In The Spotlight
The project will be implemented in two phases. (Image source: AFC)
Africa Finance Corporation is arranging a project development facility to support Africa’s largest gas-to-methanol plant, with the aim of significantly reducing CO2 emissions by offsetting flaring of natural gas and turning it instead into a valuable chemical for solvents, paints, plastics and car parts
The project in Akwa Ibom, Nigeria, targets producing an initial 1.8 million tonnes per annum (MTPA) of methanol, diversifying the local economy and generating over 18,000 jobs. AFC has committed development stage financing to de-risk the project and enable it reach financial close, along with providing financial advisory services to the sponsors to raise the required project financing and support successful delivery of this transformational project. The venture is led by Blackrose, a project development and investment firm, and co-developed with the International Finance Corporation (IFC), the private sector arm of the World Bank Group, which are co-financing alongside AFC.
Most of Nigeria’s 200 cubic feet of natural gas reserves – the largest in Africa, accounting for a third of the continent’s total – remain unexploited, presenting a substantial opportunity to bolster the country's natural resource beneficiation and enhance climate resilience. Gas flaring has been a significant hazard for local people since the beginning of oil production, emitting chemicals linked to respiratory and other health issues.
“This innovative project is transforming an immense negative for Nigerians into a very significant positive by harnessing this country’s abundant gas reserves as a unique opportunity to become a global leader in low-carbon manufacturing and energy systems,” said Samaila Zubairu, President and CEO of AFC. “This strategic collaboration with Blackrose and IFC underscores our dedication to supporting Africa’s pragmatic transition to net zero, emphasising rapid industrialisation, local job creation, and socio-economic advancement through the production of methanol, a versatile and low-carbon industrial feedstock.”
The project will be implemented in two phases, each with an installed capacity of 1.8 MTPA. Phase one will produce low-carbon methanol, an industrial chemical essential to the manufacturing of hundreds of everyday products, including solvents for the pharmaceutical industry, paints, plastics, automobile parts and construction materials. This is also a lower emissions alternative fuel used in hard-to-decarbonise sectors such as shipping and industrial boilers, with applications for cooking stoves and fuel cell solutions. Phase two of the project will expand methanol production to include ammonia, a critical feedstock for fertiliser production.
Methanol is produced using synthetic gas predominantly from coal and natural gas. By utilising best-in-class energy efficient production methods, the plant will achieve a much lower net carbon intensity compared to traditional methanol synthesis techniques, while also reducing CO2 emissions by converting gas that would otherwise have been flared. Additionally, the project incorporates plans for carbon capture and offset strategies as well as the use of external hydrogen to bring targets even closer to carbon neutrality.
Once operational, the gas-to-methanol plant is expected to generate more than 2,500 local jobs during the construction phase and a further 16,000 jobs indirectly by catalysing manufacturing activity and economic diversification.
If exercised, the Option Agreement will increase Africa Oil’s Impact shareholding to 39.5%. (Image source: Adobe Stock)
Africa Oil Corp has announced that it has signed a call and put option agreement with three shareholders (selling shareholders) in Impact Oil and Gas Limited to purchase a material 7.0% interest in Impact (option agreement)
If exercised, the Option Agreement will increase Africa Oil’s Impact shareholding to 39.5%.
Africa Oil chief executive officer, Roger Tucker, said, “Through our shareholding in Impact we have exposure to an exciting opportunity set in Namibia’s Orange Basin, including the Venus oil discovery, and a highly prospective exploration and appraisal programme on Blocks 2913B and 2912. This purchase achieves the company’s objective of materially increasing its ownership in Impact, enhancing its rights and influence over a core strategic asset and value driver for Africa Oil.”
Under the Option Agreement, the company has the right to acquire an additional 80,160,198 shares in Impact at an exercise price of GBP 0.57 per share for a period of up to six months (“Option Period”) from the Option Agreement’s signing date of 27 August 2024. The company has purchased the call option feature at a price of GBP 0.08 per underlying Impact share. If Africa Oil has not exercised its call option by the end of the fourth month post the Signing Date, Selling Shareholders have the right to put their Impact shares to Africa Oil at an exercise price of GBP 0.57 until the expiry of the Option Period.
If the Option Agreement is exercised, Africa Oil will hold 449,464,396 shares in Impact representing a 39.5% shareholding position on a fully diluted basis.
