Petroliam Nasional Bhd. (Petronas) has announced a third hydrocarbon discovery in Suriname’s

offshore Block 52, a joint venture with ExxonMobil Corp. The Fusaea-1 exploration well, which

commenced drilling in February, reached a total depth of 5,227 meters (17,149 feet). It revealed

“several oil and gas-bearing Campanian sandstone reservoir packages,” Petronas stated. “Further

evaluation is underway to determine the full extent of this discovery and its potential for integration

with the recent Roystonea-1 and Sloanea-1 discoveries.” Mohd Redhani Abdul Rahman, Petronas

Vice President for Exploration, remarked, “The success of Fusaea-1 demonstrates our improved

geological understanding of this region, strengthened by breakthroughs in Roystonea-1 and

Sloanea-1. These discoveries have significantly enhanced the prospects and integrated development

potential within Block 52.” Petronas continues to focus on sustainable and high-value resource

exploration in selected regions as part of its portfolio rationalization efforts. Block 52, located in the

Suriname-Guyana basin, covers 4,749 square kilometers (1,833.6 square miles) north of Paramaribo,

Suriname’s capital. Petronas Suriname E&P BV operates Block 52, while ExxonMobil Exploration and

Production Suriname BV holds the other half. Petronas announced its first Block 52 discovery on

December 11, 2020, through the Sloanea-1 well, marking its first exploration success in Suriname.

The well yielded “several hydrocarbon-bearing sandstone packages with good reservoir qualities in

the Campanian section,” according to a Petronas press release at the time. Last month, Suriname’s

national oil and gas company Staatsolie Maatschappij Suriname NV revealed that the Block 52

partners agreed to further explore the Sloanea area for potential gas production. Staatsolie stated,

“The letter of agreement (LoA) is necessary for further exploration of the gas discovery made in

2020 with the Sloanea-1 exploration well in Block 52.” Initially considered commercially unattractive

due to its small quantity, the development of an offshore gas field poses more technical and

economic challenges compared to an offshore oil field. Nevertheless, discussions between Petronas

and Staatsolie have led to the LoA, with plans for Petronas to drill the Sloanea-2 appraisal well

starting in April 2024, followed by a production test. Staatsolie emphasized that the LoA outlines

the principles and conditions to enhance the feasibility of developing a commercial gas field in Block

52. An essential part of the feasibility is a ten-year tax-free period from the start of production,

granted with governmental approval. The LoA serves as a basis for further negotiations on a gas

addendum to the production sharing contract (PSC) for Block 52, signed in April 2013. In the event

of a gas discovery, the PSC mandates a negotiation of a “Gas Addendum,” which will establish the

procedures and conditions for assessing and potentially developing and producing the gas

discovery. Petronas aims to start gas production by 2031 if Sloanea-2 proves commercially

successful. Additionally, the construction of a floating liquefied natural gas facility is being

considered, according to Staatsolie.

A recent report by GlobalData unveiled Saudi Aramco as the foremost investor in artificial intelligence (AI) within the oil sector, spending $3.5 billion on research and development last year. Aramco’s expansive investments extend to 250 areas of innovation, encompassing AI, drone tech, robotics, and electric vehicles.

The deployment of AI in oil exploration, fault monitoring, and cyber threat detection underscores the industry’s embrace of advanced technology. Despite its traditional image, Aramco is actively adopting cutting-edge tech to enhance operations, evident in initiatives like the Saudi Accelerated Innovation Laboratory (SAIL). This strategic move aligns with Saudi Arabia’s efforts to diversify its revenue streams beyond crude oil, akin to the UAE’s diversification strategy in construction.

AI promises significant cost savings for oil production, particularly in the U.S. shale patch, with potential benefits including improved well productivity, accurate exploration, and enhanced threat detection. Moreover, the abundant energy resources within the industry position AI as a transformative force, signaling a new era of tech-driven oil production.

In a contentious move, the government led by Rishi Sunak will permit fossil fuel companies to explore for oil and gas beneath offshore wind-power sites. The North Sea Transition Authority (NSTA) will grant licenses to approximately 30 companies to search for hydrocarbons in areas designated for future offshore wind farms.

