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#21
West Africa / Republic of Congo - Moho
Last post by Administrator - Apr 18, 2026, 07:38 AMRepublic of the Congo: TotalEnergies Makes a Hydrocarbon Discovery on the Moho License
Paris, April 13, 2026 – TotalEnergies EP Congo (63.5%, operator) announces a hydrocarbon discovery on the Moho license, offshore the Republic of Congo, following the drilling of the MHNM-6 NFW exploration well targeting the Moho G structure.
The well encountered a hydrocarbon column of approximately 160 meters in good-quality Albian reservoirs, and an extensive data acquisition and sampling campaign was carried out to support the subsurface interpretation and future development.
The Moho G discovery, together with the discovery previously made on the nearby Moho F structure, represents recoverable resources estimated at close to 100 million barrels, which are planned to be developed as a tie-back to the existing Moho facilities.
This new discovery on the Moho license benefits from its proximity to existing production infrastructure, allowing a short cycle, cost effective tie-back development, said Nicola Mavilla, Senior Vice-President Exploration at TotalEnergies. By leveraging our technical expertise and existing infrastructure, we are creating the conditions for future value-accretive production for the Company.
TotalEnergies EP Congo is the operator of Moho license with a 63.5% participation, alongside Trident Energy (21.5%) and the Société Nationale des Pétroles du Congo (SNPC, 15%). Existing production facilities include two Floating Production Units (FPU), Alima and Likouf, combining for a current output of around 90 kboe/d (100%).
Paris, April 13, 2026 – TotalEnergies EP Congo (63.5%, operator) announces a hydrocarbon discovery on the Moho license, offshore the Republic of Congo, following the drilling of the MHNM-6 NFW exploration well targeting the Moho G structure.
The well encountered a hydrocarbon column of approximately 160 meters in good-quality Albian reservoirs, and an extensive data acquisition and sampling campaign was carried out to support the subsurface interpretation and future development.
The Moho G discovery, together with the discovery previously made on the nearby Moho F structure, represents recoverable resources estimated at close to 100 million barrels, which are planned to be developed as a tie-back to the existing Moho facilities.
This new discovery on the Moho license benefits from its proximity to existing production infrastructure, allowing a short cycle, cost effective tie-back development, said Nicola Mavilla, Senior Vice-President Exploration at TotalEnergies. By leveraging our technical expertise and existing infrastructure, we are creating the conditions for future value-accretive production for the Company.
TotalEnergies EP Congo is the operator of Moho license with a 63.5% participation, alongside Trident Energy (21.5%) and the Société Nationale des Pétroles du Congo (SNPC, 15%). Existing production facilities include two Floating Production Units (FPU), Alima and Likouf, combining for a current output of around 90 kboe/d (100%).
#22
OceanSTAR Elite / Indonesia - Madura FPU Trunojo...
Last post by Administrator - Apr 15, 2026, 09:49 AMTechnical Report: FPU Trunojoyo 01
Developed by OceanSTAR Elite Group
1. Introduction
This report provides a technical overview of the Floating Production Unit (FPU) Trunojoyo 01, developed and operated by OceanSTAR Elite Group through PT Timas Oceanstar Indonesia. The unit supports offshore gas production in the Madura Strait, East Java, Indonesia, and represents a significant milestone in the company's transition into upstream asset operations.
2. Project Background
The Trunojoyo field development required a floating production solution capable of processing and delivering natural gas under offshore conditions. OceanSTAR Elite was awarded the project under a full EPCIC (Engineering, Procurement, Construction, Installation, and Commissioning) contract scope.
The FPU was designed to:
3. Design Specifications
3.1 General Particulars
The topside facilities include:
4. Engineering and Construction
The FPU was fabricated at a shipyard in China and completed within approximately 15 months, demonstrating accelerated project execution despite pandemic-related constraints.
Key engineering highlights include:
5. Installation and Commissioning
5.1 Offshore Installation
The short commissioning timeline reflects effective system integration and pre-commissioning strategies.
6. Operational Performance
Since start-up, FPU Trunojoyo 01 has demonstrated strong operational reliability:
These metrics indicate robust system design, effective maintenance practices, and strong operational management.
7. Health, Safety, and Environmental (HSE) Considerations
The FPU incorporates multiple safety-critical systems, including:
Operational procedures emphasize:
8. Strategic Significance
FPU Trunojoyo 01 represents:
The project establishes a technical and operational benchmark for future offshore developments undertaken by the company.
9. Conclusion
FPU Trunojoyo 01 demonstrates effective integration of engineering design, accelerated construction, and high operational reliability. The project highlights OceanSTAR Elite's capability to deliver complex offshore production systems under challenging conditions while maintaining strong safety and performance standards.
The successful deployment and operation of the unit position the company for continued growth in offshore energy infrastructure and production operations.
Developed by OceanSTAR Elite Group
1. Introduction
This report provides a technical overview of the Floating Production Unit (FPU) Trunojoyo 01, developed and operated by OceanSTAR Elite Group through PT Timas Oceanstar Indonesia. The unit supports offshore gas production in the Madura Strait, East Java, Indonesia, and represents a significant milestone in the company's transition into upstream asset operations.
