Latest News

• Region: North Sea
• Topics: Decommissioning
• Date: July, 2021

Following an initial agreement between the two companies in 2018, Equinor and Ardyne, a specialist downhole technology and services company for reducing rig time on well abandonment, slot recovery, workover, exploration and P&A operations have agreed a second joint industry project (JIP) to develop a unique well decommissioning technology to reduce the economic and environmental impacts of slot recovery and well decommissioning operations.

The UK£1mn project has been jointly funded by Equinor and Ardyne. Ardyne will manage all engineering, project management and onsite rig qualification testing before deployment for field trials.

TITAN RS

TITAN RS, which will be ready for commercialisation in 12 months, combines Ardyne’s field proven bottom hole assembly (BHA) systems with the new resonance tool to aid casing recovery by using resonance to reduce the pulling force required to free stuck casing. Successful trial wells have been completed recovering casing encased in settled solids.

The system uses the novel and highly effective application of resonance or vibration technology to allow longer sections to be pulled more quickly from settled material in the well. Ardyne has proved resonance to be highly effective in loosening settled material surrounding the casing, with an approximate 30% reduction in pull force required. The vibrations remain isolated downhole and are not transferred to the rig floor.

Compared to conventional rig systems, TITAN RS can provide up to 40% time efficiency savings for well abandonment, decommissioning and brownfield slot recovery projects through fewer runs and time downhole, with a resultant reduction in carbon emissions due to less rig time. The additional functionality means well clean up can be achieved as part of the recovery process without the need for additional trips in the well.

Ardyne has calculated that, when considering a single well scenario, an average rig time saving of more than 78 hours can be achieved. This would equal 136 tonnes of CO2 avoided, 156.8 MW hours of electricity and 13,807 gallons of diesel.

Alan Fairweather, CEO of Ardyne, commented, “The process is proven. The ability to cut days off existing processes through the innovative use of resonance is compelling at a time when the industry is seeking to maximise efficiencies at every opportunity. The environmental benefits of reduced carbon emissions through less time required on site are clear.”

“Equinor has already identified wells offshore Norway for the commercial deployment of TITAN RS next year. We look forward to providing them with a unique and industry-leading method to reduce operational costs and carbon emissions.”

Pål V. Hemmingsen, Task Leader Low-cost P&A Equinor, added, “The benefits of TITAN RS match our ambitions to shape the future of energy. We have been impressed with Ardyne’s unique application of resonance as a force for good in reducing project time and carbon output associated with P&A and slot recovery operations. We look forward to full commercialisation of the system from this latest JIP with the company.”

• Region: North Sea
• Topics: Decommissioning
• Date: July, 2021

The UK Oil and Gas Authority (OGA) has published a new cost estimate for offshore oil and gas decommissioning in the UK Continental Shelf (UKCS), suggesting that the total cost of decommissioning has reduced, spelling good news for both the industry and the Exchequer.

The report showed that the total cost of decommissioning UKCS offshore oil and gas infrastructure has reduced to UK£46bn, which is a projected saving of nearly UK£14bn. This marks steady progress towards the US£39bn by end-2022 target called for in the 2017 report.

Behind the decline

The UK£2bn reduction in the 2021 estimate is the result of continuous improvement and reductions in well decommissioning costs, driven by reductions in subsea P&A costs, cost estimating uncertainty and associated cost risk.

Expenditure in 2020 was impacted by Covid-19 and the low commodity price, contributing to a continuation of a plateau in the rate of cost reduction reported last year. While short-term forecasts show a recovery from this slowdown, commercial transformation remains key to meeting the cost reduction target.

There are positive signs that operators are embracing lessons learned from across the industry as well as embedding a culture of continuous improvement and setting ambitious best in class performance targets. This is helping drive the downward cost trajectory and, more will be needed to meet the target. At the same time however there remain some real inconsistencies in cost performance, reducing the overall improvement of the basin.

The majority of decommissioning cost is forecast to be incurred over the coming two decades, and the window of opportunity to identify and embed the necessary changes to drive the next step change in cost efficient decommissioning is immediate.

