Latest News

• Region: North Sea
• Date: May, 2021

Following an offer letter signed in April 2021, Archer has announced that it has signed a sales and purchase agreement (SPA) to acquire DeepWell for NOK177mn on a debt and cash free basis which will be financed using existing cash and liquidity reserves.

DeepWell is a leading Norwegian well intervention company which provides wireline and downhole services to oil companies on the Norwegian Continental Shelf (NCS). The company currently employs approximately 200 people and, across 2020, had a revenue of around NOK360mn.

The acquisition of DeepWell, which commands one of the most modern wireline unit fleets on the NCS and holds a strategic long-term contract in the light well intervention market, will greatly enhance Archer’s well intervention service offerings in the North Sea.

Lage Nordby, Vice-President of Wireline at Archer, commented, "We are pleased to welcome DeepWell’s team of employees to Archer. By strengthening our wireline equipment fleet and organisation, increasing our low emission solutions, and continuing our track record for service quality, Archer is well positioned on the Norwegian Continental Shelf. The acquisition of DeepWell gives us access to equipment and employees needed in order to fulfill our obligations under our recently awarded wireline contracts with Equinor and ConocoPhillips."

Jan Erik Rugland, COO of Moreld AS and CoB of Deepwell, said, "We are pleased to have reached an agreement with Archer securing continued operations on existing contracts and the continued development of DeepWell’s state of the art wireline technology. I want to thank all the employees, both on- and offshore, for their dedication and perfection. This transaction is in line with our strategy to divest capital intensive businesses in order to focus our energy on transition and growth plans."

The closing of the transaction is expected to be finalised during Q2 2021 and is subject to customary closing conditions and regulatory approvals.

• Region: All
• Date: May, 2021

The rate of technological advancements is advancing, and it is pulling the oil and gas industry into new realms of digitalisation, automation, AI and more. The field has become more competitive and yet, despite this, the latest innovation from Blue Spark Energy, the wireline applied stimulation pulsing technology (the BlueSpark tool) which has the potential to radically increase the efficiency of well intervention operations, stands apart.

In a virtual webinar, Blue Spark Energy representatives Todd Parker, CEO, and Chris Grahame, VP of Sales and Marketing, presented the technology, describing it as the future of environmentally responsible wellbore interventions.

As Parker explained, the engineers at Blue Spark Energy have utilised electrical energy in a third format outside of AC or DC, high pulsed power, for application within the well intervention sector. High pulsed power is the idea of taking electricity and compressing it to be released in a very short period of time. Returning to school physics, power equals energy over time, so by reducing the time taken, the power is much higher. By example, Parker demonstrated a test in the Blue Spark Energy laboratory which used the energy equivalent to two cell phone batteries and releasing it in microseconds to generate power in the hundreds of megawatts range. The company has taken this and built a device to take electrical energy, compress it and then produce a high power output for use in the well intervention sector.

Production enhancement

So what can this technology actually do? Well, as Parker continued, “The primary application of this technology is to return oil wells to optimal production by removing blockages that could cause disruptions. The BlueSpark tool, through repeated high power pulses, can effectively remove organic and inorganic debris in production zones and reopen perforations which have been plugged either immediately after perforation or as the well has matured.”

Already Blue Spark Energy has deployed this technology in hundreds of wells across the globe and returned with some incredibly promising results. Listing some of these examples, Parker stated that in one example in the Middle East, a customer used the BlueSpark technology for two remote wells and found that the high power pulses were just as effective as coiled tubing acidisation methods and was able to more easily target specific zones. Additionally, the small footprint and ability to rapidly mobilise to the remote location (due to the small amount of equipment and personnel required) meant the BlueSpark tool produced the same result in just 10% of the time and led to an aggregate increase of 60% in oil production across the two wells.

Parker noted that the technology can be used to clear blockages across the wellbore – be that in the productive zone or the completion equipment further up – any part that has the capacity to create somewhere for debris to start building up the BlueSpark tool is effective at treating the disruption. It is also not restricted by the kind of debris that is obstructing the well, and anything from waxes, calcium carbonate or even iron sulphides can be treated. With other intervention methods you often need deeper diagnostics to ascertain what chemicals are required, for example, but all Blue Spark Energy operators need to confirm is if there is debris and where – they are not concerned with what it looks like or what it is.

To emphasise this, Parker added, “In the North Sea at an unmanned installation the operator encountered a barium sulphate scale build up in the tubing and across the surface controlled subsurface safety valve (SCSSV). Operators were unable to use conventional methods due to scale build up restrictions above the SCSSV and were therefore required to shut-in the well and set up a plug as a barrier below the SCSSV. We were able to take out a small wireline mast and within 24 hours place the technology across the SCSSV, remove the debris and put the well back into production. This was a 3500bpd producer in danger of being shut which we were able to rapidly treat without causing any damage.”