2. Project Background
The Trunojoyo field development required a floating production solution capable of processing and delivering natural gas under offshore conditions. OceanSTAR Elite was awarded the project under a full EPCIC (Engineering, Procurement, Construction, Installation, and Commissioning) contract scope.
The FPU was designed to:
- Process raw gas from subsea wells
- Treat and compress gas to pipeline specifications
- Export processed gas to onshore facilities
3. Design Specifications
3.1 General Particulars
- Vessel Type: Floating Production Unit (FPU)
- Length Overall (LOA): ~160 m
- Breadth: ~32 m
- Accommodation Capacity: Up to 70 personnel
- Gas Processing Rate: ~175 MMscf/d
The topside facilities include:
- Inlet separation system
- Gas compression system
- Gas dehydration unit
- Metering and export system
- Power generation units
- Firewater and safety systems
- Instrument air and control systems
- Telecommunications and navigation systems
4. Engineering and Construction
The FPU was fabricated at a shipyard in China and completed within approximately 15 months, demonstrating accelerated project execution despite pandemic-related constraints.
Key engineering highlights include:
- Modular topside integration to reduce construction time
- Compliance with international offshore design standards
- Optimization for maintainability and operational efficiency
5. Installation and Commissioning
5.1 Offshore Installation
- Transportation to Madura Strait: Completed September 2022
- Offshore hookup and integration with subsea infrastructure
- Commissioning duration: ~30 days post-installation
- First Gas Achievement: 23 October 2022
The short commissioning timeline reflects effective system integration and pre-commissioning strategies.
6. Operational Performance
Since start-up, FPU Trunojoyo 01 has demonstrated strong operational reliability:
- Availability: 100% uptime (reported period)
- Safety Performance: Zero Lost Time Injuries (LTI)
- Stable production output meeting design capacity
These metrics indicate robust system design, effective maintenance practices, and strong operational management.
7. Health, Safety, and Environmental (HSE) Considerations
The FPU incorporates multiple safety-critical systems, including:
- Emergency shutdown (ESD) systems
- Fire and gas detection systems
- Passive and active fire protection
- Hazardous area classification compliance
Operational procedures emphasize:
- Risk-based inspection (RBI)
- Preventive maintenance
- Workforce safety training and compliance
8. Strategic Significance
FPU Trunojoyo 01 represents:
- OceanSTAR Elite's first operated offshore production asset
- A successful transition from EPC contractor to asset operator
- A key contributor to Indonesia's domestic gas supply
The project establishes a technical and operational benchmark for future offshore developments undertaken by the company.
9. Conclusion
FPU Trunojoyo 01 demonstrates effective integration of engineering design, accelerated construction, and high operational reliability. The project highlights OceanSTAR Elite's capability to deliver complex offshore production systems under challenging conditions while maintaining strong safety and performance standards.
The successful deployment and operation of the unit position the company for continued growth in offshore energy infrastructure and production operations.
#23
SBM Offshore / Brazil - SEAP II - P-87 FPSO
Last post by Administrator - Apr 15, 2026, 09:32 AMPetrobras Advances SEAP Development with FID on SEAP I
Petrobras has taken Final Investment Decision (FID) on the SEAP I module in the Sergipe-Alagoas Basin, marking a key step in the phased development of the Sergipe Deepwater Project (SEAP), an emerging offshore production hub in Brazil. This follows the earlier FID for SEAP II in December 2025, confirming full-field development progression.
Project Economics and Commercial Structuring
Project sanction was enabled by a combination of cost optimization measures, supply chain engagement, and revised commercial frameworks. Petrobras worked closely with contractors to restructure contractual terms and improve project economics, enhancing overall IRR and resilience under oil price volatility scenarios.
A notable outcome was the joint procurement strategy for the P-81 (SEAP I) and P-87 (SEAP II) FPSOs. Bundling these units allowed Petrobras to capture synergies, standardization benefits, and economies of scale—key factors in achieving commercially viable agreements.
As a result, SEAP I has been incorporated into Petrobras' Base Implementation Portfolio, reinforcing the role of collaborative supplier engagement in unlocking complex deepwater developments.
Execution Model and Contracting Strategy
Both FPSOs will be delivered under a BOT (Build, Operate, Transfer) model, with SBM Offshore responsible for EPCIC and operations during the initial contract period prior to asset transfer. This model provides capital efficiency, schedule acceleration, and operational continuity.
Contract signing is expected in May 2026, subject to final governance approvals and partner alignment, enabling transition into the execution phase.
Production Capacity and Timeline
Combined, the two FPSOs will deliver:
First oil is targeted for 2030, with gas export infrastructure coming online in 2031.
Field Development Scope
The SEAP development plan includes:
Tendering for subsea hardware is already in progress, with additional packages scheduled for bid in 2026.
