OGJ Newsletter

GENERAL INTEREST Quick Takes

WoodMac: Global deepwater production to increase 60% by 2030

Global deepwater production will increase 60% by 2030, reaching 17 million boe/d, according to a report from Wood Mackenzie.

The report highlights the sector’s expansion to 8% by the end of the decade from 6% of upstream oil and gas supply today.

“Deepwater is the fastest growing oil and gas resource theme,” said Marcelo de Assis, director of upstream research for Wood Mackenzie. “Brazil, Guyana, and Mozambique are the main growth drivers. Developments are also getting deeper; production from water depths of over 1,500 m will surpass that from 400-1,500 m by 2024.”

Wood Mackenzie’s analysis shows that traditional growth regions, such as the US Gulf of Mexico and Angola, have lacked in major new commercial discoveries.

“The forecast for mature deepwater basins remains uncertain. We could see production performance to begin to peak and then plateau after 2030 without an exploration and investment renaissance,” de Assis said.

“However, the characteristics of deepwater makes it an attractive hunting ground for those seeking advantaged resources. Deepwater economics and emissions intensity metrics are among the best in the industry. Companies focused on the most resilient projects and decarbonization will continue to consider the sector as core to their upstream business models,” he added.

The industry faces other challenges as it matures. Cost inflation has hit global hotspots first, but constraints in the global deepwater supply chain will increase lead times and unit costs across the board. The hard-fought efficiency gains made during previous downturns will start to reverse.

Maintaining the growth, economic and emissions headroom is a challenge being taken on by an increasing number of countries and operators. There are five times more operators and countries with active deepwater sectors than in the 2020s.

But relative to conventional oil and gas, deepwater remains niche. Reflecting on the changes of the last decades and the challenges of the years ahead, de Assis concluded, “the future of the deepwater sector remains in their hands of the majors and Brazil’s Petrobras for the foreseeable future.”

bp awarded exploration interest in blocks offshore Egypt

bp has been awarded interest in two new exploration blocks in the Mediterranean Sea, offshore Egypt, by Egyptian Natural Gas Holding Co.

The Northwest Abu Qir Offshore Area is west of the recently awarded North King Mariout block and north of Raven field. It covers an area of about 1,038 sq km in water depths of 600-1,600 m. bp is operator with 82.75% interest. Wintershall-Dea holds the remaining 17.25%.

The Eni SPA-operated Bellatrix-Seti East block lies west of Atoll field and North Tabya blocks. It covers an area of about 3,440 sq km in water depths of 100-1,200 m. Eni and bp each hold 50% interest.

In addition to the two new blocks, in 2022 bp was awarded interest in the King Mariout Offshore area (100%), Eni-operated North El Fayrouz offshore area (Eni 50%, bp 50%), and the North El Tabya area extension (100%).

Chevron, MOL to study CO₂ shipping from Singapore to Australia

Chevron Corp., through its Chevron New Energies International Pte. Ltd. (Chevron) subsidiary, and Mitsui O.S.K. Lines Ltd. (MOL) will explore the technical and commercial feasibility of transporting liquified CO2 from Singapore to permanent storage locations offshore Australia.

“Developing safe and reliable CO2 transportation services is a crucial step in developing large scale carbon capture, utilization, and storage solutions, said Mark Ross, president of Chevron Shipping Co., in a release Nov. 10.

Under the agreement, the companies will study feasibility of initial transport of up to 2.5 million tonnes/year (tpy) of liquified CO2 by 2030.

The agreement will complement work to be advanced by a  consortium to explore solutions for large-scale carbon capture, transport, and permanent storage of CO2 from Singapore (OGJ Online, Sept. 21, 2022).

Northern Lights preliminarily confirms 5-million tpy storage capacity

Northern Lights JV DA concluded drilling operations for a CO₂ injection well and a contingent injection well within its CO₂ storage license EL001 in the North Sea about 70 km west of Bergen. Drilling began in August using the Transocean Enabler semisubmersible rig.

Preliminary results confirm the storage capacity of at least 5 million tonnes CO₂/year, sufficient for the first two phases of the project, said Børre Jacobsen, managing director, Northern Lights, in a Nov. 11 release (OGJ Online, Mar. 24, 2022). To utilize the capacity, the JV will need to drill additional injection wells.

In 2020, Northern Lights drilled the first CO₂ exploration well that confirmed that the reservoir in the Johansen formation, at 2,600 m depth, is suitable for safe and permanent CO₂ storage.

Northern Lights is a registered and incorporated general partnership with shared liability owned by Equinor Energy AS, Shell plc, and TotalEnergies SE. It is developing the world’s first open-source CO₂ transport and storage infrastructure.

Equinor managed drilling operations on EL001 on behalf of Northern Lights.

