Recoverable barrels of oil from a well in the Bourdon prospect in the Dussafu Licence offshore Gabon have successfully surpassed millions following drilling
The second sidetrack DBM-1 ST2 well that has been drilled by the Norve jack-up rig for BW Energy has revealed 56 million barrels oil estimates in place. Of these, approximately 25 million barrels are considered recoverable.
Confirming the substantial oil discovery with good reservoir and fluid quality, Carl K Arnet, CEO of BW Energy, said, “The appraisal well confirms the potential for establishing a new development cluster with a production facility following the MaBoMo blueprint. We expect at least four producing wells.”
“We continue to successfully expand the Dussafu reserve base which, together with multiple additional prospects yet to be drilled, will support long-term production and value-creation in Gabon.”
Initial data shows that oil from Bourdon field has the lowest viscosity of the Dussafu discoveries measuring an average of 3.5 centipoise (cp), compared to 5 cp and 7 cp for the Hibiscus / Tortue and Ruche fields, respectively.
Evaluation of logging data and formation pressure measurements confirm approximately 11.2 metres of pay in an overall hydrocarbon column of 35.2 metres in the Gamba formation, drilled to a depth of 4,731 metres.
Bourdon is located approximately 15 kilometres west of FPSO BW Adolo and 7.5 kilometres southeast of the MaBoMo facility. The discovery will enable the Company to book additional reserves not included in its 2024 Statement of Reserves.
Seamless tubular solutions provider, Vallourec, has been chosen by Allseas to supply line pipes for Buzios 10 offshore project located at the Petrobras-operated Buzios field.
The risers and flowlines for the project will be made of Vallourec's 18,000 tons of subsea seamless premium carbon steel line pipes. The contract also extends beyond this initial offering to also leave scope for an aditional 5,000 tons approximately.
The Buzios field that is situated off the coast of Rio de Janeiro is one of the world's largest deepwater fields under Petrobras' name. Undoubtedly one of the company's most important portfolio, five additional units from the site are being worked upon so that they can start production to meet optimisation targets by 2028.
The services of a centralised digital portal by Vallourec called the Pipe Navigator solution will also be a part of the contract, offering the client a holistic idea of its line pipe projects via instant up-to-date contractual documentation, data and analysis. The entire production will be carried out at Valourec's facility in Jeceaba (Minas Gerais, Brazil) to ensure high local content and a reduced carbon footprint.
Philippe Guillemot, Group's Chairman and CEO, said, “This contract reinforces our strategic positioning in Brazil, one of our key markets for complex offshore projects. It also serves as legacy to our ability to deliver premium tubular solutions, fully manufactured in Brazil. This contract also validates the investment strategy implemented over the past three years to enhance our industrial performance and meet the most demanding requirements of our customers.”
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Helix Energy Solutions Group reported reduced well intervention revenues during Q1 2025 citing lower utilisation rates in the North Sea — but warned of more pressing industry-wide problems up ahead.
Owen Kratz, Helix President and CEO, identified a series of potential forward challenges, including an increasingly testing North Sea market environment with some operators looking to put the brakes on work as a result of recent commodity price falls.
In its latest set of results, the company said Q1 well intervention revenues decreased by US$27.8mn, or 12% compared to the prior quarter “primarily due to seasonally lower utilisation in the North Sea,” as well as mobilisation and docking issues relating to its Q7000 vessel in Brazil.
The Houston-based group’s well intervention vessels include the Q4000, the Q5000, the Q7000, the Seawell, the Well Enhancer, and two chartered monohull vessels, the Siem Helix 1 and the Siem Helix 2.
Its well intervention portfolio includes intervention riser systems, subsea intervention lubricators and the Riserless Open-water Abandonment Module.
“As expected, our first quarter was impacted by the seasonal slowdown in the North Sea and the Gulf of America shelf,” said Kratz.
However, he also warned of a series of major challenges facing the industry in the coming year.
“Our first quarter has been overshadowed by the announcement of production increases by OPEC+, the announcement of US tariffs and its impact on the global market, and the continuing challenges of the North Sea oil and gas market,” he said.