Strategic Importance
SEAP represents a major addition to Brazil's upstream portfolio, with total capex exceeding BRL 60 billion and expected recovery above 1 billion boe. Beyond liquids production, the project is strategically positioned to expand domestic gas supply, supporting energy security and infrastructure development in the Northeast region.
Asset Breakdown
SEAP I (P-81 FPSO):
SEAP II (P-87 FPSO):
Petrobras has taken Final Investment Decision (FID) on the SEAP I module in the Sergipe-Alagoas Basin, marking a key step in the phased development of the Sergipe Deepwater Project (SEAP), an emerging offshore production hub in Brazil. This follows the earlier FID for SEAP II in December 2025, confirming full-field development progression.
Project Economics and Commercial Structuring
Project sanction was enabled by a combination of cost optimization measures, supply chain engagement, and revised commercial frameworks. Petrobras worked closely with contractors to restructure contractual terms and improve project economics, enhancing overall IRR and resilience under oil price volatility scenarios.
A notable outcome was the joint procurement strategy for the P-81 (SEAP I) and P-87 (SEAP II) FPSOs. Bundling these units allowed Petrobras to capture synergies, standardization benefits, and economies of scale—key factors in achieving commercially viable agreements.
As a result, SEAP I has been incorporated into Petrobras' Base Implementation Portfolio, reinforcing the role of collaborative supplier engagement in unlocking complex deepwater developments.
Execution Model and Contracting Strategy
Both FPSOs will be delivered under a BOT (Build, Operate, Transfer) model, with SBM Offshore responsible for EPCIC and operations during the initial contract period prior to asset transfer. This model provides capital efficiency, schedule acceleration, and operational continuity.
Contract signing is expected in May 2026, subject to final governance approvals and partner alignment, enabling transition into the execution phase.
Production Capacity and Timeline
Combined, the two FPSOs will deliver:
- Oil production capacity: 240,000 bbl/d
- Gas processing capacity: 22 million m³/d
First oil is targeted for 2030, with gas export infrastructure coming online in 2031.
Field Development Scope
The SEAP development plan includes:
- Drilling and completion of 32 subsea wells
- Installation of subsea production systems, including Christmas trees and associated infrastructure
- A 134 km gas export pipeline (111 km offshore, 23 km onshore)
Tendering for subsea hardware is already in progress, with additional packages scheduled for bid in 2026.
Strategic Importance
SEAP represents a major addition to Brazil's upstream portfolio, with total capex exceeding BRL 60 billion and expected recovery above 1 billion boe. Beyond liquids production, the project is strategically positioned to expand domestic gas supply, supporting energy security and infrastructure development in the Northeast region.
Asset Breakdown
SEAP I (P-81 FPSO):
- Targets light oil accumulations in Agulhinha, Agulhinha Oeste, and Palombeta (BM-SEAL-10/11).
- Capacity: 120,000 bbl/d oil, 10 million m³/d gas
- Petrobras operatorship: 100% (BM-SEAL-10), 60% (BM-SEAL-11)
SEAP II (P-87 FPSO):
- Covers Budião, Budião NW, and Palombeta (~80 km offshore, BM-SEAL-4/4A/10).
- Capacity: 120,000 bbl/d oil, 12 million m³/d gas
- Petrobras operatorship: 75% (BM-SEAL-4), 100% (BM-SEAL-4A/10)
#24
SBM Offshore / Brazil - SEAP I - P-81 FPSO
Last post by Administrator - Apr 15, 2026, 09:24 AMPetrobras Advances SEAP Development with FID on SEAP I
Petrobras has taken Final Investment Decision (FID) on the SEAP I module in the Sergipe-Alagoas Basin, marking a key step in the phased development of the Sergipe Deepwater Project (SEAP), an emerging offshore production hub in Brazil. This follows the earlier FID for SEAP II in December 2025, confirming full-field development progression.
Project Economics and Commercial Structuring
Project sanction was enabled by a combination of cost optimization measures, supply chain engagement, and revised commercial frameworks. Petrobras worked closely with contractors to restructure contractual terms and improve project economics, enhancing overall IRR and resilience under oil price volatility scenarios.
A notable outcome was the joint procurement strategy for the P-81 (SEAP I) and P-87 (SEAP II) FPSOs. Bundling these units allowed Petrobras to capture synergies, standardization benefits, and economies of scale—key factors in achieving commercially viable agreements.
As a result, SEAP I has been incorporated into Petrobras' Base Implementation Portfolio, reinforcing the role of collaborative supplier engagement in unlocking complex deepwater developments.
Execution Model and Contracting Strategy
Both FPSOs will be delivered under a BOT (Build, Operate, Transfer) model, with SBM Offshore responsible for EPCIC and operations during the initial contract period prior to asset transfer. This model provides capital efficiency, schedule acceleration, and operational continuity.
Contract signing is expected in May 2026, subject to final governance approvals and partner alignment, enabling transition into the execution phase.
Production Capacity and Timeline
Combined, the two FPSOs will deliver:
First oil is targeted for 2030, with gas export infrastructure coming online in 2031.