Achieving the cost reduction target

The OGA’s updated Decommissioning Strategy sets out the commercial transformation and strategic objectives required to deliver cost efficiency and achieve the UKCS cost reduction target of greater than 35%.

The 2021 Estimate notes that there are a number of opportunities to bring about further cost reductions, but it also highlights risks to continuing to bring down costs.

An average annual cost reduction of 6% has been delivered over the past four years. If this average is maintained, the 35% target remains achievable by end-2022.

• Region: North Sea
• Date: July, 2021

Equinor Energy has opted to add additional well intervention work to the previously agreed work scope for the low-emission jack-up rig Maersk Intrepid at the Martin Linge field offshore Norway.

Maersk Intrepid is an ultra-harsh environment CJ70 jack-up rig, designed for year-round operations in the North Sea and featuring hybrid, low-emission upgrades. It was delivered in 2014 and is currently operating at Martin Linge for Equinor. The rig was initially contracted by Equinor for both drilling and accommodation activities and its scope in the region has been continually extended as the field has been developed.

Of the latest contract extension, the firm value is approximately US$10.5mn, including integrated services but excluding potential performance bonuses. The added well intervention scope has a firm duration of 31 days, which means that the rig is now contracted until February 2022.

The contract extension is entered under the Master Framework Agreement between Equinor and Maersk Drilling, in which the parties have committed to collaborate on technology advancements and further initiatives to limit greenhouse gas emissions. The contract with Equinor Energy AS contains a performance bonus scheme based on rewarding reduced CO2 and NOx emissions.

• Region: Asia Pacific
• Date: July, 2021

At the virtual Offshore Well Intervention Asia Pacific Conference, an expert panel discussed how a growing emphasis on collaboration is complementing the shift to integrated services which is unlocking value for both operators and service providers.

Commenting on the rise in integrated services, Scott Deacon, Subsea Intervention Lead, Baker Hughes, opened the session by stating, “This is a growing area in the light well intervention space and it is also growing in the plug and abandonment (P&A) space as well. To have integrated solutions allows us to collaborate and support each other and brings cost effective and efficient solutions for operators.”

Chin Siang Tan, Senior Services Manager at Baker Hughes, added, “When we go into discussions with operators, they are much more open to the idea of us putting things together in a customised package and it is a very wide range of offers we are talking about now. Not just hardware but things like digital, software, remote surveillance etc are really striking interest in the conversation with operators now.”

“The scope of these integrated services is not just defined by operators but as a service contractor we have a responsibility to integrate and support not just within ourselves but outside our capabilities. Working with key subcontractors well help provide a bigger range of coverage and exercise the flexibility to customise solutions and provide the best project value for operators.”

Ankesh Nagar, lead engineer Petroleum Engineering & Surface facility North East India, Cair Oil & Gas, said, “Looking at a decade of our discrete services we realised there were some slippages on key contracts and projects which was ultimately due to some discrete contracts unable to deliver in the right spirit of the project. We as a group thought that when we moved into integrated solutions for both OPEX and CAPEX we would be able to take care of that aspect and improve on delivery. This is exactly what we saw when we took this step from 2015 onwards. Now we have multiple, regional, integrated service contracts for drilling as well as drilling and testing integrated services. We have found that even if you have projects over large areas you can still manage the delivery of them with leaner teams and achieve objectives of your business plans.”

Muhamad Zaki Amir Hussein, Well Intervention Specialist, Petronas MPM, noted that while it can be more messy for smaller providers to merge with others in order to offer these integrated services, generally the advantages far outweigh the associated challenges. He said, “For services providers this can align and focus your resources rather than having separate businesses developed for different service lines and having to manage separate contracts and performance levels. Having a single contract is more efficient and gives them more room to work in terms of economic of scale.”

Collaboration

The growing popularity of integrated services, combined with the Covid-19 restricted climate, has put a much greater emphasis on collaboration, with most service providers and operators now considering this a far greater part of their business model.

Deacon said, “Collaboration has been highlighted as the way forward and I think it is key for industry especially through the times we have just had. Service providers need to work together, operators need to work together. By looking outside of the business you can utilise other solutions which may be the best solution for the operator.”