“The confluence of these events has caused a precipitous drop in commodity prices and created uncertainty for our customers and the global economy. As a result, we are seeing some operators pausing work, notably in the North Sea where the current regulatory environment was already challenging for offshore oil and gas production.”
In response to the new market environment, Helix is adjusting its own operations to align with decreased activity, including the decision to stack the Seawell due to the weak North Sea well intervention climate, “but with our strong balance sheet and backlog of contracted work, we nevertheless expect to generate meaningful free cash flow in 2025,” said Kratz.
Helix also noted that its quarterly revenue decreases were offset partially by higher rates during Q1 2025.
Utilisation on the offshore service company’s North Sea vessels declined to 17% during the quarter, from 38% during the prior quarter.
As well as well intervention services, Helix also operates in other market segments including robotics, shallow water abandonment and production facilities.
A well engineer from Slb recently demonstrated the tackling of injectivity issues on an offshore well during the Society of Petroleum Engineers’ (SPE) Nigeria Annual International Conference and Exhibition.
Characterised by high-permeability and unconsolidated sands in a prolific turbidite reservoir, pressure maintenance at the AX field were initially conducted by deviated frac-pack injectors which fell short in keeping issues such as fines migration and other formation damage mechanisms in check.
To address this issue, horizontal injectors were chosen, offering larger flow areas and lower velocities to mitigate sand production risks. This, however, did not turn out enough for the AX9 well, as water injectivity level still remained markedly low. It required proactive intervention to curb formation damage while ensuring long-term well integrity. Advanced surveillance techniques, including Hall plot analysis, were deployed to confirm that injectivity decline was caused by internal formation damage rather than wellbore restrictions. Mineralogical analysis revealed the presence of fines-prone clays such as Smectite, Illite, and Kaolinite, which contributed to plugging and injectivity impairment.
This gave birth to a stimulation strategy tailored to AX9’s specific reservoir characteristics. Early intervention was initiated while the well was still operating in matrix mode, ensuring maximum benefit from the stimulation process. In line with the AX9 formation, a matrix acid stimulation plan was developed utilising a nitrified mud acid system with continuous foam diversion. The metculous preparation of critical components were involved from high-pressure nitrogen units and fluid pumps to IWOCS systems, among others.
The nitrogen foaming-supported treatment sequence involved multiple stages, including ammonium chloride pre-flushes, acid pre-flushes, a main stage of 13.5:1.5 mud acid, and post-flushes. This made sure even acid distribution and effective fines removal.
Post-treatment the injection rate improved to 43 kbwpd, with a substantial pressure drop of 21% and the injectivity index rose from 20 to more than 80-100 bpd/psi. Besides the improved injection rates, the treatment helped boost production by an additional 5,000 barrels per day approximately.
Decom Engineering, subsea cutting specialist and provider of green decommissioning solutions, continues to expand globally, winning contracts for its subsea cutting solutions in the Gulf of Mexico and elsewhere.
The company won contracts v.alued at more than £2 million (US$2.7 million) in the first quarter of 2025, including a chain cutting scope in the Gulf of Mexico in which it will deploy its new ultra-light and neutrally buoyant C1-16 chopsaw to cut studless mooring chains.
Offshore Brazil a 300-day campaign will see two C1-16 chopsaws cutting multiple link mooring chains of up to 142mm diameter, while a project due to start offshore Nigeria will involve tender cutting and flexible riser cutting scopes.
Decom Engineering’s range of cold cuttings Chopsaws can perform “clean cuts” through 2-46” materials and which can operate in the harshest working conditions, including subsea. The cutting saws are a cost-effective, snag-free alternative to diamond wire saws and hydraulic shears, and can be deployed on pipes, drill pipe, conductors, umbilicals, chains, wire rope and more.
Decom recognised the need to devise neutrally buoyant integration for its cutting tools when it was last year commissioned to assist with the removal of 30” conductors - with flexible risers inside - on the Brent Charlie platform in the UKCS. Due to the seabed conductor layout and restricted 3 metre width access, Decom’s C1-32 chopsaw had to be neutrally buoyant in seawater and easily manoeuvreable with a single ROV. Weighing approximately 6,700kg in air but only 50kg in seawater and with a blade diameter of 2,100mm, the C1-32 assisted with the cutting of 40 multi-string conductors, many with the added challenge of loose internal strings.