This decision has sparked renewed criticism from environmentalists, including the government’s former net zero champion, who fear it could undermine clean energy efforts. While proponents argue that any production could utilize wind turbine power to reduce emissions, experts caution that the environmental impact of burning extracted oil and gas will outweigh any benefits. The announcement is expected to dent investor confidence in the UK’s green energy sector, with offshore wind investors expressing concern.

Sunak’s policy rollbacks, aimed at lowering energy costs and enhancing security, have faced criticism for potentially politicizing climate issues ahead of the upcoming general election.

Analysts from Standard Chartered Bank emphasize the significance of May and June in shaping oil market fundamentals for the first half of 2024. These months are forecasted to witness a substantial tightening compared to previous years, with global stock draws expected to reach 189 million barrels.

Key to this trend is the anticipated surge in demand, set to hit record highs during these months. The analysts stress the need for close monitoring to assess market tightening accurately. Additionally, insights into OPEC+ decisions depend heavily on understanding the fundamentals of May and June. Meanwhile, analysts at Morningstar DBRS note stronger-than-expected oil demand in 2024, cautioning against potential disruptions from geopolitical conflicts.

They project eventual moderation in oil prices but highlight ongoing risks.

Vår Energi ASA has announced a significant oil discovery in the Balder area of the Central North Sea. The company’s latest exploration well in production license PL 956, the Ringhorne North well, was successful, with estimated recoverable resources ranging from 13 million to 23 million barrels of oil. Drilled by the semi-submersible rig Deepsea Yantai, the Ringhorne North well and two additional side-track/appraisal wells are located five miles (eight kilometers) north of the Vår Energi-operated Ringhorne field, approximately 124 miles (200 kilometers) northwest of Stavanger.

Vår Energi considers this discovery a potential commercial candidate for tie-in to nearby existing infrastructure in the Balder area. The company’s COO, Torger Rød, highlighted the success of their near-field exploration strategy and emphasized the potential for further value creation in the Balder area. Rune Oldervoll, EVP for Exploration and Production at Vår Energi, reiterated the company’s commitment to exploring for further resources, leveraging both their experienced team and the expertise of major shareholder Eni. The discovery not only unlocks new resources and extends the Ringhorne field but also de-risks additional prospects in the area and offers development synergies with other nearby Vår Energi-operated discoveries such as King-Prince and Evra-Iving.

Furthermore, the discovery supports the long-term development plans for the Balder area as a key production hub in the North Sea, contributing to Vår Energi’s goal of producing high-value, low-emission barrels for years to come. The license partners for PL 956 include Vår Energi (50%), Aker BP ASA (20%), Harbour Energy Norge AS (15%), and Sval Energi AS (15%). Vår Energi also highlighted its impressive discovery rate of over 50% in the past five years, with costs of less than $1 per barrel post-tax.

BP Plc has implemented a top management restructuring, allowing new Chief Executive Officer Murray Auchincloss to make his mark on the oil and gas giant as some executives depart. In an effort to simplify the organizational structure and enhance the company’s value, the executive leadership team will be reduced to 10 members, according to a statement released on Thursday.

William Lin, former head of regions, corporates, and solutions, will succeed Anja-Isabel Dotzenrath as the leader of natural gas and low-carbon energy, who is retiring. Auchincloss emphasized, “We need to deliver as a simpler, more focused, and higher value company.” He believes that these changes will enable BP to achieve this goal. Emeka Emembolu will assume leadership of BP’s technology division, succeeding Leigh-Ann Russell, who is departing the company, according to the statement. BP will maintain three primary business units: production and operations led by Gordon Birrell; gas and low-carbon energy led by Lin; and customers and products led by Emma Delaney. These divisions will continue collaborating with trading and shipping, overseen by Carol Howle.

Supporting these business units are five functions: finance under the leadership of Kate Thomson; technology led by Emembolu; strategy, sustainability, and ventures managed by Giulia Chierchia; people and culture overseen by Kerry Dryburgh; and legal led by Mike Sosso. The company’s regions, corporates, and solutions organization will be integrated into these businesses and functions, as outlined in the statement.