Commenting on how his company has expanded this aspect, Nagar said, “We do an annual workshop with not only the service companies who have done work with us but also discrete and more niche services present as well. Then, when we project a need for a solution, there is already a good networking platform for these niche companies to showcase their potential so they can ultimately become part of the integrated service solution. Since our objective is to get a good quality output it is important to ensure there is good collaboration not just between us but also on their end as well. At the end of the day good communication and good collaboration equals good delivery of projects.”

Zaki added, “I agree there are great opportunities for smaller service providers with standalone solutions to learn through collaboration. There is great potential for syndication, experience and resource sharing across these service providers via collaboration for integrated solutions. As for collaboration among operators, there are more opportunities for this especially for bigger packages like workover and subsea work where mobilisation costs are high.”

“Bigger mobilisation and higher spread rates with subsea and workover packages require more economic of scale. Hence we try to find synergies and encourage collaboration across operators for this in the form of joint tenders or farming into an existing, awarded contract.”

To view the full session, follow the link below:
https://www.youtube.com/watch?v=1mPcYhTsBfE

• Region: Asia Pacific
• Date: July, 2021

At the Offshore Well Intervention Asia Pacific Conference attention turned to Indonesia as representatives from Pertamina Hulu Mahakam, Harbour Energy and TGT Diagnostics discussed the market trends in the region and what best practices and new technologies are being considered to optimise campaigns.

Sakti Dwitama, Head of Wells Studies at Pertamina Hulu Mahakam, stated that in Mahakam the well intervention business was very heavy. Across the more than 2,000 producing wells the company maintains around 5,000 operations are carried out each year with around thirty units (be that coil tubing, E-line, slickline, etc) being used on a daily basis. Yet this market is not without its challenges. Most obviously, as all panellists agreed, was the disruption caused by the Covid-19 pandemic which has caused immense logistical issues for mobilising teams to safely perform well intervention operations. As Hubert Menard, Asia Pacific Business Manager at TGT Diagnostics, added, this has been problematic for operators and service companies alike and has required some real forward thinking in terms of resource management to accommodate for quarantining etc.

The other major challenge has been the economic situation in Indonesia where the low oil price (although it is returning) and poor exchange rates has required some frugal planning from operators. The Indonesian government, in order to boost the economy and wean the country off of its reliance on exported oil has targeted the production of 700,000 barrels of oil per day for this year 2021 (up from the current production figure close to 700,000) to push on to 1,000,000 by 2030. This will be a tough task and the panellists discussed the role of well intervention within this.

Sakti said, “In a way I see this as an opportunity for well intervention. In Mahakam there has been a steep decline in production, especially gas, and so there will be an increase in well intervention activities in order to achieve the national objective. We also want to get more efficient and to optimise this and we are seeing more and more rig activities getting taken over by rigless vessels.”

“However, this decline in production will not be stabilised if we only rely on existing wells. So while we do intervention to maintain a smooth baseline we need to balance it with the development of new wells. Last year we drilled about 300 new wells across the nation, to achieve the national target this year we are aiming to drill about 600. This will be maintained throughout the next few years so that we aim to be drilling around 1,000 wells per year.”

Athur Simatupang, Well Service Engineer at Harbour Energy agreed with this sentiment. At Harbour Energy, he noted, the main goal is to maintain gas production and by utilising intervention methods such as acidisation, perforation etc they hope to increase and maintain the gas production from their fields and help the government reach its target. He also noted intervention strategies were of more importance due to the increasing costs associated with drilling new wells. Companies in Indonesia are having to look to deeper waters to explore and develop new reservoirs which is much more challenging and requires more expensive equipment. While his company is looking to drill new wells in order to increase production, well intervention is being used to sustain and maintain it.

Data Management

In order to stay on top of which wells require production enhancement, precise and effective data acquisition and data management is key. As Menard noted, “The digital transformation is something that every operator and service provider needs to go through even though each has different objectives and initiatives relating to this.”

Sakti noted that in his company an in-house digitalisation platform (in use since 2007) captures all the historical data acquired from assets and allows them to get a better understanding of their wells in order to optimise and more efficiently manage their operations. Athur added that one of the most important uses of this data for his company was to allow them to manage, coordinate and plan the activities of all departments more effectively, so they could identify shared targets and strategies. In an age where making the most of resources is paramount, ensuring all departments are working together in this way can achieve substantial cost savings for the company.