Multiple applications

In addition to cleaning screens and gravel packs in oil production, the BlueSpark tool has also been deployed for usage in other applications such as water source wells or improving geothermal efficiency, proving its versatility across the energy sector. In another case in the North Sea, Parker showed how the technology was used to improve the efficacy of decommissioning wells by removing debris to allow for a rigless type of decommissioning as opposed to section mill or something more complicated.

This technology, as Parker continued, is particularly suited when deployed by wireline tractor, and is compatible with all wireline industry equipment – if a perforating gun can be run off the wireline unit so can the BlueSpark tool. It is very transportable, able to be transferred in a helicopter for example, and is deployed in pairs to de-risk operating time. It also has an incredibly small environmental footprint, without using chemical fluids, explosives and requiring only a small amount of energy. Although the pulses are released at high power, due to the low energy used, there is no risk of damaging any equipment.

Saving money as well as the environment

After the webinar, Parker spoke to Offshore Network to shed more light on this innovative new technology and which markets the company is targeting in the future.

Parker said, “The process people are talking about a lot at the moment is the electrification of a lot of carbon intensive processes. The BlueSpark tool can become that intervention device that leads in the electrification of conventional well intervention techniques. There is no risk of creating a situation worse than you had before, no safety hazards, and finally you are reducing the carbon footprint of your intervention operations.”

Aside from the environmental and safety benefits, the BlueSpark technology also offers significant financial incentives as well. Parker added, “The costs savings mainly come from operators not having to move a rig or heavy equipment, and the ability to intervene quickly. It costs less to transport, there are less people required to move it, and it’s very fast to set up (there is no wellbore preparation). Looking from a fiscal perspective you are probably looking at being able to save more than 50% over using a conventional technique to accomplish the same result. We have case studies where we have saved customers days of operating time and millions of dollars.”

The story so far

Parker took some time to reflect on Blue Spark Energy’s journey so far which, at times, has been quite frustrating. He said, “The physics is basically high school physics, the engineering was not, so it took some time to build the tool robust, durable and slimmer to access more wellbores, but we finally had a commercial model in 2013 which we started to take around the world.”

“Unfortunately this is where you run up against the inherent conservativeness of the industry itself. From 2013 to 2018 we really faced that from a lot of operators who, broadly speaking were interested in new technology but really struggled to introduce it as it is radically changing their intervention, not changing a small part of it such as introducing a type of chemical. It took us a few years to get some customers to where they were comfortable making that change.”

Currently Blue Spark Energy has quite a large capacity, after deploying to more projects and manufacturing more assets to meet demand. It has ongoing projects in Nigeria, Denmark, Norway, the UK, Malaysia and the Middle East and, to date, has completed over 600 projects across the world working with a variety of clients such as Exxonmobil, Chevron, Shell, Equinor and more. Across the thousands of well descents attempted by the technology, it boasts a 99.6% operating efficiency and rarely creates downtime for customers. As there is a small amount of equipment and capex required to perform an operation, it is a relatively easy fleet to maintain. Additionally, as there are no complicated moving parts and the supply chain is quite simple, it is an extremely scalable business.

Looking ahead

Turning to the future, Parker commented, “Covid had an impact on business, 2020 was not our best year but it was our second best year. Now there is a tremendous backlog of wells that require maintenance and people want to do it rapidly and effectively, so we are envisioning a big uptake in activity in the short term. We think it is an opportunity for a lot of customers to see the benefit of this technology.”

Parker continued, “We want to continue to operate in logistically challenged regions, that is the easy argument. In some regions such as Africa, the Middle East, and Far East it is hard to get equipment to these locations, so why not try something radically different that is easy to get there.”

“The second dimension is we are still discovering additional applications. People are coming to us and asking, can we do it for this or use it for this purpose and we are continually refining the technology. So while there is a geographic spread there is also some technical growth we are seeing as well. Being able to help the decommissioning process, for example, to more effectively cut off any methane leaks in the future is exciting, as it is a big topic which at the moment has tremendous costs for operators. We are starting to get some real interesting air time in that space.”

• Region: West Africa
• Date: May, 2021

Petrofac has secured a contract with BP to develop operational procedures for the Greater Tortue Ahmeyim (GTA) Project in Mauritania and Senegal.

Centred on minimising risk and harm to personnel, plant and the environment, the procedures will encompass all offshore operations, including subsea, floating production storage and offloading (FPSO) and hub.