63 wells in Tilenga and 9 in Kingfisher have been drilled. (Image source: Adobe Stock)
Uganda’s journey towards its first oil production by 2025 is on track, with critical milestones achieved in the Tilenga and Kingfisher projects, Ruth Nankabirwa Ssentamu, the Minister for Energy and Mineral Development, announced at a press conference for the media
She confirmed that 63 out of the planned 426 wells in the Tilenga project have been successfully drilled, surpassing the target necessary for first oil. Additionally, 9 out of the 11 wells required for first oil in the Kingfisher project have also been completed.
In addition to the drilling achievements, the Minister pointed out other critical developments, including the near completion of civil works at the Tilenga Industrial Area and the ongoing construction of the Central Processing Facility (CPF) at both the Tilenga and Kingfisher sites. These facilities are vital to Uganda’s oil production capacity and are expected to be fully operational in time for the first oil.
Speaking at the Ministry of Energy and Minerals offices in Kampala, Hon. Dr. Nankabirwa underscored Uganda's progress in the oil and gas sector as a testament to the country's determination to become a key player in the global oil market.
She emphasised that the Tilenga and Kingfisher projects, which are critical components of Uganda’s oil development strategy, are advancing steadily. With 63 out of 426 wells completed in Tilenga and 9 out of 11 in Kingfisher necessary for first oil, Uganda is firmly on track to achieve first oil by 2025.
The Minister also highlighted the strategic importance of the East African Crude Oil Pipeline (EACOP) and the Uganda Refinery, noting that these midstream projects are crucial in ensuring that Uganda maximizes the economic benefits from its petroleum resources.
“Our integrated approach, which includes the upstream, midstream, and downstream sectors, positions Uganda to significantly contribute to the global oil supply, fostering economic growth and boosting national revenue,” she said.
Nankabirwa also reaffirmed the government's dedication to balancing economic growth, social development, and environmental conservation as the country navigates its path to prosperity. "Uganda's leap in economic growth is partly based on the development of its oil and gas resources, which, once commercialized, will significantly impact all Ugandans," she noted.
“These developments are not only pivotal for Uganda's economy but also have significant implications for the global energy market. Uganda’s oil reserves, estimated at 6.5 billion barrels with 1.5 billion barrels recoverable, are set to make the country a key player in the global oil industry. The successful completion of these projects will ensure a stable and reliable supply of energy resources, contributing to global energy security.”
Nankabirwa emphasized Uganda’s commitment to transparency and sustainability, highlighting the ongoing review of the National Oil and Gas Policy to align with the dynamic global environment. "Balancing economic growth, social development, and environmental conservation remains a priority as we navigate our path to prosperity," she said.
Umar Ajiya, chief financial officer, NNPC. (Image source: NNPC)
The Nigerian National Petroleum Corporation (NNPC) has declared a net profit of N3.297 trillion for the year ended December 2023 in its 2023 audited financial statement (AFS)
This marks not only an increase of more than N700bn (28%) when compared to the 2022 profit of N2.548 trillion, but also the company's best performance since its inception in 1977.
NNPC has been on a consistent growth curve from 2020, when it posted its ‘first ever’ profit of N287bn, followed by a record N674.1bn profit in 2021. The corporation is now looking to announce an initial public offer (IPO) following approval from shareholders and members of the board.
Strategic foresight and operational resilience
“Our fiscal performance reflects both strategic foresight and operational resilience. Despite inherent challenges of our operational and economic environment, we have improved the productivity and the financial performance of this great company,” said Umar Ajiya, chief financial officer, NNPC.
Ajiya attributed the positive results to the Petroleum Industry Act (PIA) 2021, which safeguards national energy security and profitability even while ensuring investor interests. Holders can benefit massively from new fiscal provisions and tax rate under the PIA if they consider conversion from oil prospecting license (OPL) to petroleum prospecting license (PPL) and from oil mining lease (OML) to petroleum mining lease (PML). Upon conversion from OPL to PPL, holders are liable to pay 15% instead of 65.75% as previously mandated by the Petroleum Profits Tax Act (PPTA), and 30% instead of 85% for holders converted from PML to OML, both applicable to onshore and shallow water areas.
TotalEnergies has renewed its production license in OML 130 in May for a further 20 years, bringing its operations under the terms of the PIA. Sanctioning deepwater projects as per the new regime is crucial to boosting Nigeria's production output, which NNPC is targeting at 2mn barrels per day by the end of the year.
With the final investment decision (FID) reached in July by TotalEnergies, as the operator of OML 58 onshore license with a 40% interest, for the development of the Ubeta gas field, where NNPC holds a 60% interest, the corporation is up to a steady start to expect healthy financial results in the coming years.