Decom Engineering commercial director Nick McNally said, “By analysing past campaigns in challenging environments including the Indian Ocean and the North Sea, we have fine-tuned our designs to perform seamlessly in extreme conditions.
“The development and integration of enhanced blade technology such as replaceable tips, custom deployment frames, and increased operational flexibility ensures that our tools are equipped to handle even the most demanding offshore operations with precision and reliability.
“On several projects we have been asked to assist on structural removal scopes after other cutting technologies have proven not to be capable, and this contingency role is now moving Decom into a position where we are becoming the first choice on larger and more complex scopes.”
Other solutions offered by Decom include a pipe coating removal machine which it says is the fastest and greenest process on the market. The cold process is capable of removing multiple coating types from decommissioned or surplus pipelines. The pipelines can then be repurposed and deployed in a number of sectors, for example piling and construction, which returns value to the client while decreasing the carbon footprint compared to using new steel.
The Asia Pacific (APAC) offshore well intervention market is witnessing significant growth, given the advancements in technologies that are capable of boosting operational efficiency while reducing operator costs.
The future scope of the APAC Well Intervention Market points towards further expansion as exploration and production (E&P) activities in the region continue to thrive. The integration of automation and digitalisation in well intervention processes is expected to play a major role in driving market growth. Moreover, rising offshore production activities, especially in countries with untapped hydrocarbon reserves, are projected to offer lucrative opportunities for well intervention services.
Environmental regulations and a focus on sustainable production will also influence the adoption of advanced technologies and efficient well management practices. This evolving market landscape presents ample growth potential for stakeholders in the APAC Well Intervention Market in the years to come.
Petrobras-contracted PA-38 jack-up platform has arrived in the Sergipe Basin to initiate well decommissioning activities in the Guaricema field, in shallow waters, approximately 9km from the coast.
These are in line with Petrobras' US$1.7bn-worth Facilities Decommissioning Programme in Sergipe that falls under the company's Strategic and Business Plan for the period 2025 to 2029.
With legs measuring almost 150 meters in height (equivalent to a 42-story skyscraper) and weighing 12,700 tons (equivalent to more than 12,000 popular cars), the self-elevating platform will perform intervention activities in oil and natural gas wells for their deactivation and capping. The initial campaign will last approximately seven months, with subsequent movement to other wells.
“Petrobras is advancing its decommissioning processes in the Sergipe Basin, a natural step for assets with more than 25 years of production in a mature industry such as Brazil’s oil and gas industry. All work is being conducted using the best techniques and in line with current regulations,” said Carlos Castilho, Petrobras’ General Manager of Decommissioning Projects.
The decommissioning of as many as 26 production units will be initiated by Petrobras in Sergipe, unlocking opportunities to the industry and the local supply chain. The Sergipe Basin is the second with the largest volume of investments in decommissioning in the country, right after the Campos Basin, which occupies the first position. Petrobras' operational unit in the region, headquartered in Aracaju, is dedicated to decommissioning operations in the Sergipe-Alagoas, Rio Grande do Norte and Ceara Basins.
Island Drilling Company's Island Innovator semi-submersible rig is set for action in the Norwegian continental shelf (NCS) to deliver a well pugging operation for Equinor.
Scheduled for start-up early 2026, the rig will be held by Equinor under a three-year contract worth nearly US$330mn with five one-year scopes available. The contract outlines mobilisation, planned upgrading and certain integrated drilling services.
“We will drill 600 improved oil recovery wells and about 250 exploration wells to maintain our production on the NCS towards 2035. At the same time, many wells will be permanently securely plugged. This rig provides us with a tool specially designed for plugging operations. The initial plan is a three-year work programme, but we do not rule out utilising the rig for operations also in the longer term,” said Erik G. Kirkemo, Equinor’s senior vice president for drilling & well.
According to the plan Island Innovator will permanently plug 15 to 20 wells annually for a total of nine licences. These wells will no longer be used for oil or gas production. The rig will plug subsea wells at Heidrun, Snorre and Norne, among others.
Island contract besides, Equinor has awarded framework agreements to the oil service companies Archer Oiltools and Baker Hughes Norge for full-range delivery of plugging services with a duration of three years, with two two-year options.