The Tortue Ahmeyim gas field, with estimated resources of 15 trillion cu ft of gas, is located offshore the border between Mauritania and Senegal in water depths of more than 2,000 metres. Spanning five blocks (three in Mauritania and two in Senegal) in addition to the GTA unit, the LNG project will have BP as operator and is being jointly developed by BP, Kosmos Energy, Societe des Petroles du Senegal (Petrosen) and Société Mauritanienne des Hydrocarbures.

The final investment decision (FID) for phase 1 of the project was taken in December 2018 with the FID for phase 2 expected in 2022. Initial production was projected in 2022 before Covid delays caused this to be pushed back to 2023. Once completed, the GTA LNG project is expected to produce up to 10mn tonnes of LNG a year.

The integrated gas value chain and near-shore liquefied natural gas (LNG) development will export LNG to global markets as well as supplying gas to Senegal and Mauritania.

On the opportunity to take part in this exciting project, Steve Webber, Senior Vice-President of Operations at Petrofac, commented, “BP is an important longstanding client and we look forward to supporting them in operating safely and responsibly, in their delivery of the GTA Phase 1 Project, which is creating a new LNG hub in Africa.”

• Region: North Sea
• Date: May, 2021

Aker BP was the first operator worldwide to use bismuth alloy to plug the top section of old oil wells. Since then, the technology is now used on 30 wells on the Valhall field, resulting in safer, permanent well plugging.

The Valhall field

The Valhall field in the southern part of the North Sea has produced over a billion barrels of oil equivalent since it began production. To ensure consistent performance, old oil wells must be plugged to make room for new wells in the hopes that over the next 40 years another one billion barrels of oil will be drawn up.

Martin Knut Straume, Aker BP’s Chief Engineer for Plugging and Abandonment, commented, “We’ll continue to work on Valhall for many decades to come. That means we have to make sure that we shut down and abandon old wells safely, so that it is safe for us to be there when we continue to produce and drill new wells at the same time. We use the best available technology, and in this case, in the top part of the old wells, that means bismuth.”

Aker BP has already started removing the old field centre on Valhall with the living quarters platform removed in 2019. Another two installations will disappear over the next five years and all wells connected to the old drilling platform will be permanently plugged over the course of 2021.

Egil Thorstensen, Senior Engineer for Plugging and Abandonment at Aker BP, said, “We’re currently installing bismuth plugs in the top section of all the wells; in other words, in the 30-inch casing. That’s the last thing we do before we cut and pull the pipes from the seabed to the platform, and the well is permanently abandoned.”

Diverse solutions provided by new technology

Plugging wells on Valhall may pose an additional challenge both due to gas migration to the surface, and due to subsidence and compaction. The seabed around the Valhall field has sunk seven metres since the early 1980s, and the top of the reservoir has dropped about 15 metres.

This means that cement, which is commonly used as a barrier material to plug wells, is an inadequate solution as it can fail when subjected to wellbore or casing stresses resulting from subsidence and compaction events. In the worst case, hydrocarbons in old wells could migrate upwards and potentially leak into the sea.

“Aker BP installed a trial plug over two years ago, and was the first operator worldwide to use bismuth alloy in the top section of the well. When we use this technology, we make sure that the plug is 100% impermeable. Gas cannot leak to the surface,” said Thorstensen.

Bismuth is a metal with unique properties that make it particularly well-suited for applications in P&A operations. As a solid metal, it is completely impermeable and is heavy as lead, making it less prone to contamination during its placement into the well. When melted, liquid bismuth flows like water, giving it the ability to flow into the smallest interstices in the well. When bismuth solidifies, it expands, which helps provide permanent sealing capability inside a wellbore.

Additionally, unlike cement plugs which need to be several dozens of metres in length in order to qualify as barrier, a 2.5 metre-long bismuth plug suffices to provide long term isolation in the well.

Reducing environmental impact

Bismuth alloy is typically a more expensive option than cement but total costs of plugging the top well sections are less due to decreased rig time for these operations.

“Even so, we have chosen to use it on Valhall because of the unique field conditions. For us, this is a matter of making sure that we minimise the carbon footprint from our operations, while ensuring that the wells are plugged and abandoned to the highest standard. Bismuth has what cement lacks: it changes almost instantaneously from liquid to solid when the heating source is removed, it is completely impermeable, and it is not affected by contamination issues,” commented lead technical engineer at Aker BP, Laurent Delabroy.

During the autumn of 2020 and winter this year, bismuth plugs were installed continuously from the Maersk Invincible rig on the Valhall field centre. The plugs are up to 2.5 metres long and weigh 9 tonnes. The work has been performed through the jack-up rig alliance between Aker BP, Maersk Drilling and Halliburton. Time spent per well was cut in half to a record-low 30 hours this winter which has resulted in significant cost savings and freed up several months of rig time that can now be used for new operations.