Contracts with multiple scopes accounted for 9%. (Image source: GlobalData)
Global oil and gas contract activity witnessed a notable 47% quarter-on-quarter increase in total disclosed value to reach US$54.91bn in Q2 2024 from US$37.3bn in Q1, reveals GlobalData
The data and analytics company's latest report, 'Oil and Gas Industry Contracts Review by Sector, Region, Terrain and Top Contractors and Issuers, Q2 2024', reveals that the overall oil and gas contracts volume decreased marginally from 1,473 in Q1 2024 to 1,377 in Q2 2024.
Pritam Kad, oil and gas analyst at GlobalData, said, “Petrobras' monumental awards, including the US$8.15bn P-84 and P-85 FPSO construction contract to Seatrium, the US$1.8bn contract for subsea engineering to the Sapura consortium, and an additional US$2.5 billion for pipelay vessels, rigid risers, and flowlines contracts to Subsea 7, were the driving forces behind the surge in the overall oil and gas contracts value.”
Operation and Maintenance (O&M) scope reported 681 contracts, accounting for 49% of the total contracts in Q2 2024, followed by procurement with 400 contracts representing a 29% share. Contracts with multiple scopes, such as construction, design and engineering, installation, O&M, and procurement, accounted for 9% of the contracts.
Deals in Middle East and Africa
The other notable contracts include Samsung Engineering, GS Engineering & Construction, and Nesma & Partners’ $7.7 billion EPC contract from Saudi Aramco for Fadhili Gas plant expansion from 2.5 to up to 4 billion standard cubic feet per day (bscfd) in Saudi Arabia; Tecnimont-led consortium’s US$2.3bn EPC contract from Sonatrach for three gas boosting stations with 20 turbo-compressor trains in Algeria; and Saipem’s US$850mn rigid pipelines, flexible flowlines, jumpers, and umbilicals work for Azule Energy’s Ndungu field development in Angola.
The enlarged Africa Oil is expected to have significant scale. (Image source: Adobe Stock)
Africa Oil Corp has announced its financial and operating results for the three and six months ended 30 June 2024
Africa Oil president and CEO, Roger Tucker, said,“It was an incredibly busy first half of the year as we signed three strategic transactions, taking Africa Oil towards the next phase of value creation and shareholder returns. We have high-quality development projects, high-impact exploration and appraisal catalysts that will all be funded on completion of these deals. The quality of our organic growth opportunity set is demonstrated by the size and calibre of our partners.
"The Prime consolidation once closed, will see the roll-out of a new transparent capital allocation framework and will create scope for a significantly enlarged capital returns programme for our shareholders. Africa Oil stands with a differentiated investment case of offering sustainable shareholder returns, significant organic growth opportunities, and is well-positioned to pursue new opportunities on the back of a strong balance sheet.”
According to a definitive agreement for proposed reorganisation with BTG, Africa Oil will hold 100% of Prime with BTG Oil & Gas receiving newly issued common shares in Africa Oil, representing approximately 35% of the outstanding share capital of the enlarged Africa Oil. This move aims to create a strong and differentiated upstream oil and gas company. The enlarged Africa Oil is expected to have significant scale with robust long-term free cash flows and a low leverage balance sheet, driven by large-scale and high netback assets in deepwater Nigeria. This will be complemented by funded development and exploration projects in the prolific Orange Basin.
Completion of the proposed reorganisation is targeted to occur during or before Q3 2025 and is subject to, among other conditions, Africa Oil shareholder approval, customary consents and approvals from the Nigerian authorities, the TSX and Nasdaq Stockholm, completion of the previously announced farm-down of Africa Oil’s Namibian interests that are held via Impact, and a reorganisation of the holding structure of BTG Holding to implement the amalgamation agreement.
Namibia: Venus opportunity in Orange Basin
In Namibia Orange Basin, the drilling and test results from Venus-1X, Venus-1A, Venus-2A and Mangetti-1X (Venus interval), completed in 2023 and H1 2024, support the development of the Venus oilfield. The technical studies to be carried out during 2024 are expected to define the Venus development concept.
In addition to the Venus opportunity, the company has retained upside exposure to appraisal and exploration opportunities that, in a success case, could significantly increase the existing discovered resource base on Blocks 2912 and 2913B. Processing of data from the 3D seismic data survey that was completed during H1 2024, could better define the prospectivity on Block 2193B to the south of the Venus discovery. The joint venture will consider drilling further high-impact exploration wells on separate fan structures on this Block in late 2024 or 2025 once the 3D seismic interpretation work is completed. The Mangetti-1X exploration well, located approximately 35km to the Northwest of the Venus-1X well, also intersected hydrocarbon bearing intervals in the Mangetti and Venus fans. The operator has commenced planning of a well to appraise the Mangetti Fan.