Field Development Scope
The SEAP development plan includes:
Tendering for subsea hardware is already in progress, with additional packages scheduled for bid in 2026.
Strategic Importance
SEAP represents a major addition to Brazil's upstream portfolio, with total capex exceeding BRL 60 billion and expected recovery above 1 billion boe. Beyond liquids production, the project is strategically positioned to expand domestic gas supply, supporting energy security and infrastructure development in the Northeast region.
Asset Breakdown
SEAP I (P-81 FPSO):
SEAP II (P-87 FPSO):
Petrobras has taken Final Investment Decision (FID) on the SEAP I module in the Sergipe-Alagoas Basin, marking a key step in the phased development of the Sergipe Deepwater Project (SEAP), an emerging offshore production hub in Brazil. This follows the earlier FID for SEAP II in December 2025, confirming full-field development progression.
Project Economics and Commercial Structuring
Project sanction was enabled by a combination of cost optimization measures, supply chain engagement, and revised commercial frameworks. Petrobras worked closely with contractors to restructure contractual terms and improve project economics, enhancing overall IRR and resilience under oil price volatility scenarios.
A notable outcome was the joint procurement strategy for the P-81 (SEAP I) and P-87 (SEAP II) FPSOs. Bundling these units allowed Petrobras to capture synergies, standardization benefits, and economies of scale—key factors in achieving commercially viable agreements.
As a result, SEAP I has been incorporated into Petrobras' Base Implementation Portfolio, reinforcing the role of collaborative supplier engagement in unlocking complex deepwater developments.
Execution Model and Contracting Strategy
Both FPSOs will be delivered under a BOT (Build, Operate, Transfer) model, with SBM Offshore responsible for EPCIC and operations during the initial contract period prior to asset transfer. This model provides capital efficiency, schedule acceleration, and operational continuity.
Contract signing is expected in May 2026, subject to final governance approvals and partner alignment, enabling transition into the execution phase.
Production Capacity and Timeline
Combined, the two FPSOs will deliver:
- Oil production capacity: 240,000 bbl/d
- Gas processing capacity: 22 million m³/d
First oil is targeted for 2030, with gas export infrastructure coming online in 2031.
Field Development Scope
The SEAP development plan includes:
- Drilling and completion of 32 subsea wells
- Installation of subsea production systems, including Christmas trees and associated infrastructure
- A 134 km gas export pipeline (111 km offshore, 23 km onshore)
Tendering for subsea hardware is already in progress, with additional packages scheduled for bid in 2026.
Strategic Importance
SEAP represents a major addition to Brazil's upstream portfolio, with total capex exceeding BRL 60 billion and expected recovery above 1 billion boe. Beyond liquids production, the project is strategically positioned to expand domestic gas supply, supporting energy security and infrastructure development in the Northeast region.
Asset Breakdown
SEAP I (P-81 FPSO):
- Targets light oil accumulations in Agulhinha, Agulhinha Oeste, and Palombeta (BM-SEAL-10/11).
- Capacity: 120,000 bbl/d oil, 10 million m³/d gas
- Petrobras operatorship: 100% (BM-SEAL-10), 60% (BM-SEAL-11)
SEAP II (P-87 FPSO):
- Covers Budião, Budião NW, and Palombeta (~80 km offshore, BM-SEAL-4/4A/10).
- Capacity: 120,000 bbl/d oil, 12 million m³/d gas
- Petrobras operatorship: 75% (BM-SEAL-4), 100% (BM-SEAL-4A/10)
#25
Field Development / Re: Brazil - Sergipe Deepwater...
Last post by Administrator - Apr 15, 2026, 02:59 AMPetrobras Advances SEAP Development with FID on SEAP I
Petrobras has taken Final Investment Decision (FID) on the SEAP I module in the Sergipe-Alagoas Basin, marking a key step in the phased development of the Sergipe Deepwater Project (SEAP), an emerging offshore production hub in Brazil. This follows the earlier FID for SEAP II in December 2025, confirming full-field development progression.
Project Economics and Commercial Structuring
Project sanction was enabled by a combination of cost optimization measures, supply chain engagement, and revised commercial frameworks. Petrobras worked closely with contractors to restructure contractual terms and improve project economics, enhancing overall IRR and resilience under oil price volatility scenarios.
A notable outcome was the joint procurement strategy for the P-81 (SEAP I) and P-87 (SEAP II) FPSOs. Bundling these units allowed Petrobras to capture synergies, standardization benefits, and economies of scale—key factors in achieving commercially viable agreements.
As a result, SEAP I has been incorporated into Petrobras' Base Implementation Portfolio, reinforcing the role of collaborative supplier engagement in unlocking complex deepwater developments.
Execution Model and Contracting Strategy
Both FPSOs will be delivered under a BOT (Build, Operate, Transfer) model, with SBM Offshore responsible for EPCIC and operations during the initial contract period prior to asset transfer. This model provides capital efficiency, schedule acceleration, and operational continuity.