 Exploration & Development Quick Takes

Equinor to tie Irpa back to Aasta Hansteen

Equinor Energy AS has submitted a plan for development and operation (PDO) to the Norwegian Minister for Petroleum and Energy for Irpa gas discovery in Vøring basin, 340 km west of Bodø in the Norwegian Sea in 1,350 m of water.

The discovery will be developed with three wells and an 80-km tie-back pipeline to the Aasta Hansteen platform. It is the only planned deepwater development in Norway.

Gas will be phased into existing infrastructure over Aasta Hansteen and transported to the Nyhamna gas processing plant via Polarled. From there, gas will be transported via the Langeled pipeline system to the UK and continental Europe.

The development will have a total cost of NOK 14.8 billion in 2022. The field is scheduled to come on stream fourth-quarter 2026. There will be joint production from Irpa and Aasta Hansteen through 2031 and then Irpa will continue to produce until 2039.

Irpa, formerly known as Asterix, was proven in 2009. Expected recoverable resources are estimated at about 124 MMboe.

Equinor Energy AS is operator at Irpa (51%) with partners Wintershall DEA (19%), Petoro AS (20%), and Shell PLC (10%).

Neptune Energy encounters hydrocarbons near Draugen field

Neptune Energy will consider additional data gathering and reservoir testing after encountering hydrocarbons in the Calypso exploration well in the Norwegian Sea.

The prospect lies on the Norwegian Continental Shelf, 14 km northwest of Draugen field and 22 km northeast of Njord A platform in PL 938. Logs proved the presence of hydrocarbons, but operations in the reservoir section are at an early stage and commercial volumes are not yet confirmed, the operator said in a release Nov. 16. 

The well is being drilled by the Deepsea Yantai and comprises a mainbore (6407/8-8 S) with an optional sidetrack (6407/8-8 A) based on the outcome of the exploration well. The reservoir target is the middle and lower Jurassic formations. It is expected to be reached at a depth of about 2,960 m. In the event of a commercial discovery, Calypso could be tied back to existing infrastructure (OGJ Online, Nov. 2, 2022).

Neptune Energy is operator of the license (30%) with partners OKEA ASA (30%), Pandion Energy AS (20%), and Vår Energi ASA (20%).

TotalEnergies, APA deem Awari prospect noncommercial

TotalEnergies and partner APA Corp. have deemed an exploration well in the previously untested northwest portion of Block 58 offshore Suriname noncommercial.

Drilling operations have concluded at the Awari prospect, APA Corp. said in a release Nov. 28.

Elsewhere on the block, the joint venture will begin flow test operations at the Sapakara South-2 (SPS-2) appraisal well following drilling to the targeted Maastrichtian-Campanian formation. Results are expected in December. SPS-2 lies about 4.6 km south of Sapakara South-1.

TotalEnergies is operator of the 50-50 joint venture with APA Corp.

Sinopec discovers shale gas in Sichuan basin

China Petroleum & Chemical Corp (Sinopec) discovered a new gas field in Sichuan basin. The Qijiang shale gas field adds new geological reserve of 145.9 billion cu m, the company said in a release Nov. 25.

Qijiang is the first shale gas field discovered in medium-deep and deep strata in a complex tectonic zone on the margin of the basin. Shale gas reserves at the field lie at depths of 1,900-4,500 m, with the majority deeper than 3,500 m.

Sinopec conducted more than 10,000 lab analysis tests on the core at 1,320 m depth and obtained 3D seismic data covering an area of 3,662 sq km in the southeastern margin of the basin. Analysis revealed the development and maintenance mechanism of deep shelf shale pores and proved that the deep shale can develop vast reservoirs with high porosity, the company said.

 Drilling & Production Quick Takes

Gas leak shuts down Santos offshore gas field

Santos Ltd. has shut down John Brookes gas field offshore Western Australia following detection of a gas leak from a subsea flange on the main 50 km trunkline to the Varanus Island gas treatment infrastructure.

The leak was discovered during routine work on the normally unmanned John Brookes platform, the company said. Bubbles were seen rising to the sea surface about 20 m from the platform.

Both the pipeline and platform were immediately shut in and depressurized. All personnel were evacuated.

John Brookes field, which lies in production license WA-29-L in the Carnarvon basin, supplies about a quarter of the gas fed into the 390 terajoules/day Varanus Island plant which, after treatment, is then sent to Western Australian mainland’s domestic grid.

The pipeline will remain shut in until the source of the leak has been confirmed and the integrity of the line has been restored, the company said. Repairs are expected to take 4-6 weeks to allow for a return to full production.

John Brookes field was discovered in 1998 in about 100 m water depth and brought on stream in 2005.