Nigeria: High production efficiency
The Agbami field in Nigeria has delivered higher production efficiencies and lower decline rates than planned during H1 2024. The operator has also rescheduled planned maintenance from H1 2024 to H2 2024 resulting in production exceeding plan for both Q2 2024 and H1 2024. The asset remains on target to meet or exceed its production plan for 2024. The Agbami 4D M3 seismic acquisition survey started in Q2 2024. The survey is expected to conclude during Q3 2024, which will be followed by processing of the seismic and detailed planning of the proposed drilling campaign expected to commence late 2025/ early 2026.
The Egina field has also performed above plan during H1 2024 as a result of higher production efficiency than forecast.
In Q2 2024, the Akpo FPSO celebrated 15 years LTI-free. During H1 2024, two new producers and one injection well were brought online at Akpo West, a subsea tie back to the Akpo FPSO. Both of the new production wells are producing above expectation. H1 2024 production at Akpo has been impacted by the planned one-month maintenance outage. Full field production resumed from the shutdown in mid-April, with production rates at the end of Q2 2024 over 16% higher than the production rates at the start of 2024, primarily as a result of the successful infill drilling campaign.
The commitment to the drilling rig has been extended, allowing drilling to continue across the Akpo & Egina fields through 2025. An extensive seismic acquisition campaign was completed in Q2 2024, with surveys taken in Akpo, Preowei, and Egina. The seismic acquisition campaign has established a baseline survey for the Preowei field, and 4D monitor surveys for Akpo and Egina. The latest 4D surveys will be used to guide the infill drilling program and to assist with reservoir surveillance activities.
The first phase of the Preowei Field front end engineering design (FEED) was completed in Q2 2024, with phase 2 expected to be concluded in Q3 2024. FEED studies are aimed at supporting a FID decision on the project and enabling Engineering, Procurement, Construction and Installation (EPCI) to commence in 2025.
South Africa: Drilling in 2025
The company acquired an additional 1.00% interest in Block 3B/4B in South Africa from Eco. It also announced a farm down agreement for Block 3B/4B with TotalEnergies and QatarEnergy, which includes the transfer of operatorship of the Block to TotalEnergies for a total consideration, including the carry, of up to US$46.8mn. The closing of both transactions is subject to government approval and is expected in 2024. On completion of these transactions, the company will retain a non-operated 18.00% interest in the Block.
Subject to obtaining the requisite approvals, the first exploration well on Block 3B/4B could be drilled during 2025.
There is a potential for an uptick in E&A drilling activity. (Image source: Westwood)
Mozambique can still lead production and drilling in the East African Ruvuma-Rufiji (EARR) Gas Basin through to 2030, if the government continues to take strides to guarantee rapid progression of projects off Cabo Delegado province, writes Michela Francisco, analyst - onshore energy services, Westwood Global Energy Group
According to bp's 2024 Energy Outlook, global liquefied natural gas (LNG) traded volumes are forecast to grow 43% by 2030 from the 543 bn cu/m recorded in 2022
In recent years, LNG exports have been dominated by the United States, Australia and Qatar, which, according to the Energy Information Administration (EIA), held a combined LNG export capacity of approximately 257 mmtpa in 2023 (60% of total global LNG capacity). By 2030, Qatar and the US are projected to add approximately 150 mmtpa in LNG feedstock, securing the top two positions in global LNG export capacity. New additions are anticipated to stem from LNG facilities currently under construction in the US (84.1 mmtpa) and expansion phases of QatarEnergy’s North Field (65mmtpa). Despite this, there is still an appetite for additional LNG supply, given current demand expectations, making the business case for developing long-stalled gas projects from frontier areas stronger.
Mozambique and Tanzania, which house the EARR Gas Basin, could potentially be major beneficiaries of this projected demand, given abundant gas reserves (165.7 trillion cu/ft) and the basin's proximity to South-Asian import markets. However, the burning question remains – how soon can the world expect the EARR Gas Basin to roar amid an increasingly thirsty LNG demand environment?
It is pertinent to state that the EARR Gas Basin has failed to live up to its full potential due to a series of endemic bottlenecks faced in the host countries. In Tanzania, the US$40bn Tanzania LNG project, which aims to receive gas feedstock from six fields across Blocks 1 and 4 (Shell) and Block 2 (Equinor), has been subject to extensive delays due to protracted negotiations rooted in unattractive fiscal terms due to high domestic supply obligations.