In order to acquire this data, the panellists noted a growing trend of moving away from E-line operations, with many companies instead relying on other methods such as slickline. While doing so does not allow for real time data to be acquired, it has major benefits in regards to mobilisation and potential cost savings.

Menard noted that E-line has a much bigger footprint and unless urgent real-time data acquisition was required, in his companies experience it is often much more fruitful to use other methods such as slickline which requires much less equipment and is much lighter. Because of these advantages to ease of mobilisation, it can be a much better option especially for smaller platforms. Additionally slickline is often needed anyway to perform jobs such as removing safety valves etc and bringing in E-line would most add another logistical problem if another crew was required.

New technology

After touching upon digitalisation the panellists moved onto other new technology trends that are shaping the well intervention industry. Sakti bridged the gap to data by noting that the advancements of AI combined with big data will push companies to be much more efficient and could optimise campaigns through things such as predictive analytics. There are also new solutions emerging in the realm of sand control, a “common enemy” in Indonesia, which would allow operators to move away from traditional methods such as gravel packs which are becoming less economically suitable –especially for marginal wells.

All the panellists stressed their companies were not afraid to utilise new technology and insisted that their doors were open for new viable ideas which could optimise their operations. Sakti said, “In Mahakam we are open to trying out new technologies and there are plenty of new products and techniques being implemented and trialled on our wells. The first step is to get to know each other, then we can have a tech day or forum to see what you have in your toolbox. From there we can discuss how to move forward in more detail, perhaps offer a scenario and understand how this technology will help and what benefit we can gain.”

Athur added, “Every year we do a new tech presentation for all out contractors but, not waiting for that, our door is always open and you may contact us directly. Of course in the Indonesian market everything is about low price but we are happy to have a discussion to see if we can insert the product into our applications.”

To listen to the full session, follow the link below:
https://www.youtube.com/watch?v=KpZeA629gtU

• Region: Australia
• Date: July, 2021

ICON Engineering, an oilfield service company, and IK-Group, a supplier of specialist products and services for subsea and topside pipe and pipelines, have formed a strategic alliance to offer operators repair, decommissioning intervention services to the Australian offshore market.

The innovative provision of often bespoke solutions to offshore engineering problems was a common factor that led to the alliance. This partnership will combine IK-Group’s 30 year experience working in emergency repairs for offshore subsea equipment as well as ICON’s expertise installing and servicing offshore platforms, for which the company received an engineering award from the British Government.

IK-Group COO, Adrian Gamman, said, “With ICON’s local presence and IK’s track record, we believe this agreement will suit the Australian market very well. ICON’s head office is located in Perth WA, which will enable ICON to provide IK-Group’s solutions to the local market with a much quicker response time and a better understanding of the local market.”

“Specifically, this will be hugely beneficial to the end client when working on fast track deployment of emergency repairs that are synonymous with IK-Group. These are exciting times, and we are looking forward to growing this relationship in the years to come,” Gamman added.

David Field, ICON Managing Director, commented, "ICON and IK-Group have very similar innovative cultures. Our respective, and complimentary, product and services lines have all evolved from solving technically challenging and real problems, often when there simply isn't a solution anywhere.”

“At our respective Company's cores are very capable technical and management teams, experienced with execution in the field, and the proven ability to respond quickly.

“With Covid-19 restricting travel it makes a lot of sense for the two companies to collaborate by sharing our service offerings on either side of the planet. Nothing beats face to face meetings with Clients; the collaboration means there is a way to meet face to face to understand the problem and develop solutions using our combined technical horsepower.”

• Region: North Sea
• Date: July, 2021

A/S Norske Shell has utilised Kongsberg Digital’s digital twin solution Kognitwin Energy to create a virtual representation of their Ormen Lange deepwater gas field which was released to users last month.

Feeding into the onshore digital twin developed at Nyhamna gas processing facility, the two will be combined to become the first ever fully integrated reservoir to market digital twin.

