved both new construction or revamping of 23 major units across the system (OGJ Online, June 22, 2020; Mar. 19, 2018).
REG lets contract for Geismar renewable fuels expansion
Renewable Energy Group Inc. (REG), Ames, Iowa, has let a contract to John Wood Group PLC to provide a suite of services to support a 250-million gal/year capacity expansion and improvement project now under way at its existing 90-million gal/year renewable diesel refinery in Geismar, Ascension Parish, La.
As part of the Nov. 2 contract announced on Nov. 2, Wood is delivering engineering, procurement, and construction management (EPCM) services for the expansion and related works at the refinery to improve the site’s operational reliability and logistics, the service provider said.
Recently combined with an original plant improvement project, the Geismar expansion project, which broke ground on Oct. 13, will involve upgrades to the existing site as well as construction of an existing site to accommodate Geismar’s aggregate finished renewable diesel production capacity increase to 340 million gal/year (OGJ Online, Oct. 18, 2021).
Alongside expanding renewable diesel production, REG’s Geismar project will include planned improvements involving works to expand the site’s marine logistics to enable global trading of feedstocks and fuel, for which International-Matex Tank Terminals LLC will build out storage tanks and related logistics infrastructure at its nearby Geismar bulk-liquid storage and marine terminal to accommodate REG’s increased production.
Previously estimated to require a minimum $825-million capital investment, REG in early August estimated overall cost of its revised Geismar project at about $950 million.
The project is on schedule to reach mechanical completion by 2023, with full commissioning of the expanded plant in 2024.
Once online, fuel produced at REG’s expanded Geismar plant will reduce CO2 emissions by up to 2.8 million tonnes/year.
TRANSPORTATION Quick Takes
Williams net income slips despite gas gathering, transmission records
Williams Cos. had net income of $164 million in third-quarter 2021 on adjusted earnings before interest, taxes, and depreciation (EBITDA) of $1.42 billion, compared with third-quarter 2020 figures of $308 million and $1.27 billion respectively. The lower net income was primarily attributed to a $277-million net unrealized loss in Williams’ Sequent Energy Management LP business segment. Williams completed its acquisition of Sequent from Southern Co. Gas in July 2021. The company also reported record quarterly gathering volume of 14 bcfd and record quarterly contracted transmission capacity of 23.8 bcfd.
It will put the second phase of its 582-MMcfd Leidy South expansion in full service in time for the winter heating season and is executing another 1.5 bcfd in expansions along its Transcontinental Gas Pipe Line (Transco) and Gulfstream transmission corridors. Williams brought 125 MMcfd of Leidy South capacity online in November 2020 and 382 MMcfd in November 2021. The remaining 75 MMcfd is expected to be online by year-end 2021.
Included in the additional Transco expansion are two Mid-Atlantic projects adding 523 MMcfd to the system. Commonwealth Energy Connector will add 100 MMcfd and Southside Reliability Enhancement 423 MMcfd. Williams also filed a US Federal Energy Regulatory Commission application in March 2021 for its 829-MMcfd Transco Regional Energy Access expansion, designed to connect Marcellus shale natural gas production to Northeast demand by the 2023-24 heating season.
During third-quarter 2021 the company reached agreement with Shell Offshore and Chevron USA for an expansion project to provide transportation from the Whale offshore development to Williams’ Perdido infrastructure in the Western GoM. It expects the project to come online in 2024.
Adjusted EBITDA of $630 million Williams’ Transmission & Gulf of Mexico (GoM) segment, its largest, was $8 million higher than third-quarter 2020. Its largest percentage gains came in its West segment, in which adjusted EBITDA increased to $293 million from $245 million.
The company attributed its improved Transmission & GoM earnings to increased revenues from transmission expansion projects and favorable commodity margins; partially offset by slightly higher segment operating costs and hurricane-related shut-ins. In the West, higher results were driven by favorable marketing margins, lower maintenance expenses, and higher gathering and processing commodity-based rates.
Empire, APA Group sign infrastructure MoU for Beetaloo
Empire Energy Ltd. and the APA Group, Sydney, signed a memorandum of understanding (MoU) to evaluate opportunities to develop Beetaloo basin midstream infrastructure including gas and liquids gathering, processing, and pipelines to market.
The companies will seek to enter agreements for APA to build, own, and operate infrastructure to move gas and liquids from Empire’s Beetaloo discoveries in the Northern Territory and promote a common user model for development to drive economies of scale and lower cost per unit charges.
APA proposes a staged incremental development approach, leveraging its network to reduce the required initial capital investment and align the pace of upstream development.
The MoU does not restrict Empire from negotiating a deal for use of the existing McArthur River gas pipeline, it said.
APA’s northern strategy envisions an expansion of the Amadeus gas pipeline through additional gas compression to augment the Northern Territory government’s plans to develop gas-supported industry and LNG export expansion in Darwin.
APA’s eastern strategy includes development of a greenfield pipeline between the Amadeus gas line and the Carpentaria gas pipeline at Mt. Isa in Queensland to bring gas to southern markets. The proposed new Beetaloo pipeline will become part of the existing APA gas distribution network and be the most capital-efficient model for connecting the Beetaloo discoveries to market.