Methane emissions along the Oil & Gas production chain have garnered significant attention in the international climate debate due to their high climate-altering potential and the technical-economic feasibility of reducing emissions in the short and medium term.

The main sources of methane emissions stem from unintentional releases into the atmosphere (i.e., fugitive emissions), unburned fractions present in flare gas and exhaust gases from combustion systems, and venting. Eni confirms the stability of Upstream emission intensity below 0.2%, in line with the “well below 0.2%” target of the Oil and Gas Climate Initiative (OGCI) by 2025, which Eni has already achieved. This is achieved by focusing particularly on reducing fugitive emissions and through projects for methane abatement from venting and flaring. Eni’s methane emissions have decreased by over 50% in 2022 compared to 2018, primarily due to the implementation of Leak Detection And Repair (LDAR) campaigns in almost all Eni-operated assets. In 2022, Eni has contributed to launching the Aiming for Zero Methane Emissions initiative with OGCI, which now has over 90 participating companies.

To ensure greater transparency in methane emission reporting, the company is implementing a measurement plan at their operated sites using the best available technologies on the market, in line with international guidelines shared in the OGMP 2.0 program. This campaign will also allow Eni to set a new emission reduction target for 2024. In 2023, Eni achieved the Gold Standard, recognition obtained for presenting a robust implementation plan for emission reporting in line with the OGMP 2.0 program.

China Petroleum & Chemical Corporation (Sinopec) has achieved a significant milestone by completing the drilling of the Fushen-1 Well in Hainan, marking the deepest geothermal exploration well in China at a depth of 5,200 meters. This achievement not only uncovers the deep geothermal formation and enrichment processes in South China but also marks a significant advancement in the exploration of hot dry rock, both in terms of geographical scope and depth. This breakthrough is pivotal for the large-scale development and utilization of geothermal resources in South China, contributing to the adjustment of the energy structure. The Fushen-1 Well targets granite formations estimated to be 250 million years old.

Since the commencement of the exploration in August 2023, Sinopec has implemented several proprietary innovative technologies. These include a dual-drive drilling technique combined with high-pressure injection, enabling the team to reach the temperature limits for hot dry rock as defined by national energy industry standards. This exploration has led to the development of key technologies for the detection and evaluation of deep geothermal resources. Moving forward, Sinopec plans to conduct comprehensive research and field tests at the Fushen-1 Well. The aim is to establish South China’s first integrated platform for deep geothermal research, education, and experimentation. This initiative will support the development of theoretical methods and technical systems tailored to the region, aiding China in achieving its “Dual-Carbon” objectives. Deep geothermal energy, recognized for its stability, reliability, and ecofriendly nature, represents a promising avenue for renewable energy development. With vast reserves and widespread availability, deep geothermal energy is a significant, environmentally friendly resource. Geological surveys in China estimate that the hot dry rock geothermal resources within a depth range of 3 to 10,000 meters could equate to 856 trillion tons of standard coal. Extracting just 2% of these resources could fulfill China’s annual energy consumption over 2,993 times as of 2023. Sinopec is dedicated to leading the development and utilization of geothermal energy in China.

The company has already achieved a geothermal heating capacity of nearly 100 million square meters and operates several large-scale regional geothermal heating projects. Through its efforts, Sinopec has developed a series of core technologies for efficient exploration and has contributed to over 50% of the industry standards, including China’s first international geothermal association standard. In 2023, Sinopec also hosted the 7th World Geothermal Congress (WGC2023) in Beijing, underscoring its commitment to advancing geothermal energy development.

Petrobras, the Brazilian state-run oil giant, has made a significant oil discovery in the ultra-deep waters of the Potiguar Basin, located along the Brazilian Equatorial Margin. This discovery was made at the Anhangá exploratory well, identified as 1-BRSA-1390-RNS, within the POT-M-762_R15 Concession. Positioned near the boundary of the Ceará and Rio Grande do Norte states, the well is approximately 118 miles from Fortaleza and 155 miles from Natal, with a depth reaching 7,205 feet. This marks the second discovery in the Potiguar Basin for the year 2024, following the earlier identification of hydrocarbons in the Pitu Oeste Well within the BM-POT-17 Concession, merely 15 miles from Anhangá.