The story behind undeveloped gas reserves is quite different for the reserves offshore Mozambique, with the main culprit being the Islamist insurgency in Cabo Delgado province. The conflict has led to delays in final investment decisions (FIDs) and project start-ups, given declarations of force majeure for key projects. An example is TotalEnergies’ enforcing force majeure on the 13 mmtpa Mozambique LNG project, hereby delaying production start from the operator's Golfinho-Atum field into 2028, nine years post sanction.
On a similar note, ExxonMobil's Rovuma LNG project also felt the knock-on effect following the declaration of force majeure by TotalEnergies, given that it plans to share some facilities belonging to the Mozambique LNG project. ExxonMobil, however, seized this as an opportunity to cut costs by heavily reconfiguring the design plan from its initial two-train 15.2 mmtpa stick-build facility to an 18 mmtpa facility now being constructed using a modular approach whilst putting some emphasis on mitigating greenhouse gas emissions from the project. To date, ExxonMobil has launched tenders for a front-end engineering and design (FEED) contract and an engineering, procurement, construction and installation (EPCI) option for the subsea-to-shore gas gathering facilities.
Another factor contributing to the untimely development of resources in Mozambique is complicated project economics. TotalEnergies highlighted this in 2023 when it reported that supply chain inflationary pressures further complicated the resumption of the US$20bn Mozambique LNG project. However, there have been signs of positive developments given that TotalEnergies communicated in the company’s April 2024 earnings call that contractors have agreed to reverse contract inflation plans; thus, this is no longer an obstacle to the project’s sanctioning decision.
Despite these challenges, the Basin's inaugural project, Eni's 75,000 boepd Coral South floating liquified natural gas (FLNG) project, came onstream in 2022, signalling that complex, multi-billion-dollar developments could work offshore Mozambique. Output in Mozambique is forecast to remain stable at around 75,000 boepd until 2027 before growing to a peak of 295,000 boepd by 2030, up 296%, driven by TotalEnergies’ Golfinho-Atum and Eni's Coral Phase II fields.
Additionally, Tanzania's inaugural field in the Basin should come onstream in 2026 from Aminex's 7000 boepd Ntorya onshore gas field, boosting total output across the Basin to a peak of approximately 302,000 boepd by 2030, up 305% on 2023. Although there are positive signs for production, the spectre of delays that have been haunting projects remains strong, potentially diluting the positive picture prior to 2030, especially since only one of the three projects expected onstream by 2030 has passed sanctioning (TotalEnergies’ Golfinho-Atum).
Drilling activity across both countries has been negligible, averaging one well per annum over the 2019-2024 period. Activity is anticipated to liven up over the forecast, driven by approximately 50 wells to be drilled to support upcoming LNG projects in Mozambican deepwater. Of these, 27 subsea trees have already been awarded between 2017 and 2019 for Eni’s Coral South and TotalEnergies’ Golfinho-Atum fields. 30 additional subsea trees are forecast to be awarded, with six awards anticipated for Eni’s Coral North field, scheduled to reach FID before the end of 2024. Onshore drilling activity will remain negligible, with only Aminex’s Chikumbi-1 exploration well set to be spud in 2024, the only onshore E&A well spud in the basin since 2016.
Post 2030, the outlook from the EARR Basin could be more promising, given continued interest from international energy companies (IECs), as well as licencing rounds and concession award announcements made across both countries since 2023. Although projects are few and far between in Tanzania, Shell and Equinor proposed a US$42bn LNG project from three deepwater blocks in March 2023, and this was later followed by CNOOC’s expression of interest in developing a FLNG deepwater project in blocks 4/1B and 4/1C in June 2023. From a regulatory standpoint, the current administration has increased optimism, given ongoing negotiation on fiscal terms with joint venture companies; however, nothing has materialised thus far.
Additionally, it is noteworthy to highlight the potential for an uptick in E&A drilling activity beyond Westwood’s current forecasts. This is due to the semi-autonomous Government of Zanzibar, off-Tanzania, launching its inaugural five-year licensing round in March of 2024, inviting IECs to explore eight offshore blocks.
E&A drilling could also occur in Mozambique, given that the National Hydrocarbon Company approved a concession contract for oil exploration and production in the Angoche A6-C Area in July 2024. However, Westwood is bearish on these progressing into any E&A drilling activity before the second half of the forecast.
When dissecting current developments in the EARR Basin, it is evident that by the onset of the next decade, the Basin could contribute about 295,000 boepd of gas to meet global LNG demand. Westwood anticipates that Mozambique will continue to lead production and drilling in the EARR Basin through to 2030. However, it remains crucial for the Mozambican government to continue to take strides towards eradicating the insurgency to guarantee rapid progression of projects off Cabo Delegado province, which are currently mainly in the FEED stage.