Santos is 100% interest holder and operator.

bp Trinidad and Tobago delivers first gas from Cassia C

bp Trinidad and Tobago LLC (bpTT) delivered first gas from its Cassia C development 57 km off the southeast coast of Trinidad.

Cassia C is bpTT’s first offshore compression platform. It will enable bpTT to access and produce low pressure gas resources from the Greater Cassia area. The platform is connected to the existing Cassia hub. bpTT operates in about 680,000 acres off Trinidad’s east coast and now has 16 offshore platforms and two onshore processing plants. 

Cassia C is expected to produce, at peak, about 200-300 MMscfd.

The platform’s jacket was built at Trinidad Offshore Fabricators and installed in 2020. Its topside structure was built in the McDermott fabrication yard, Altamira, Mexico, and was installed in 2021.

First gas from Cassia C follows the recent sanction of the Cypre development and the execution of the gas supply agreement with the National Gas Co. 

Shell begins Pensacola prospect drilling

Shell UK Ltd. has begun drilling operations at License P2252 in the Pensacola prospect, northwest of Breagh gas field in the Zechstein Reef play fairway, Southern North Sea, according to a release by license partner Deltic Energy.  

The Maersk Resilient rig has been installed on Pensacola and drilling operations are expected to last 60-90 days. The well will be plugged and abandoned after completion of operations.

The Pensacola prospect is a Z2 Zechstein reef partially mapped on 3D seismic data and is analogous to similar structures identified on adjacent blocks. The reef is 15 km long by 6 km wide, clearly defined on 2D and 3D seismic, and builds to more than 200 m above the surrounding Z2 (Hauptdolomite) platform (OGJ Online Oct. 22, 2021).

Deltic estimates that Pensacola contains 309 bcf gross P50 prospective resources. Commercialization options include export via existing Breagh infrastructure or a new pipeline to Teesside.

Shell is operator of the license with 70% interest. Deltic Energy holds the remaining 30%.

Norway production up in October, NPD says

Norway’s production averaged 1.950 million in October, the Norwegian Petroleum Directorate (NPD) reported. The figure is up from the 1.832 million b/d produced in September (OGJ Oct. 20, 2022).

Average daily liquids production in October consists of 1.745 million b/o, 187,000 bbl of NGL, and 19,000 bbl of condensate.

Oil production in October was 7.3% lower than the NPD’s forecast and 5.4% lower than the forecast so far this year.

 PROCESSING Quick Takes

TotalEnergies lets contract for Grandpuits refinery-to-renewables project

TotalEnergies SE has let a contract to Air Liquide SA to supply renewable, low-carbon hydrogen for production of sustainable aviation fuel (SAF) as part of the operator’s Project Galaxie repurposing of its 101,000-b/d Grandpuits refinery at Seine-et-Marne near Melun in northern France. TotalEnergies intends to convert the site into a zero-crude industrial platform by 2025 (OGJ Online, Sept. 28, 2020).

As part of the long-term supply contract, Air Liquide will invest more than €130 million to build and operate a grassroots hydrogen production unit (HPU) based on its proprietary Cryocap carbon-capture technology, TotalEnergies and Air Liquide said Nov. 22.

Configured to partly use recycled residual biogas from the SAF biorefinery under construction at Grandpuits, the new HPU will produce more than 20,000 tonnes/year (tpy) of renewable, low-carbon hydrogen, most of which will be returned to the biorefinery to enable additional SAF production.

By replacing natural gas typically used to produce hydrogen with the biorefinery’s recycled residual biogas, the HPU will reduce carbon dioxide (CO2) emissions by about 150,000 tpy compared with existing hydrogen production process, while its use of Cryocap technology will capture more than 110,000 tpy of CO2 for reuse in food and industrial applications, according to the companies.

Alongside supporting the operator’s conversion of Grandpuits into a zero-crude industrial platform, TotalEnergies and Air Liquide said the combined low-carbon, CO2-capturing HPU project at Grandpuits is part of a broader collaboration to support TotalEnergies’ plan to decarbonize all hydrogen used at its European refineries by 2030.

This latest contract for the more than €500-million Project Galaxie at Grandpuits follows TotalEnergies’ recent agreement with SARIA AS GmbH & Co. KG to partner on SAF production at the site (OGJ Online, Sept. 26, 2022).

Already under way, Project Galaxie includes construction of the new biorefinery that will use Honeywell UOP LLC’s proprietary UOP Ecofining technology to process what initially was planned to be 400,000 tpy of mostly animal fats from Europe and used cooking oil—supplemented with other vegetable oils like rapeseed but excluding palm oil—primarily from local suppliers to produce 170,000 tpy of SAF; 120,000 tpy of renewable diesel; and 50,000 tpy of renewable naphtha for production of bioplastics.