In October 2019, Norske Shell collaborated with Kongsberg Digital to operationalise an ‘asset of the future’ through a partnership development of the Nyhamna Dynamic Digital Twin, using Kongsberg Digital’s Kognitwin Energy solution. By the end of the year the solution was operational and since January 2020 the Nyhamna Dynamic Digital Twin has been evolving continuously through monthly product releases, focusing on safe, effective and integrated work processes and the optimisation of production and energy use. With Nyhamna having paved the way, the decision was made to expand the collaboration with another digital twin of the related Ormen Lange deepwater gas field, which feeds gas to Nyhamna.

Ormen Lange

Hege Skryseth, President of Kongsberg Digital and EVP Kongsberg, said, “With Ormen Lange, we are very proud to have been awarded the contract for the development of a second digital twin for Norske Shell. This is a direct result of our successful collaboration around the Nyhamna dynamic digital twin. We would particularly like to highlight a strong core product, Kognitwin Energy, rapid deployments, and fast time to value as unique differentiators in this ongoing project. Now, we are eager to help Norske Shell realise the full potential of their assets through integration of these two digital twins.”

The first version of the Ormen Lange digital twin comprises primarily data integrations and visualisation of subsea 3D models including production and MEG pipelines, well surface locations and well-bore paths, seabed bathymetry data detailed around the production templates, built documentation and drawings, real time data from DCS and PI and much more. For disciplines and teams across the initial Ormen Lange user base the twin provides unified data for everyone to access across the same work surface.

Rolf Einar Sæter, Digitalisation Manager in Norske Shell, commented, “Digital twins are technology for people. The partnership model, combining Kongsberg Digital’s digital capabilities with our own employee’s expertise in the operations and maintenance domain, has been very effective in delivering use cases that let our teams to collaborate better and become more effective. This in turn enable us to save costs and optimise production whilst improving safety and environmental impact.”

• Region: Australia
• Topics: Decommissioning
• Date: July, 2021

The Government of Australia has taken the next step in its plans to remove the Northern Endeavour FPSO facility by releasing a Request for Expressions of Interest (REOI) for Phase 1 decommissioning works, in spite of the debate that continues to rage over the decommissioning levy.

In 2019, the 170,000 bpd Northern Endeavour FPSO was shut down by the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) after an immediate threat to health and safety was found at the facility.

The task of decommissioning the infrastructure fell to owners Northern Oil & Gas Australia (NOGA) but, in late 2019 the company went into liquidation and so the facility has been abandoned, with the national government forced to maintain the facility. At the end of 2020, the government decided it was finally time to push the facility into retirement, announcing it would take on responsibility to decommission the FPSO and all related infrastructure.

In order to cover the estimated cost of US$200mn for this task, the Australian government issued a levy to the oil and gas industry to help foot the bill, which was met with disproval from many organisations such as the Australian Petroleum Production and Exploration Association (APPEA), ExxonMobil and Chevron.

Despite this, the Resources, Water and Northern Australia Minister, Keith Pitt, is pressing ahead and said that the release of the REOI was the next step in the process to disconnect and decommission the Northern Endeavour from oilfields in the Timor Sea.

A REOI from the Department of Industry, Science, Energy and Resources has been published on AusTender, inviting qualified and experienced organisations to demonstrate their capability and capacity to undertake the Phase 1 works to decommission and disconnect the FPSO from the related subsea equipment.

“The Australian Government committed to decommission the Northern Endeavour last December to remove potential future risks to the environment,” Pitt commented. “The department intends to use this process to shortlist organisations for a more detailed request for proposal stage later in the year.”

Responses to the REOI are due before 2:00pm Australian Eastern Standard Time, 29 July 2021.

• Region: All
• Topics: Decommissioning
• Date: July, 2021

Global engineering company Aker Solutions has signed a letter of intent (LOI) with AF Gruppen, a leading contracting and industrial group, to merge the two companies’ existing offshore decommissioning operations into a 50/50 owned company.

With the signing of the letter, the companies plan to create a leading global player for environmentally friendly recycling of offshore assets. By joining and focusing their assets, the companies hope to unleash the decommissioning potential across the globe and make a significant contribution towards a sustainable and green transition of the offshore sector.