Contract signing is expected in May 2026, subject to final governance approvals and partner alignment, enabling transition into the execution phase.
Production Capacity and Timeline
Combined, the two FPSOs will deliver:
Oil production capacity: 240,000 bbl/d
Gas processing capacity: 22 million m³/d
First oil is targeted for 2030, with gas export infrastructure coming online in 2031.
Field Development Scope
The SEAP development plan includes:
Drilling and completion of 32 subsea wells
Installation of subsea production systems, including Christmas trees and associated infrastructure
A 134 km gas export pipeline (111 km offshore, 23 km onshore)
Tendering for subsea hardware is already in progress, with additional packages scheduled for bid in 2026.
Strategic Importance
SEAP represents a major addition to Brazil's upstream portfolio, with total capex exceeding BRL 60 billion and expected recovery above 1 billion boe. Beyond liquids production, the project is strategically positioned to expand domestic gas supply, supporting energy security and infrastructure development in the Northeast region.
Asset Breakdown
SEAP I (P-81 FPSO):
Targets light oil accumulations in Agulhinha, Agulhinha Oeste, and Palombeta (BM-SEAL-10/11).
Capacity: 120,000 bbl/d oil, 10 million m³/d gas
Petrobras operatorship: 100% (BM-SEAL-10), 60% (BM-SEAL-11)
SEAP II (P-87 FPSO):
Covers Budião, Budião NW, and Palombeta (~80 km offshore, BM-SEAL-4/4A/10).
Capacity: 120,000 bbl/d oil, 12 million m³/d gas
Petrobras operatorship: 75% (BM-SEAL-4), 100% (BM-SEAL-4A/10)
Petrobras has taken Final Investment Decision (FID) on the SEAP I module in the Sergipe-Alagoas Basin, marking a key step in the phased development of the Sergipe Deepwater Project (SEAP), an emerging offshore production hub in Brazil. This follows the earlier FID for SEAP II in December 2025, confirming full-field development progression.
Project Economics and Commercial Structuring
Project sanction was enabled by a combination of cost optimization measures, supply chain engagement, and revised commercial frameworks. Petrobras worked closely with contractors to restructure contractual terms and improve project economics, enhancing overall IRR and resilience under oil price volatility scenarios.
A notable outcome was the joint procurement strategy for the P-81 (SEAP I) and P-87 (SEAP II) FPSOs. Bundling these units allowed Petrobras to capture synergies, standardization benefits, and economies of scale—key factors in achieving commercially viable agreements.
As a result, SEAP I has been incorporated into Petrobras' Base Implementation Portfolio, reinforcing the role of collaborative supplier engagement in unlocking complex deepwater developments.
Execution Model and Contracting Strategy
Both FPSOs will be delivered under a BOT (Build, Operate, Transfer) model, with SBM Offshore responsible for EPCIC and operations during the initial contract period prior to asset transfer. This model provides capital efficiency, schedule acceleration, and operational continuity.
Contract signing is expected in May 2026, subject to final governance approvals and partner alignment, enabling transition into the execution phase.
Production Capacity and Timeline
Combined, the two FPSOs will deliver:
Oil production capacity: 240,000 bbl/d
Gas processing capacity: 22 million m³/d
First oil is targeted for 2030, with gas export infrastructure coming online in 2031.
Field Development Scope
The SEAP development plan includes:
Drilling and completion of 32 subsea wells
Installation of subsea production systems, including Christmas trees and associated infrastructure
A 134 km gas export pipeline (111 km offshore, 23 km onshore)
Tendering for subsea hardware is already in progress, with additional packages scheduled for bid in 2026.
Strategic Importance
SEAP represents a major addition to Brazil's upstream portfolio, with total capex exceeding BRL 60 billion and expected recovery above 1 billion boe. Beyond liquids production, the project is strategically positioned to expand domestic gas supply, supporting energy security and infrastructure development in the Northeast region.
Asset Breakdown
SEAP I (P-81 FPSO):
Targets light oil accumulations in Agulhinha, Agulhinha Oeste, and Palombeta (BM-SEAL-10/11).
Capacity: 120,000 bbl/d oil, 10 million m³/d gas
Petrobras operatorship: 100% (BM-SEAL-10), 60% (BM-SEAL-11)
SEAP II (P-87 FPSO):
Covers Budião, Budião NW, and Palombeta (~80 km offshore, BM-SEAL-4/4A/10).
Capacity: 120,000 bbl/d oil, 12 million m³/d gas
Petrobras operatorship: 75% (BM-SEAL-4), 100% (BM-SEAL-4A/10)
#26
Dgitilization (AI, Machine Learning, Data) / SLB and Azule Energy Scale Ent...
Last post by Administrator - Apr 13, 2026, 04:53 AMHOUSTON Mar. 31, 2026 — Global technology company SLB (NYSE: SLB) today announced a three-year agreement with Azule Energy to continue and expand the use of its enterprise digital platform across Azule's operations in Angola. The platform will help Azule drive more consistent execution, accelerate decision-making, and support reliable energy delivery across its portfolio.