Petrobras, which operates and fully owns both concessions, has indicated that further evaluations are necessary to fully assess these findings. The company’s exploratory efforts in the Equatorial Margin are part of its broader strategy to replenish reserves and explore new frontiers, ensuring the fulfillment of global energy demands throughout the ongoing energy transition. The discovery of oil in Albian-age turbidite reservoirs within the Potiguar Basin is hailed as a groundbreaking achievement for the region. Petrobras plans to continue its exploration in the POT-M-762_R15 concession to determine the quality of the reservoirs, the characteristics of the oil, and the potential commercial viability of the discovered accumulation. Petrobras CEO, Jean Paul Prates, highlighted the company’s impeccable safety record in drilling almost 3,000 wells in deep and ultra-deepwater environments, underscoring its technical prowess and environmental stewardship over nearly seven decades. Joelson Mendes, Petrobras Exploration and Production Director, emphasized the strategic importance of the Equatorial Margin as a promising new frontier that is crucial for Brazil’s future oil supply and development.

The company has announced plans to invest $7.5 billion in exploration activities by 2028, with $3.1 billion allocated for the Equatorial Margin. This investment strategy includes drilling 50 new exploratory wells, 16 of which will be in the Equatorial Margin. Petrobras is also expanding its exploration footprint beyond Brazil, with recent acquisitions in the Pelotas Basin and stakes in exploratory blocks in São Tomé and Príncipe. This exploration expansion aligns with Petrobras’ strategic goals of maximizing portfolio value, replenishing oil and gas reserves, boosting natural gas supplies, and advancing the decarbonization of its operations. In 2023, the company reported its second-highest annual net income of $24.9 billion, with plans to distribute 58.1 percent of this amount as dividends, reflecting a robust financial performance and commitment to shareholder value.

The Dogger Bank Wind Farm is gearing up for a significant phase of construction and commissioning activities, with the arrival of key installation vessels at the project site. The Saipem 7000 and Seaway Strashnov are set to commence construction work shortly, alongside HEA Leviathan and Edda Boreas, which will focus on the commissioning of the offshore substation (OSS) and underwater noise monitoring, respectively. The Saipem 7000 is currently en route from Norway to the Dogger Bank B site, tasked with installing the OSS topside onto an existing jacket foundation.

This topside is being transported by the Castoro XI cargo barge, towed by the Pacific Discovery anchor-handling tug. The installation process is anticipated to conclude by April 18, marking the beginning of commissioning activities. These activities will be supported by the HEA Leviathan jack-up vessel, providing accommodation and logistical support through mid-August. Concurrently, the Seaway Strashnov is expected to arrive at the site to start monopile installation. Subacoustech Environmental will conduct underwater noise monitoring during the initial monopile installations from the Edda Boreas service operations vessel. This phase follows a delay from the originally scheduled start in September 2023, attributed to mechanical issues discovered during the Dogger Bank A foundation installation campaign. The Dogger Bank Wind Farm consortium has indicated that monopile installation will continue into the third quarter of this year.

Meanwhile, the Seaway Strashnov has been spotted in Maasvlakte, Rotterdam, preparing for its upcoming deployment. Foundations for Dogger Bank B are being supplied by the Sif Netherlands and Smulders Projects Belgium consortium, under a contract signed in 2020 covering the first two phases of the Dogger Bank Wind Farm. These phases will feature 95 Haliade-X 13 MW turbines each, with the third phase, Dogger Bank C, set to include 87 Haliade-X 14 MW turbines. Currently, Dogger Bank A is in the turbine installation stage, having already commenced power production last year. The installation of the first turbine was carried out by Jan De Nul’s Voltaire vessel in September 2023, with eleven more turbines installed since. After a maintenance break, the Voltaire is expected to resume work in May, continuing the project’s progress towards its completion.