Delabroy concluded, “We succeeded through strong teamwork and close collaboration with our solid technology partner, BiSN. And last but not least, because we are part of a company that dares to use new technology. Aker BP is not only the first in the world to develop and perform this type of operation, we are now the world’s largest users of this technology, and many other oil and gas operators are following suit. That says something about our company.”

• Region: Latin America
• Date: May, 2021

Baker Hughes has been awarded a subsea oilfield equipment contract from Petrobras as part of the Marlim and Voador field revitalisation plan in the Campos Basin, offshore Brazil.

The contract includes several key technologies from Baker Hughes’ Subsea Connect portfolio and will provide Petrobras with a connected suite of solutions to help drive efficiencies, reduce costs and improve execution speed.

Baker Hughes will supply up to five subsea production and injection manifold systems, which benefit from a lightweight and compact design for installation from smaller vessels and include integrated hydraulic connection systems and retrievable choke modules to realise life of field cost savings. The manifold systems will also include Baker Hughes’ field proven vertical mechanical clamp connection system which increases installation efficiencies.

In addition to the manifold systems, Baker Hughes will provide 32 modular, structured, subsea control modules (called Modpods) which are powered by SemStar5 technology, manufactured in the company’s Nailsea facility in Bristol, UK. The modules have extensive field deployment history with a mean time between failures of more than 150 years.

Neil Saunders, Executive Vice President of Oilfield Equipment at Baker Hughes, commented, “This order is an important example of how Subsea Connect is bringing structured technology to improve execution certainty. We are able to deliver world-class subsea solutions with a breadth of expertise and skills to bring flexibility, scalability and versatility to complex projects. We are proud to partner with Petrobras on the revitalisation of Marlim and Voador and offer our latest subsea technologies for Brazil.”

The contract will include a global team of experts delivering the subsea production and injection manifold systems, subsea control modules, subsea connection systems and field installation support. The manifold systems will be fabricated, tested and assembled in Baker Hughes’ Centre of Excellence facility in Jandira, Brazil.

Adyr Tourinho, Vice President of Brazil and Oilfield Equipment for Latin America at Baker Hughes, said, “This contract is a culmination of our multi-year engagement with Petrobras and builds on our history supplying subsea production systems to deepwater projects in Brazil. Our lightweight, compact technology is engineered to combat the most demanding conditions found in today’s deepwater environments.”

A bright future ahead

Baker Hughes’ recent Q1 2021 results show that the company had faced a challenging year, suffering year on year declines in areas such as orders and revenue. However this is a squeeze being felt unanimously across the energy industry and Lorenzo Simonelli, Chairman and CEO of Baker Hughes, noted that he envisioned a bright future for the company, which will no doubt be aided by the recent agreements with Petrobras and other major players such as Saudi Aramco.

Simonelli commented, “We are pleased with our first quarter results as we generated strong free cash flow, continued to drive forward our cost-out efforts, and took further meaningful steps in the execution of our strategy. During the quarter, TPS delivered solid orders and operating income while OFS continued to execute cost-out programmes to help drive another strong quarter of margin performance. We also advanced our position in the energy transition, investing in strategic areas for growth and entering important partnerships to advance new energy frontiers including hydrogen and carbon capture, utilisation and storage.”

“As we look ahead to the rest of 2021, we remain cautiously optimistic that the global economy and oil demand will recover from the impact of the global pandemic. We expect spending and activity levels to gain momentum through the year as the macro environment improves, likely setting up the industry for stronger growth in 2022.”

• Region: Asia Pacific
• Topics: Decommissioning
• Date: May, 2021

Beacon Offshore and Claxton, the lead brand for the Acteon drilling and decommissioning business segment, have signed a master services agreement for the severance and recovery of more than 100 subsea wells in the Gulf of Thailand.

While detailed information of the agreement has so far been withheld, Sam Hanton, CEO of Claxton, stated, “The relationship with Beacon Offshore is a milestone for long-term collaboration in the region which was underpinned by significant effort and commitment by all parties.

“We are very excited about this project as it highlights Claxton’s rigless P&A capabilities and reflects the expertise of Claxton as a trusted partner in vessel-based decommissioning.”

Asia Pacific decommissioning

This is the latest agreement regarding decommissioning operations in Asia Pacific, a market which is expected to take off in the next few years largely due to the shared global desire to limit climate impact by ensuring abandoned wells are properly plugged and abandoned with infrastructure removed. While, traditionally, complicated government regulation and lack of experience has restricted such campaigns in the region, this problem is fast becoming too large to ignore, especially with a large number of fields approaching the end of their production life.