Azule Energy — a joint venture of bp and Eni and the largest independent energy producer in Angola — operates some of the region's most complex assets. The agreement builds on two years of Delfi™ use within Azule's reservoir organization, where the platform supports reservoir studies, modelling, simulation, and well planning workflows, and supports enterprise-scale digital integration by connecting reservoir workflows with broader operational data environments over time.
"Azule operates large, complex energy assets where execution reliability and consistency matter," said ND Maduemezia, president, Europe and Africa, SLB. "This agreement expands the use of an enterprise digital platform that connects workflows and data, strengthening and accelerating decision-making and improving execution predictability in support of reliable energy delivery in Angola."
The agreement reflects a move to enterprise-scale digital operations, enabled by SLB's digital platform and cloud-based capabilities. Delivery is supported through the SLB Luanda Performance Center, which enables digital solutions to be deployed and sustained locally.
The platform supports key workflows across Azule's reservoir and planning activities, with integration into broader operational data environments over time. It also positions Azule to rapidly adopt new digital and AI-enabled technologies as they emerge, enabling continuous performance improvement.
Early deployments demonstrate impact: integrated workflows, including DrillPlan™ coherent well planning and engineering solutions, have cut planning cycles from days to hours while increasing automation and minimizing manual coordination.
The enterprise platform reinforces execution consistency across Azule's large, mature operations, where operational discipline is central to sustaining performance.
Azule Energy — a joint venture of bp and Eni and the largest independent energy producer in Angola — operates some of the region's most complex assets. The agreement builds on two years of Delfi™ use within Azule's reservoir organization, where the platform supports reservoir studies, modelling, simulation, and well planning workflows, and supports enterprise-scale digital integration by connecting reservoir workflows with broader operational data environments over time.
"Azule operates large, complex energy assets where execution reliability and consistency matter," said ND Maduemezia, president, Europe and Africa, SLB. "This agreement expands the use of an enterprise digital platform that connects workflows and data, strengthening and accelerating decision-making and improving execution predictability in support of reliable energy delivery in Angola."
The agreement reflects a move to enterprise-scale digital operations, enabled by SLB's digital platform and cloud-based capabilities. Delivery is supported through the SLB Luanda Performance Center, which enables digital solutions to be deployed and sustained locally.
The platform supports key workflows across Azule's reservoir and planning activities, with integration into broader operational data environments over time. It also positions Azule to rapidly adopt new digital and AI-enabled technologies as they emerge, enabling continuous performance improvement.
Early deployments demonstrate impact: integrated workflows, including DrillPlan™ coherent well planning and engineering solutions, have cut planning cycles from days to hours while increasing automation and minimizing manual coordination.
The enterprise platform reinforces execution consistency across Azule's large, mature operations, where operational discipline is central to sustaining performance.
#27
SBM Offshore / Guyana - Longtail
Last post by Administrator - Apr 13, 2026, 04:49 AMSBM Offshore awarded FEED contracts for the Longtail project in Guyana
SBM Offshore is pleased to announce it has been awarded contracts by ExxonMobil Guyana Limited, an affiliate of Exxon Mobil Corporation, to perform Front End Engineering and Design (FEED) studies for a Floating Production, Storage and Offloading vessel (FPSO) for the Longtail development project in Guyana.
The FEED contracts award triggers the initial release of funds by ExxonMobil Guyana Limited to begin FEED activities and allocate a Fast4Ward® hull for the Longtail development project in Guyana. SBM Offshore will further construct and install the FPSO, subject to government approvals of the development plan, final investment decision by ExxonMobil, and project approval to release the second phase of work.
Under the contracts, the FPSO's ownership is expected to be transferred to the client at the end of the construction period and before start of operations in Guyana. The construction costs are expected to be partially funded by senior loans which will be repaid at the time of the FPSO's transfer to the client.
SBM Offshore is expected to operate the FPSO through its integrated operations and maintenance model combining SBM Offshore and ExxonMobil's expertise and experience, leveraging key learnings and the operational excellence of the units currently deployed in Guyana.
SBM Offshore will design and construct the FPSO using its industry-leading Fast4Ward program using the Company's ninth new build, Multi-Purpose Floater hull, combined with several standardized topsides modules. The FPSO will be designed to process 1,200 million cubic feet of gas per day and produce 250,000 barrels of condensate per day. The FPSO will be spread moored in water depth of about 1,750 meters and will be able to store around 2 million barrels of condensate.
Building on the experience to date of FPSOs Liza Destiny, Liza Unity, Prosperity, ONE GUYANA and Jaguar, SBM Offshore continues to commit to local content development in Guyana by sourcing fabrication scope locally and integrating Guyanese engineers into the execution and operational teams.
SBM Offshore is pleased to announce it has been awarded contracts by ExxonMobil Guyana Limited, an affiliate of Exxon Mobil Corporation, to perform Front End Engineering and Design (FEED) studies for a Floating Production, Storage and Offloading vessel (FPSO) for the Longtail development project in Guyana.