Contrarily, on the Tanzanian side of the Basin, the portrait is more promising than in the hindcast, albeit there is still a need to focus on improving fiscal terms to attract more near-term investment and ensure that current interest from IECs is maintained. Overall, Westwood believes that by 2030, the EARR Gas Basin might start to live up to its potential as projects finally move from potential to reality.
If exercised, the Option Agreement will increase Africa Oil’s Impact shareholding to 39.5%. (Image source: Adobe Stock)
Africa Oil Corp has announced that it has signed a call and put option agreement with three shareholders (selling shareholders) in Impact Oil and Gas Limited to purchase a material 7.0% interest in Impact (option agreement)
If exercised, the Option Agreement will increase Africa Oil’s Impact shareholding to 39.5%.
Africa Oil chief executive officer, Roger Tucker, said, “Through our shareholding in Impact we have exposure to an exciting opportunity set in Namibia’s Orange Basin, including the Venus oil discovery, and a highly prospective exploration and appraisal programme on Blocks 2913B and 2912. This purchase achieves the company’s objective of materially increasing its ownership in Impact, enhancing its rights and influence over a core strategic asset and value driver for Africa Oil.”
Under the Option Agreement, the company has the right to acquire an additional 80,160,198 shares in Impact at an exercise price of GBP 0.57 per share for a period of up to six months (“Option Period”) from the Option Agreement’s signing date of 27 August 2024. The company has purchased the call option feature at a price of GBP 0.08 per underlying Impact share. If Africa Oil has not exercised its call option by the end of the fourth month post the Signing Date, Selling Shareholders have the right to put their Impact shares to Africa Oil at an exercise price of GBP 0.57 until the expiry of the Option Period.
If the Option Agreement is exercised, Africa Oil will hold 449,464,396 shares in Impact representing a 39.5% shareholding position on a fully diluted basis.
63 wells in Tilenga and 9 in Kingfisher have been drilled. (Image source: Adobe Stock)
Umar Ajiya, chief financial officer, NNPC. (Image source: NNPC)
The agreement will allow TGS to manage and license more than 132,000 sq kms of seismic data, both 2D and 3D. (Image source: TGS)
By agreement, Tanzania’s Petroleum Upstream Regulatory Authority (PURA) has given energy data and intelligence company TGS full access to the region's extensive offshore subsurface data
The agreement will allow TGS to manage and license more than 132,000 sq kms of seismic data, both 2D and 3D.
Tanzania boasts strong play diversity, proven through exploration success across much of the stratigraphy, from Early Cretaceous to Miocene reservoirs. The comprehensive dataset comprises of regional seismic as well as well data, unlocking insights into the basin's evolution and structural history.
It will help identify hydrocarbon plays, allow for prospect-specific analysis, mapping of robust trapping configurations, and help understand the maturity and distribution of source rocks.
Besides exclusive rights to license all of Tanzania’s offshore mainland data, TGS is also free to acquire new seismic data and reprocess existing data.
The company can support upcoming licensing rounds, which is expected to start next year. Tanzania is now ranked third in sub-Saharan Africa for future investment, anticipating 6% GDP growth by 2025, with million-dollar investments in infrastructure, and LNG, among other sectors.
Attractive exploration target
David Hajovsky, EVP of multi-client at TGS, said, “Tanzania remains an attractive exploration target with its world-class gas fields and excellent sands proven across multiple source intervals. By providing access to high-quality seismic data ahead of potential future licensing activities, TGS will empower exploration and production companies to evaluate opportunities in this under-explored but highly promising region of East Africa.”
TGS has also signed an agreement recently with the national oil company of Liberia (NOCAL) for data access expansion in the region.
TGS plans to reprocess approximately 15,616 sq kms of legacy 3D seismic data in the Liberia Basin. (Image source: TGS)
A thorough geophysical scanning might have more to reveal from the historic wells drilled and operated on the Tobias field in KON-11. (Image source: Adobe Stock)
The pump is ideally suited for applications with limited suction head. (Image source: Michael Smith Engineers)
Michael Smith Engineers has introduced the TPM magnetic-coupled peripheral pump, engineered by Dickow Pumpen
The latest addition to Michael Smith's extensive range of high-performance pumps, this innovation is designed for application across industries, including oil & gas, chemical, petrochemical, aviation, and renewable energy.
Also known as turbine pump, the TPM peripheral pump works like any centrifugal and side-channel pumps. It is ideally suited for applications with limited suction head as it comes with a low net positive suction head (NPSH).