As Jean-Baptiste Berchoteau, Wood Mackenzie’s Asia upstream analyst, told Breakbulk last year, “With more than 380 fields expecting to cease production in the next decade, the magnitude and cost of work can no longer be ignored. Through learning from global decommissioning projects, the industry can adopt and adapt practices best suited for Asia-Pacific’s own set of challenges.”

Breakbulk noted that across the 380 fields there are 35,000 offshore wells, serviced by 2,600 platforms representing 7.5 million tonnes of steel and more than 55,000km of pipelines which will need to be retired in the forthcoming years – representing an enormous challenge which operators will have to deal with in order to meet their environmental commitments. Such a challenge, however, opens a very promising door for service providers such as Claxton who in the coming years will no doubt be called into action to conduct more decommissioning operations in this region.

• Region: Asia Pacific
• Date: Apr, 2021

 Reliance Industries Limited (RIL) and bp have announced the start of production from the Satellite Cluster gas field in block KG D6 located about 60km from the existing onshore terminal at Kakinada on the east coast of India in water depths of up to 1,850m.

RIL is India’s largest private sector company spanning hydrocarbon exploration and production, petroleum refining and marketing, petrochemicals, retail and digital services. Together with bp, the company has been developing three deep-water gas developments in block KG D6 – R Cluster, Satellite Cluster and MJ which are expected to produce a combined 30mn cu/m per day (around one billion cu/ft a day) of natural gas by 2023.

Both of the developments will utilise the existing hub infrastructure in the KG D6 block. RIL is the operator of the block with a 66.67% participating interest, while bp holds a 33.33% participating interest. It had originally been scheduled to start production in mid-2021.

The Satellite Cluster is the second of three scheduled developments to come onstream, following the start-up of R Cluster in December 2020. R Cluster is located at a water depth of greater than 2,000m, is the deepest offshore gas field in Asia, and is expected to reach plateau gas production of about 12.9mn cu/m per day in 2021.

Mukesh Ambani, Chairman and Managing Director of Reliance Industries Limited, commented, “We are proud of our partnership with bp that combines our expertise in commissioning gas projects expeditiously, under some of the most challenging geographical and weather conditions. This is a significant milestone in India's energy landscape, for a cleaner and greener gas-based economy. Through our deep-water infrastructure in the Krishna Godavari basin we expect to produce gas and meet the growing clean energy requirements of the nation.”

bp Chief Executive, Bernard Looney, added, “This start-up is another example of the possibility of our partnership with RIL, bringing the best of both companies to help meet India’s rapidly expanding energy needs. Growing India’s own production of cleaner-burning gas to meet a significant portion of its energy demand, these three new KG D6 projects will support the country’s drive to shape and improve its future energy mix.”

Together the R Cluster and Satellite Cluster are expected to produce about 20% of India’s current gas production. The third KG D6 development, MJ, is expected to come onstream towards the latter half of 2022.

• Region: North Sea
• Date: Apr, 2021

Archer Limited has signed an offer letter with Moreld laying out principle terms to purchase 100% of the shares in DeepWell AS (DeepWell).

DeepWell is a leading Norwegian well intervention company established in 2004 that is focused on mechanical wireline and cased hole logging services. Headquartered in Avaldsnes, Norway, DeepWell had approximately 200 employees and a revenue of NOK355mn in 2020.

Starting from 1 May 2021, Archer will also take over the Equinor wireline services scope from DeepWell, which was awarded in 2018. The light well intervention services for Equinor were to be completed by the AKOFS Seafarer together with Welltec, and included the provision of all wireline and basic logging services, together with operational support and crews.

Archer's CEO, Dag Skindlo, commented, “An acquisition of DeepWell would secure Archer’s access to a modern fleet of electric wireline units, as well as enable participation in the vessel-based light well intervention market. Strengthening our equipment fleet, broadening our low carbon/low emission solutions and continuing our track record for service quality are all key aspects of our strategy on the NCS. We are impressed by DeepWell’s team and look forward to continuing this process with them.”

The contemplated transaction is subject to due diligence, negotiation of the transaction documentation, closing conditions and regulatory approvals.

Archer’s North Sea expansion

The addition of DeepWell is further evidence of Archer’s formidable performance in the North Sea as it continues to expand operations and offerings in the region. The company continues to pursue new technology and digital solutions for well simulations and remote support in order to enhance efficiency and target reducing their carbon footprint.

Additionally, in April 2021, the company secured a long-term frame agreement with ConocoPhillips for the provision of wireline services on the Norwegian Continental Shelf. According to their release, this makes Archer the largest mechanical intervention company on the Shelf, with an estimated total contract back-log of NOK3.5bn.