TotalEnergies—which discontinued crude oil refining at Grandpuits in first-quarter 2021 and will cease storage of petroleum products at the site by late 2023—most recently said it remains on schedule to commission new units at Grandpuits in 2022-24 to reach full operation of the zero-crude platform by 2025.

Supplying SAF to French aircraft operators since 2021, TotalEnergies also began producing SAF in early 2022 at its 253,000-b/d integrated Normandy refining and petrochemicals platform in Gonfreville l’Orcher, France (OGJ Online, Apr. 28, 2022).

The company also has confirmed it is working on pilot units near its 227,000-b/d Leuna refinery in central Germany to make molecules that can be converted into methanol and SAF using green hydrogen and captured CO2 (OGJ Online, Sept. 19, 2022).

The downstream projects are part of TotalEnergies’ broader commitment to achieve net-zero emissions across its global operations by 2050 in accord with its commitments under the Paris Agreement.

 TRANSPORTATION Quick Takes

QatarEnergy, ConocoPhillips to provide LNG to Germany

QatarEnergy and ConocoPhillips signed two agreements to supply up to 2 million tonnes/year (tpy) of LNG to Germany. The suppliers are joint venture companies established between ConocoPhillips and QatarEnergy to participate in the North Field East (NFE) and North Field South (NFS) projects, and the buyer is a wholly owned subsidiary of ConocoPhillips.

First delivery is expected in 2026 to the 8-billion cu m/year German LNG Terminal at Brunsbüttel (OGJ Online, Mar. 2, 2022). The agreements mark the first ever long-term LNG supply to Germany with a supply period that extends for at least 15 years, QatarEnergy said in a release Nov. 29. 

Through its joint ventures with QatarEnergy, ConocoPhillips holds a 3.125% interest in the NFE project and a 6.25% interest in the NFS project. The projects are expected to begin production in 2026 and 2027, respectively. 

Sempra to take Port Arthur LNG Phase 1 FID first-quarter 2023

Sempra Energy will take first-quarter 2023 final investment decision (FID) on its 13.5-million tonne/year (tpy) Port Arthur LNG Phase 1 project in Texas. The company is targeting a 2027 in-service date for the plant.

Last month Sempra finalized its fixed-price engineering, procurement, and construction contract for Port Arthur LNG Phase 1 (OGJ Online, Oct. 20, 2022). A similarly sized Port Arthur LNG Phase 2 project is under active marketing and development.

Sempra also continues to advance its 6.75-million tpy Cameron LNG Phase 2 project and anticipates FID after the front-end engineering and design process is completed, currently targeted for third-quarter 2023. The single-train expansion would boost Cameron’s capacity to more than 20.25 million tpy (OGJ Online, Apr. 4, 2022).

In reference to Port Arthur Phase 2, Sempra chief executive officer Jeffrey Martin noted in the company’s third-quarter 2022 earnings call that “volumes currently committed at Cameron…could be moved over to support Phase 2” and that “roughly 3 [million tpy] of capacity [are] in advanced negotiations.” His remarks came in response to an analyst asking about reports that Williams Cos. would be a Port Arthur Phase 2 supplier.

Commonwealth LNG gets FERC approval for Louisiana plant

Commonwealth LNG LLC has received US Federal Energy Regulatory Commission approval for its 8.4-million tonne/year (tpy) liquefaction plant in Cameron Parish, La. The company filed its application in August 2019 and expects to begin shipments from the plant in third-quarter 2026.

Commonwealth plans to begin preliminary site work on the side of the Calcasieu Ship Channel near the Gulf of Mexico in early 2023, with final investment decision targeted for third-quarter 2023. The project will include:

• Six 1.4 million tpy liquefaction trains, each with a 60-Mw gas turbine with mechanical drive.
• Six 50,000 cu m full-containment LNG storage tanks.
• A single berth with the capacity to service vessels as large as 216,000 cu m.
• A potable water supply line from existing municipal water systems.
• A 180-Mw simple-cycle electric power generator for auxiliary loads, including emergency and back-up systems.
• Various buildings and structures.
• A 3.04-mile, 42-in. OD natural gas pipeline with tie-ins (including metering and emergency shut-off systems) at EnLink Bridgeline Holdings LP’s existing 12- and 20-in. OD pipelines and Kinetica Partners LLC’s 16-in. OD Kinetica pipeline.
• An interconnection to the LNG terminal, including a pig receiver, separator, liquid storage, custody transfer meters, pressure regulators, emergency shutdown valves, and gas analyzers.

The plant will have a peak liquefaction capacity of up to 9.5 million tpy and the pipeline will be capable of delivering 1.44 bcfd.

The Department of Energy (DOE) in 2020 authorized Commonwealth to export 9.5 million tpy for 25 years to nations with which the US has a free trade agreement (FTA). Commonwealth’s application to export to non-FTA nations is pending with DOE.