Archer Oiltools has also been assigned responsibility for planning plugging operations for 26 wells to be plugged from Island Innovator, in addition to options to perform the work.
“Through these contracts the suppliers are involved at an early stage and get a greater responsibility for planning the plugging operations, closely monitored by Equinor, who has the overall responsibility. We facilitate the industrialisation of safe and efficient plugging operations, ensuring continuous improvements together. This is about ensuring quality and reducing costs for work that will gradually increase on the NCS in the future,” said Mette H. Ottøy, Equinor’s chief procurement officer.
A recent breach flagged by Australia’s offshore regulator Nopsema during decommissioning activities on the Stybarrow field highlights some of the hazards now facing operators.
As Australia’s decommissioning effort gathers pace — an industry estimated to be worth US$60bn over the next few decades — oil and gas operators must seek to navigate what is becoming an increasingly complex legal and regulatory minefield.
Nopsema recently issued US-based offshore contractor McDermott with an ‘Improvement Notice’ citing safety concerns on its DLV2000 construction vessel.
The ship was undertaking decommissioning activities at the Stybarrow field for operator, Woodside Energy, but was ordered to cease work until it had rectified any breaches.
A Nopsema inspector visited the ship in March and raised concerns about the securing of a portable generator, which it was claimed could have resulted in heightened health and safety risks to personnel on board.
“The incorrect securing of the generator resulted in the generator shifting, when the generator was used as a secure point for belaying a tag line, subsequently the tag line became snagged,” the Improvment Notice stated on 20 March, 2025.
“The Manual does not describe the assurance procedure to ensure the generator has suitable sea fastening.”
The status of the case has now been marked as ‘Complied With’, which suggests that McDermott took immediate action to rectify the issue.
It highlights the increasing glare of regulators on the industry as it grapples with the decommissioning challenge.
Nopsema has scrutinised the work of other offshore contractors in recent times, including Subsea 7, though this was not linked to decommissioning activities.
The Stybarrow development is situated within production licence WA-32-L located on the North West Shelf in Commonwealth waters ranging from 700 to 850 metres in depth, approximately 51 km northwest of the North West Cape, Western Australia.
First oil was produced at the field in 2007 and production ceased in 2015.
Subsea infrastructure connected the field’s reservoirs to the Stybarrow floating production, storage and offtake (FPSO) facility, which has already been removed.
At the cessation of production, all wells were bull-headed and valves were pressure tested and closed, while flowlines were flushed with treated seawater.
Ongoing operations involve periodic surface and subsea inspections of the remaining subsea infrastructure.
“Well abandonment and full-field decommissioning of the remaining infrastructure will be undertaken at a future point in time and will be subject to separate approvals for this phase of activities,” Nopsema states in an information resource on its website.
Following 2024's extensive eight-well production drilling campaign in the Dussafu Marin permit offshore Gabon, operator BW Energy and partner Panoro Energy have managed to hit their production targets of 40,000 barrels of oil per day (bopd) in November 2024, and has remained consistent since.
This was made possible by a robust workover and electrical submersible pump replacement programme with the help of Borr Drilling's Norve jack-up rig. An effective artificial lifet method, ESPs help pump production fluids from low pressure situations. It is easy to maintain, and is considered a cost effective alternative to vertical turbine, split case and positive displacement pumps.
At approximately 37,153 bopd in the fourth quarter of 2024, the site crossed a milestone as it was the highest quarterly rate achieved since 2018, when the block first started producing.
The current production rate might jump by another 10%, given the scope for the FPSO nameplate capacity to reach beyond 40,000 bopd.
After the 2024 production campaign concluded in October, with the installation of a conventional electrical submersible pump (ESP) system for the DHIBM-7H well as it was brought online, the rest of the seven Hibiscus / Ruche production wells also underwent a workover and ESP replacement programme in January this year.
According to Panoro Energy's Chief Executive Officer, John Hamilton, the Dussafu drilling campaign was expanded to eight wells in order to accomodate first track development of the final two discoveries made in May 2024.