• Region: All
• Date: Apr, 2021

Ardyne, an Aberdeen and Norway-based fishing, milling and casing recovery provider, has announced a strategic alliance with Dynasty Energy Services (Dynasty), a leader in specialised fishing services and plug and abandonment (P&A), to deliver enhanced P&A services around the world.

The exclusive partnership will enable easier access to leading world-class downhole technologies from both companies to deliver major cost and time efficiencies for P&A operations. As part of the agreement, Ardyne’s US team of five people will transfer to Dynasty, ensuring continuity from employees experienced in running Ardyne equipment over the last three years in US onshore and offshore applications.

Worldwide service

The alliance broadens Dynasty’s market offering in the western Hemisphere, while also enhancing Ardyne’s technology offering in the North Sea and wider eastern Hemisphere. It also allows for increased efficiencies for clients in both western and eastern Hemisphere markets.

Alan Fairweather, CEO of Ardyne, commented, “The future of many oil and gas supply chain companies will depend on their ability to adapt to market conditions and to continue identifying opportunities to improve their offering by creating greater operational efficiencies.

“Our strategic alliance with Dynasty is not only exciting for Ardyne, it also presents a model for other companies of a similar size to strengthen their existing technology portfolio and deliver a more robust global offering to clients.”

The alliance’s offerings

Ardyne will bring to the table its systems for casing recovery which save rig time and can provide solutions to challenging operations. The company’s Casing Recovery Toolbox offers flexibility and functionality to optimise operations and quickly adapt to unexpected circumstances.

Ardyne’s TRIDENT system, an integrated, single-trip casing cutting and pulling system has been developed to save rig time while offering precision and additional functionality is also on offer. Additionally, the TITAN system provides power downhole, enabling repeatable, on demand casing cutting and jacking capability in a single trip – it has been run successfully more than 1,200 times around the world.

From Dynasty, the unique Predator thru-casing section milling technology mitigates sustained pressure, providing a secure environment for barrier placement, saving costs through less rig time and multiple trips in the well. The Predator enables stabilised multiple string section milling without damaging outer casing strings. It allows real time decision-making, greater flexibility and contingency planning – especially valuable for P&A campaigns where the original well records are questionable or absent.

Combining Predator with the TRIDENT and TITAN systems enables multiple time saving solutions for P&A operations, with the benefit of being available from one service provider.

Alan Fairweather continued, “Forecasts for the decommissioning market are healthy but to maximise these opportunities will require greater innovation in technology and service provision. The exclusive partnership between Ardyne and Dynasty answers the need for a truly world-class full service fishing, milling and casing recovery offering for the global P&A sector.

“It reaffirms our ongoing commitment to the North Sea well-decom efficiency tool kit and opens our business up to greater opportunities in the locations where Dynasty is already established, including the Gulf of Mexico and US land.”

Keith Alexander, executive VP and chief operations officer of Dynasty Energy Services, added, “Under the partnership agreement, we will supply Ardyne’s technologies to support our services in the Western Hemisphere while Ardyne will supply our products along with their own in the Eastern Hemisphere.

“Combining our technologies to establish a stronger, holistic offering represents a win-win for both companies. However the ultimate winners are the clients who will benefit from easier access to our products to help them achieve greater P&A efficiencies.”

• Region: North Sea
• Date: Apr, 2021

Aker BP has completed the plugging of wells at the Valhall oilfield centre six years earlier than originally planned, saving more than NOK5bn.

Aker BP is the operator alongside partner Pandion of the Valhall oilfield which first saw oil flow in 1982. Since then, more than one bnboe have been produced from the area, which is three times more than originally expected.

In 2014, as a result of the decision to pursue a policy of modernisation rather than abandonment, Aker BP began a plugging campaign in order to revamp the field and keep it producing for the foreseeable future. Since that time, a total of 30 oil wells from the original drilling platform have been plugged in order to pursue the ambition of bringing up a further one bnboe from the field over the next forty years.

The first plugging campaign spanned 2014-2016 and was conducted by the Maersk Reacher rig. The next two campaigns, between 2017-2018 and 2020-2021, were carried out by the Maersk Invincible drilling rig, the departure of which last week marks the end of plugging operations for the field.

These campaigns were a roaring success as Aker BP have reported that no serious incidents were incurred during the work and that they were carried out in a total of four years, at a cost of NOK10.1bn, as opposed to original estimations of 10 years and NOK15.5bn.

Tommy Sigmundstad, SVP Drilling and Wells in Aker BP, commented, “The work to plug the wells has been a success through three major campaigns. The plugging has been carried out safely and efficiently. We have an unrelenting focus on improvement, and that has paid off in shorter operation times and reduced costs. Our alliance partner Maersk Drilling has been a key factor in all the campaigns. I am incredibly proud of the work delivered by teams across all companies both offshore and onshore.”