The FEED contracts award triggers the initial release of funds by ExxonMobil Guyana Limited to begin FEED activities and allocate a Fast4Ward® hull for the Longtail development project in Guyana. SBM Offshore will further construct and install the FPSO, subject to government approvals of the development plan, final investment decision by ExxonMobil, and project approval to release the second phase of work.
Under the contracts, the FPSO's ownership is expected to be transferred to the client at the end of the construction period and before start of operations in Guyana. The construction costs are expected to be partially funded by senior loans which will be repaid at the time of the FPSO's transfer to the client.
SBM Offshore is expected to operate the FPSO through its integrated operations and maintenance model combining SBM Offshore and ExxonMobil's expertise and experience, leveraging key learnings and the operational excellence of the units currently deployed in Guyana.
SBM Offshore will design and construct the FPSO using its industry-leading Fast4Ward program using the Company's ninth new build, Multi-Purpose Floater hull, combined with several standardized topsides modules. The FPSO will be designed to process 1,200 million cubic feet of gas per day and produce 250,000 barrels of condensate per day. The FPSO will be spread moored in water depth of about 1,750 meters and will be able to store around 2 million barrels of condensate.
Building on the experience to date of FPSOs Liza Destiny, Liza Unity, Prosperity, ONE GUYANA and Jaguar, SBM Offshore continues to commit to local content development in Guyana by sourcing fabrication scope locally and integrating Guyanese engineers into the execution and operational teams.
QuoteØivind Tangen, SBM Offshore's Chief Executive Officer:
"We are proud to receive this sixth FPSO award from ExxonMobil Guyana. This project underscores the strength of our Fast4Ward approach and extensive experience in large-scale gas-processing systems. SBM Offshore is well positioned to support the Longtail development, a major gas play demanding the highest gas handling capacity ever deployed on an FPSO. Our teams remain fully committed to supporting the success of this project and ExxonMobil's long-term energy development strategy."
#28
Maritime / World’s First 24,000 TEU Metha...
Last post by Administrator - Apr 12, 2026, 04:54 AM
On December 31, 2025, the world's first 24,000 TEU methanol dual-fuel container ship, built by Nantong COSCO KHI Ship Engineering under COSCO Shipping Heavy Industry, was successfully launched. The milestone vessel fills a gap in China's design and construction capability for ultra-large methanol dual-fuel container ships, offering a Chinese contribution to the global maritime industry's low-carbon transition.
The vessel is among the largest and most technologically advanced green container ships in operation today. Measuring 399.99 meters in length, its deck area is comparable to approximately 3.5 standard football fields. Equipped with a methanol dual-fuel propulsion system, the ship is designed for both high efficiency and low emissions, enabling carbon-neutral operations throughout its voyages.
Fully independently designed and built by Nantong COSCO KHI Ship Engineering, the vessel integrates multiple industry-leading technologies. The project overcame key technical challenges, including intelligent and efficient construction of ultra-large hull structures and the structural safety design of methanol fuel tanks. These breakthroughs provide a strong foundation for the independent development and large-scale construction of clean-energy vessels in China.
As one of China's first batch of "National Excellence-Level Smart Factories," Nantong COSCO KHI Ship Engineering has pursued innovation-driven and lean manufacturing development. The company has advanced smart manufacturing and green transformation, establishing multiple automated and intelligent production lines that have significantly improved shipbuilding processes and efficiency. It has delivered a wide range of high-end vessels, including ultra-large container ships, bulk carriers, tankers, and car carriers, filling several domestic and international technological gaps.
In response to the global shipping industry's shift toward green and low-carbon development, COSCO Shipping Heavy Industry continues to prioritize technological innovation and core shipbuilding capabilities, focusing on green, low-carbon, and digital-intelligent transformation. The company aims to provide global clients with more environmentally friendly, intelligent, and safe maritime equipment.
#29
Exploration / Rhino announces successful wel...
Last post by Administrator - Apr 12, 2026, 04:48 AM23 Feb 2026
Rhino Resources Namibia Ltd ('Rhino' or 'the Company') provides the following update on behalf of the Petroleum Exploration License 85 ("PEL85") JV regarding the drill stem testing activities of the Volans-1X discovery on Block 2914A, offshore Orange Basin, Namibia.
PEL 85, where the well was drilled, is operated by Rhino with a working interest of 42.5%. Co-venturers are Azule Energy (42.5%), NAMCOR (10%), and Korres Investments (5%).
The Volans-1X well, spudded on 31 July 2025 using the Northern Ocean's semi-submersible Deepsea Mira, reached a total depth of 4,497.5m TVDSS on 30 August 2025, successfully penetrating the Upper Cretaceous target, with partners declaring the well a high liquid-yield gas condensate discovery in excellent quality reservoir on 1 October 2025.