“Our current focus is on fully transitioning all the new wells to conventional ESP systems and restoring production at the three shut-in wells, after which we will drill the exciting Bourdon prospect in line with our infrastructure lead exploration and appraisal strategy aimed at unlocking the substantial organic upside that exists on the block,” said Hamilton, while speaking on the drilling campaign.
As part of its 2025-26 programme in Gabon, Borr Jack-Up XIV Inc will be deployed by Vaalco Energy for the drilling of multiple development wells and appraisal/exploration wells.
"We are excited about the major projects planned for 2025 that are expected to deliver a step-change in organic growth across our portfolio in the coming years. In Gabon, we continue to work with our joint owners at Etame on our shared goal of executing another successful drilling campaign designed to enhance production and add reserves. We have signed a contract with Borr that we believe allows us the flexibility to optimise our drilling and workover plans offshore Gabon.
“We anticipate the programme to begin in mid-2025 with the sequencing and exact number of wells yet to be finalised. We are planning on multiple wells in the Etame field, multiple wells at our SEENT platform and a redrill and several workovers in the Ebouri field to access production and reserves that were previously shut in and removed from proved reserves due to H2S. Over the past three years, we have delivered on our focused strategy and believe we will continue to do so with the organic growth programmes across our diversified portfolio over the coming years,” said George Maxwell, the Chief Executive Officer of Vaalco Energy.
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A number of technologies and equipment have been developed towards the drilling and completion of deep and ultra-deep wells.
This technology is developing towards composite bit, special-shaped tooth PDC, adaptive bit, intelligent bit, electric drill, real-time optimisation and non-contact rock breaking.
This technology is developing towards higher efficiency, whole process clean and environmental protection, intelligence and recycling; ultra-high temperature, extremely low temperature, nanometer, strengthening borehole wall materials and intelligent treating-agents will occur; and the integrated lost circulation resistance and plugging of malignant thirsty formations containing vugs or fractures will develop towards online performance measurement and control, automatic closed-loop solid control and automatic mud preparation system.
This technology is developing towards operation automation, information, intelligence and whole life cycle control of cementing process; cementing materials are developing towards ultra-high temperature, functionality, safety, environmental protection and adaptability; and cementing tools are developing towards high stability and high reliability under complex process conditions.
Coiled tubing operation is developing towards well logging, cementing, completion fracturing, downhole operation integration and deep ultra-deep layers, while coiled tubing drilling is developing towards intelligent measurement and control while drilling and closed-loop steering drilling
Addressing a challenging deepwater permanent abandonment operation in the Gulf of America (GOA), Oilfield Service Professionals (OSP), along with Lee Energy Systems (LES), initiated the PerfPro Perf & Squeeze method to overcome the limitations that arise out of mechanical blowout preventer (BOP), posing an obstacle to conventional cut-and-pull operations for the 14.15” casing string. In case explosive perforative guns needed deployment, a lot of uncertainty centred marred casing centralisation, giving rise to potential risks of unintentional perforation across multiple casing strings.
There were also other challenges concerning high-risk lower marine riser package (LMRP) interventions, which could introduce debris into the well, leading to costly extended work scopes.
The Bureau of Safety and Environmental Enforcement-approved PerfPro Perf & Squeeze method offered an innovative low-risk solution to these challenges. The single-trip Perf & Squeeze method was implement by OSP and LES to leverage its safer, faster, and cost-effective alternative to conventional approaches. The package comprised NEXUS High-Pressure/High-Tensile Packer, Gator Perforator, CatchPro Dart/Ball Catcher, and BarrierPro Hydra-Set Bridge Plug with Scraper System.
The PerfPro Perf & Squeeze method altogether eliminated the need for LMRP intervention, leaving the potential well debris issues out of the question. Without the rig, more than 24 hours were saved in terms of downtime. The method provides assurance against explosive perforating guns to avoid unknown casing centralisation. It ensures access to the 14" x 22” annulus above the 16” TOL, enabling placement and verification of two critical zonal isolation barriers. It executed rapid planning, testing, and deployment, including a pre-job perforation test on 14.15” casing to confirm operational feasibility.
The PerfPro Perf & Squeeze approach saved operators more than US$1mn in operational cost savings while enhancing safety and efficiency . It has the potential to redefine primary P&A approaches.
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