The TPM range can deliver flow rates of up to 17 cu/m per hour and a maximum differential head of 400 m. With a design pressure of 40 bar and maximum operating temperature of 300°C, the TPM range is built to ensure reliable performance even under the most challenging conditions.
One of the standout features of the TPM peripheral pump is its ability to handle liquids with entrained gas, enabling continuous operation even during gas release or temporary air ingress. Additionally, its hermetically sealed design makes it an excellent choice for handling toxic, explosive, or environmentally hazardous fluids, ensuring safety and compliance with stringent environmental standards.
New technology
David Todd of Michael Smith Engineers said, "‘We are delighted to be able to offer our customers this new pump technology from Dickow Pump, whom we have been in partnership with for almost three decades. We are confident this will be as successful as the rest of the Dickow pump range."
Also read: GD Energy introduces customer-friendly pumps
Total spending to surpass US$42bn by 2027. (Image source: Rystad Energy)
The companies will develop one integrated platform for subsurface workflows. (Image source: Adobe Stock)
The project will be implemented in two phases. (Image source: AFC)
Africa Finance Corporation is arranging a project development facility to support Africa’s largest gas-to-methanol plant, with the aim of significantly reducing CO2 emissions by offsetting flaring of natural gas and turning it instead into a valuable chemical for solvents, paints, plastics and car parts
The project in Akwa Ibom, Nigeria, targets producing an initial 1.8 million tonnes per annum (MTPA) of methanol, diversifying the local economy and generating over 18,000 jobs. AFC has committed development stage financing to de-risk the project and enable it reach financial close, along with providing financial advisory services to the sponsors to raise the required project financing and support successful delivery of this transformational project. The venture is led by Blackrose, a project development and investment firm, and co-developed with the International Finance Corporation (IFC), the private sector arm of the World Bank Group, which are co-financing alongside AFC.
Most of Nigeria’s 200 cubic feet of natural gas reserves – the largest in Africa, accounting for a third of the continent’s total – remain unexploited, presenting a substantial opportunity to bolster the country's natural resource beneficiation and enhance climate resilience. Gas flaring has been a significant hazard for local people since the beginning of oil production, emitting chemicals linked to respiratory and other health issues.
“This innovative project is transforming an immense negative for Nigerians into a very significant positive by harnessing this country’s abundant gas reserves as a unique opportunity to become a global leader in low-carbon manufacturing and energy systems,” said Samaila Zubairu, President and CEO of AFC. “This strategic collaboration with Blackrose and IFC underscores our dedication to supporting Africa’s pragmatic transition to net zero, emphasising rapid industrialisation, local job creation, and socio-economic advancement through the production of methanol, a versatile and low-carbon industrial feedstock.”
The project will be implemented in two phases, each with an installed capacity of 1.8 MTPA. Phase one will produce low-carbon methanol, an industrial chemical essential to the manufacturing of hundreds of everyday products, including solvents for the pharmaceutical industry, paints, plastics, automobile parts and construction materials. This is also a lower emissions alternative fuel used in hard-to-decarbonise sectors such as shipping and industrial boilers, with applications for cooking stoves and fuel cell solutions. Phase two of the project will expand methanol production to include ammonia, a critical feedstock for fertiliser production.
Methanol is produced using synthetic gas predominantly from coal and natural gas. By utilising best-in-class energy efficient production methods, the plant will achieve a much lower net carbon intensity compared to traditional methanol synthesis techniques, while also reducing CO2 emissions by converting gas that would otherwise have been flared. Additionally, the project incorporates plans for carbon capture and offset strategies as well as the use of external hydrogen to bring targets even closer to carbon neutrality.
Once operational, the gas-to-methanol plant is expected to generate more than 2,500 local jobs during the construction phase and a further 16,000 jobs indirectly by catalysing manufacturing activity and economic diversification.
There is a potential for an uptick in E&A drilling activity. (Image source: Westwood)
ADNOC's first long-term LNG deal with Osaka Gas. (Image source: ADNOC)
Gas yield from OML 58 is processed in the Obite treatment centre for supply to NLNG. (Image source: Adobe Stock)
TotalEnergies and the Nigerian National Petroleum Corporation Ltd has reached a final investment decision (FID) for the development of the Ubeta gas field
Located about 80 km northwest of Port Harcourt in Rivers state, the Ubeta gas field falls under OML 58 onshore license which is operated by TotalEnergies with a 40% interest while NNPC holds the other 60%.