Following the discovery, the partnership returned to Volans-1X to execute well testing operations between 5 and 13 January 2026. The well was perforated across 29,7m of the target reservoir interval which provided the following data:
• Strong deliverability: 33Mmscfd of gas and ~5.3kkbls condensate on a 46/64 choke
• High liquid gas condensate: CGR of ~160 STB/Mmscf
• Low CO2 and H2S: 1-2% CO2 and ca. 3ppm H2S (highest value of 5ppm in 200 samples)
Commenting on the update, Chief Executive Officer Travis Smithard said:
Rhino Resources Namibia Ltd ('Rhino' or 'the Company') provides the following update on behalf of the Petroleum Exploration License 85 ("PEL85") JV regarding the drill stem testing activities of the Volans-1X discovery on Block 2914A, offshore Orange Basin, Namibia.
PEL 85, where the well was drilled, is operated by Rhino with a working interest of 42.5%. Co-venturers are Azule Energy (42.5%), NAMCOR (10%), and Korres Investments (5%).
The Volans-1X well, spudded on 31 July 2025 using the Northern Ocean's semi-submersible Deepsea Mira, reached a total depth of 4,497.5m TVDSS on 30 August 2025, successfully penetrating the Upper Cretaceous target, with partners declaring the well a high liquid-yield gas condensate discovery in excellent quality reservoir on 1 October 2025.
Following the discovery, the partnership returned to Volans-1X to execute well testing operations between 5 and 13 January 2026. The well was perforated across 29,7m of the target reservoir interval which provided the following data:
• Strong deliverability: 33Mmscfd of gas and ~5.3kkbls condensate on a 46/64 choke
• High liquid gas condensate: CGR of ~160 STB/Mmscf
• Low CO2 and H2S: 1-2% CO2 and ca. 3ppm H2S (highest value of 5ppm in 200 samples)
Commenting on the update, Chief Executive Officer Travis Smithard said:
Quote"These well test results validate our pre-drill optimism around Volans with the flow data suggesting that Volans-1x well was drilled in a geologically contiguous reservoir system, which is very encouraging for our ongoing development planning purposes. The test confirmed good flow rates of hydrocarbons, with liquid production in line with the condensate-gas-ratio range that we had previously guided. The data also indicates the useful calibration with the discovery at Capricornus, which has served to de-risk Volans and provide a far more holistic understanding of the reservoir distributions across the block. These positive test results are critical in informing Rhino, in collaboration with our partners Azule Energy, NAMCOR and Korres on how to assess the next steps for appraisal, development and production planning across the acreage."
#30
Middle East / Iran attacked Ras Laffan LNG I...
Last post by Administrator - Apr 12, 2026, 02:45 AMQatarEnergy has estimated that missile strikes on Ras Laffan Industrial City on 18–19 March 2026 will result in roughly $20 billion in annual lost revenue, with repairs expected to take up to five years. The damage is also likely to disrupt energy supplies to key markets in Europe and Asia.
In a statement addressing the incident, Minister of State for Energy Affairs and QatarEnergy CEO Saad Sherida Al-Kaabi confirmed that no injuries were reported. He condemned the attacks, describing them as unjustified and harmful not only to Qatar but to global energy security and stability, emphasizing their broader impact on economic development and reliable energy access.
The strikes affected two LNG production units—Trains 4 and 6—with a combined capacity of 12.8 million tons per year, representing about 17% of Qatar's LNG exports. Both facilities are joint ventures with ExxonMobil. Repairs to the damaged LNG infrastructure are expected to take between three and five years, potentially forcing QatarEnergy to declare force majeure on some long-term supply contracts, particularly affecting countries such as China, South Korea, Italy, and Belgium.
The Pearl GTL facility, operated by Shell, was also targeted. One of its two production trains sustained damage and is expected to remain offline for at least a year. This outage will reduce output of several associated products, including condensates, liquefied petroleum gas, naphtha, sulfur, and helium—each representing notable shares of Qatar's export volumes.
Al-Kaabi also praised the swift response of Qatar's military, security forces, and energy sector emergency teams, noting their professionalism in containing the situation safely and efficiently.
In a statement addressing the incident, Minister of State for Energy Affairs and QatarEnergy CEO Saad Sherida Al-Kaabi confirmed that no injuries were reported. He condemned the attacks, describing them as unjustified and harmful not only to Qatar but to global energy security and stability, emphasizing their broader impact on economic development and reliable energy access.
The strikes affected two LNG production units—Trains 4 and 6—with a combined capacity of 12.8 million tons per year, representing about 17% of Qatar's LNG exports. Both facilities are joint ventures with ExxonMobil. Repairs to the damaged LNG infrastructure are expected to take between three and five years, potentially forcing QatarEnergy to declare force majeure on some long-term supply contracts, particularly affecting countries such as China, South Korea, Italy, and Belgium.
The Pearl GTL facility, operated by Shell, was also targeted. One of its two production trains sustained damage and is expected to remain offline for at least a year. This outage will reduce output of several associated products, including condensates, liquefied petroleum gas, naphtha, sulfur, and helium—each representing notable shares of Qatar's export volumes.
Al-Kaabi also praised the swift response of Qatar's military, security forces, and energy sector emergency teams, noting their professionalism in containing the situation safely and efficiently.