Alongside the plugging operations there has been a number of decommissioning activities carried out and planned. The QP accommodation platform was removed in the summer of 2019 by the catamaran crane vessel, Pioneering Spirit, and over the course of the next few years the original drilling platform and process platform will be removed along with the replacement of the original Hod wellhead platform (south of the Valhall field).

Utilising the latest technology

Wherever possible, Aker BP made use of the latest technology in order to optimise their operations.

Martin Straume, Chief Engineer for Well Plugging and Abandonment at Aker Bp, said, “Section milling of cemented casing has been carried out inside larger casing. We have done this to verify that well barriers are in place on the outside of the conductor. This means that we have avoided having to mill or pull entire sections of casing from the surface and down to the relevant depth. This represents up to several weeks of time saved per well, and is an enormous improvement in the plugging work.”

For the first time ever worldwide, Aker BP along with Halliburton and Maersk Drilling, conducted fully automated cementing operations from land, taking place from Aker BP’s offices in Stavanger. The technology increases efficiency, reduces costs and lowers HSE risk.

In addition, the top section of the old Valhall wells have been plugged using bismuth technology, an innovation conceived by BiSN to solve the challenge of potential methane leaks from old wells, and results in lower CO2 emissions compared with cement.

For the future

At the end of 2019, the first oil flowed from Valhall Flank West. As of March 2021, a new Hod platform is nearing completion at Aker Solutions’ yard in Verdal. The concept, implementation model and organisation for the Hod project were copied from Valhall Flank West. The planned production start for Hod is in Q1 2022, and recoverable reserves are estimated at around 40mnboe. Aker BP has also now embarked upon studies for a new central platform on Valhall, which will ensure production capacity for future volumes in the area.

• Region: Latin America
• Date: Apr, 2021

Karoon Energy Ltd has contracted the Maersk Developer rig, operated by Maersk Drilling, for the 2022 Baúna workover campaign with the option to retain the rig for the potential development of the Patola field, located adjacent to Baúna within the BMS-40 Production Licence, and drilling of a control well on the nearby Neon light oil discovery.

The rig, currently located in the Caribbean, will mobilise to Baúna following the completion of its present drilling programme and is expected to arrive in Brazil in the first half of 2022. The value of the contract is approximately US$34mn, including rig modifications and a mobilisation fee.

Baúna

For the Baúna well workover campaign, the rig will target an increase in production of 5-10kbopd by replacing the downhole pumps in two wells, installing a gas lift in one well and re-opening an oil zone in one final well.

Patola

The development of the Patola Field, which is located adjacent to the Baúna Field, involves the drilling and completion of two vertical wells which would be tied back to the Baúna floating production storage and offloading (FPSO) vessel, the Cidade de Itajaí. This development has the potential to produce more than 10kbopd and add incremental reserves to the Baúna asset. A final investment decision on Patola is expected to be taken in Q2 2021.

Neon

Karoon also holds the option to extend its contract with Maersk Drilling to drill a control well on the Neon light oil discovery, located approximately 60km North-East of Baúna. Subsurface and engineering studies are currently underway to assess whether this is a viable option.

Maersk Drilling in demand

Karoon Energy’s Chief Executive Officer and Managing Director, Julian Fowles, commented, “We are delighted to have signed this contract with Maersk Drilling, a global leader in offshore drilling, with one of the youngest and most advanced rig fleets in the industry. The contract marks another significant milestone in the evolution of Karoon into a substantial production and development company with material near term growth potential.”

“The arrival of the Maersk Developer rig will enable Karoon to implement a workover programme at Baúna, which is expected to add materially to our production, and is an important step in getting to a final investment decision (FID) for the Patola Development. Karoon also retains flexibility under the contracts with Maersk Drilling to drill the Neon control well.”

“The Karoon team looks forward to working closely with Maersk Drilling to deliver the Baúna workover campaign safely and efficiently. The programme is expected to commence in the first half of 2022 and, subject to FID, activities on the potential Patola development would follow immediately after the workover campaign is complete,” concluded Fowles.

It appears that the services of Maersk Drilling are in high demand with the company receiving a number of high-profile contracts including an exploration contract for Aker BP offshore Norway, a similar contract offshore Gabon awarded by PC Gabon Upstream, and an agreement for a long term drilling campaign offshore Ghana with Tullow Oil. 

• Region: West Africa
• Date: Apr, 2021

The Phase II plug and abandonment (P&A) campaign of the Chinguetti Field offshore Mauritania, which was stalled due to Covid-19 complications, has seen the successful intervention and barrier placement on all 15 wells since its resumption with projected completion of the entire abandonment scope by the end of the year, according to Expro and PETRONAS.