The development plan includes the installation of a 11 km buried pipeline to connect Ubeta's new six-well cluster to the existing Obite facilities, thus allowing emissions reduction and cost efficiency. A 5 MW solar plant is currently under construction at Obite to further alleviate carbon intensity. A completely electrified drilling rig will be deployed for production which is due to start in 2027.
During COP28, TotalEnergies signed an agreement with NNPCL among other African oil companies to deploy its advanced drone-based technology AUSEA on oil & gas facilities in Nigeria, and soon after, an inspection of OML 100 field in south-eastern Niger Delta confirmed that their joint venture has achieved zero routine gas flaring across all its assets, including OML 58.
Favourable government initiatives
While things are looking up in terms of sustainable practices, Nigeria is also focusing on production optimisation, and its recent collaboration with SLB testifies this approach.
The Ubeta field capacity is expected at approximately 70,000 bopd including condensates. The Obagi oil field and the Ibewa gas and condensate field that also belong within OML 58 are currently in production. The gas yield is processed in the Obite treatment centre for supply to the Nigerian domestic gas market as well as Nigeria LNG (NLNG) plant.
TotalEnergies owns a 15% interest in NLNG, which is a liquefaction plant in Bonny Island, with an on-going capacity expansion from 22-30 Mtpa.
With more than 90% of manhours to be worked locally, the major, along with NNPCL, is aiming to enhance local content.
“Ubeta is the latest in a series of projects developed by TotalEnergies in Nigeria, most recently Ikike and Akpo West. I am pleased that we can launch this new gas project which has been made possible by the Government’s recent incentives for non-associated gas developments. Ubeta fits perfectly with our strategy of developing low-cost and low-emission projects, and will contribute to the Nigerian economy through higher NLNG exports,” said Mike Sangster, senior vice president - Africa, exploration and production at TotalEnergies.
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The conference brings together the brightest minds and technical experts from across the energy value chain. (Image source: dmg events)
The ADIPEC 2024 Technical Conference has received a record 5,977 submissions, a 16% increase over last year, with major submission growth seen in the AI and Digital Transformation and Energy Transition and Decarbonisation categories, and increased submissions from African and Arab states.
The ADIPEC Technical Conference is a key part of ADIPEC, the world’s largest energy event, which takes place on 4-7 November 2024 in Abu Dhabi. Organised by SPE, the Technical Conference this year will feature 159 sessions across 12 categories, for which energy experts and engineers from around the world submit their work to be considered for presentation.
“As chairman of the ADIPEC Technical Conference, I am immensely proud to announce a historic milestone of 5,977 technical submissions received this year. This unprecedented volume of contributions underscores ADIPEC's vital role as a premier forum for innovative dialogue and exchange within the global energy sector. I extend my heartfelt thanks to all authors – the pioneering experts that continue to drive our industry forward, fostering the advancements and collaborative spirit necessary to meet the evolving demands of our world,” said Dr. Khaled Abdul Monem Al Kindi, Senior Vice President, Upper Zakum, ADNOC Offshore and ADIPEC 2024 Technical Conference Programme Chair.
Continuing its 40-year legacy of energy leadership and innovation, ADIPEC 2024 aims to be a driving force for accelerated energy action. This year, the event sets out a renewed vision, gathering diverse voices from communities, nations, and industries to find collective solutions that can deliver affordable, secure, and sustainable energy for all.
As a key part of ADIPEC’s portfolio of 10 conferences, the ADIPEC Technical Conference brings together the brightest minds and technical experts from across the energy value chain – the changemakers at the forefront of engineering, technology and industry innovation.
The two submission categories that saw the biggest increases were Energy Transition and Decarbonisation and AI and Digital Transformation, with 38% and 32% jumps respectively. These increases reveal the energy industry’s growing focus on emerging digital technologies and efforts to decarbonise in support of the energy transition, which are a major focus of ADIPEC this year, reflected across its dynamic conference and exhibition agenda.
A significant increase was also recorded in the number of submissions from Arab and African countries over last year, rising 50% and 28% respectively. Double-digit growth was also recorded in submissions from the Asia & Pacific Region, North America, and the Middle East. The ADIPEC Technical Conference also saw experts from 25% more companies submit their work for presentation.
Christopher Hudson, president of dmg events, the organiser of ADIPEC, said: "Decarbonisation presents many challenges and opportunities for all sectors. ADIPEC’s focus on platforming low-carbon energy innovations to power industry, empower lives, and accelerate global prosperity makes its Technical Conference a critical forum to advance a sustainable, secure and equitable energy future. This year’s record number of submissions, along with the substantial increases in geographical and category-specific contributions, highlights the alignment of our agenda with the industry's needs and the global commitment to be part of the solution."
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