The Phase II P&A campaign

Phase II of the P&A campaign on the PETRONAS-owned Chinguetti Field began in late 2019, carried out by Pacific Drilling LLC, who had commissioned the help of Expro to provide an Intervention Riser System (IRS) and associated surface support equipment to be deployed from the Pacific Drilling drillship, the Pacific Santa Ana.

The award to Expro included a range of services such as the subsea well access system, surface flowhead, umbilicals, topside control equipment and IWOCS (installation and workover control system) package. Expro would also provide an onshore project management team to support Pacific Drilling throughout the project planning and execution phases. For their part, over the course of the 2019 summer, Expro carried out system integration testing on the equipment before shipping and installing it on the Pacific Santa Ana in Las Palmas in October 2019.

Expro, in turn, requisitioned for the campaign the support of Worldwide Oilfield Machine (WOM) who were contracted to provision the subsea well access system and a technical support team. This formidable team were contracted to complete the Phase II P&A project in Mauritania, which would take an estimated 360 days.

Covid-19 stalls progress

By late 2019 the campaign was in full swing (with the abandonment of the first well completed in December) so that by the end of March, subsea well access had concluded on nine of the 15 wells. Of course, then the Covid-19 pandemic struck and operators and oilfield owners across the world were forced to stall projects and forego operations as they dealt with closed borders, new quarantine rules, social distancing and keeping their employees safe. Such was the case on the Chinguetti field, where a strong start to the campaign made at the beginning of 2020 was drawn to a sudden halt with PETRONAS, due to the enforcement of travel restrictions, forced to declare force majeure on its contract with Pacific Drilling effective on 29 March 2020. Subsequently, Pacific Drilling agreed to leave the rig on stand-by at 35% of its contractual day rate until March 2021 and on the 31 March made sail for Las Palmas.

Keith Allan, Global Sales Manager at Expro, spoke to Offshore Network to reveal the challenges that his company faced during this difficult time, and how the rig was eventually returned to Mauritanian waters. He commented, “The main challenge we faced at that time was around travelling and personnel. Although we were shutdown at the end of March we still had some personnel in West Africa for a few months and faced challenges getting them home due to all borders being closed.

“We also had to keep skeleton crews on the vessel throughout the pandemic to ensure all routine and preventative maintenance was carried out on the equipment. They continued to perform to extremely high standards considering the global situation that meant extended trip durations, isolation periods and everything else that went along with travelling during the pandemic. The team were a critical part of the success of this project, providing a seamless operational start up when operations resumed.”

Returning to Mauritania

As Mr. Allan alluded, eventually there was light at the end of the tunnel and on 23 December 2020 the Pacific Santa Ana departed Las Palmas to resume the campaign in Africa. Since operations started up again in January, the subsea well access operations have been carried out effectively and efficiently and Allan proudly reported that as of 4 April the remaining six wells had been successfully intervened and Expro’s equipment offloaded.

Mr. Allan continued, “After the pandemic the six wells were challenging with regards to personnel movement, however all equipment and personnel continued to perform to an extremely high standard. One of the highlights for us was the ability to retrieve the Christmas trees with the IRS without requiring an additional run subsea. The IRS system’s compact nature combined with Pacific Drilling’s dual Derrick capabilities saved considerable rig time.

“This was Expro’s first venture into the IRS market therefore, we had to form new offshore and support teams to ensure we provided a quality service for the duration of the campaign. Our team’s skillsets were easily transferred to run this new system, and although we did employ experienced personnel, the crew was mainly made up of our people from the existing subsea product line.

“On a management level, it worked well. We had project managers onshore in Mauritania working from the Pacific Drilling offices to provide support for the operations duration," Mr Allan added.

Eyes set on the future

With the initial P&A of the 15 wells on Chinguetti Field the campaign has nearly reached its conclusion with some more work required to mop up the heavily lifting that has just been completed. PETRONAS, in a statement to Offshore Network, have confirmed “The campaign is progressing as planned and is projected to be completed by the end of this year.”

With vaccine distribution picking up speed across the globe and with the industry continuing to show the resilience and ability to work round the restrictions whilst maintaining the safety of their employees (as this campaign showed), there seems little reason to doubt this projection.

For Expro’s part, aside from some equipment remaining onboard for operations in a month or two, their role has been played to fruition and has marked a successful venture, which has overcome some serious challenges in the process.

As Mr. Allan concluded, “This was our first venture into the intervention riser system market, and we were able to carry out the campaign with no non-productive time (NPT) incurred. From an Expro point of view this has been a very successful project and something we are very proud and grateful to have played our part in. The success of this project has led to another contract award for a client in Australia, for a very similar scope of work and will commence in early 2022 once the equipment has completed a maintenance campaign in preparation for the work.