Kjetel Digre, CEO of Aker Solutions commented, "By combining Aker Solutions’ offshore, engineering and project execution capabilities with AF Gruppen’s decommissioning and construction capabilities, we aim to increase customer efficiency throughout the decommissioning process and maximise the total recycling potential.”

“The company will be uniquely positioned to offer integrated end-to-end services from well plug and abandonment to planning, removal, dismantling and recycling at its own environmental base. Sustainability and circular economy ambitions will be key focus areas for the new entity, and we see increased activity in the market for decommissioning and recycling moving forward.”

Amund Tøftum, CEO of AF Gruppen, added, "Our ambition is to establish a unique recycling player, positioned to offer a total decommissioning solution for the global offshore recycling market. The two parties have complementary strengths and capabilities, with potential to build a global offshore recycling powerhouse. Furthermore, the new entity will deliver on the green, circular ambitions outlined in the UN’s sustainable development goals.”

The two companies represent unmatched and complementary engineering and construction capabilities, offshore and onshore. Jointly, the two units brings extensive capabilities in running large-scale offshore projects, lifecycle and value chain competence and a broad global portfolio of customers and projects. The joint company will have an order backlog of approximately NOK2.5bn.

The transaction is expected to be completed during the second half of 2021 and is subject to due diligence and regulatory approvals by the Norwegian Competition Authorities (NCA).

Achieving a circular economy

Goal 12 in the UN’s sustainable development goals (SDG) is to ensure sustainable consumption and production patterns, in an urgent need to end our reliance on raw materials and achieve a circular economy. These goals will be met by viewing old structures as material banks of dynamic and valuable resources, rather than fixed and final objects. The recycling of steel from decommissioned oil platforms represents a significant contribution to reducing greenhouse gas emissions compared with ordinary steel production in this way and will help to achieve this goal of the UN.

The unit aims to recycle as much of the materials from the decommissioned offshore platforms as possible. Reusing steel results in 70% less CO2 emissions than ore-based production, which corresponds to an emission reduction of 1kg CO2 per kilo of recycled steel. In 2020, AF Offshore Decom, a specialised contractor within AF Gruppen, demolished and facilitated the recycling of approximately 22,000 metric tons of steel, corresponding to a reduction of alternative CO2 emissions of 22,000 metric tons.

The decommissioning market

The offshore decommissioning market has a vast untapped global potential, with approximately 10,000 operational platforms. In the North Sea alone there is more than 900,000 metric tons of top deck expected to be removed during the period from 2020 to 2029. Based on today’s current annual decommissioning spend, it implies that it will take operators approximately 100 years to deplete liabilities for current assets. Thus, a further ramp up of pace is necessary, leading to a positive contribution to the demand for this type of services.

• Region: Asia Pacific
• Date: July, 2021

On day three of OWI APAC, attention turned to optimising production enhancement strategies as host Sohan Harkesh Singh, Asset Performance Solution Commercial Manager – Asia, Schlumberger, was joined by representatives from EnQuest and South East Asia Hibiscus to consider the best way to capture value from this “low hanging fruit”.

As the panellists agreed it was critical to have an efficient workflow for any production enhancement programme, Khairul Riza bin Zainul Riza, Well Services Engineer, Hibiscus, took the opportunity to explain the process at his company whereupon they split intervention into two – routine and non-routine. The first, routine, is slickline only which is being worked 365 days a year. There is an overall plan of when work should be starting but it is updated as they go along when new opportunities are identified which can slot into the sequence. Such dynamic processes can help save time as if an opportunity to implement a solution can be identified with crew currently working on a remote jacket, turnaround will be much faster than if they need to return to it at a later date.

Non-routine, as Riza continued, is for more complex well entry and typically involves some sort of support vessel with a crane. This is for anything beyond slickline such as coil tubing. Planning is done far in advance (6-8 months) with opportunities continually identified for the following year.

Mohd Farid Mohd Talib, Wells Engineer, EnQuest, said that his company had an almost similar workflow to cater for most of the 362 strings in the Seligi field with OSV throughout the year where the team works in integrated systems between Subsurface, Ptech, Wells Team and also the Operation department. This process is started from a field reservoir workshop a year in advance to develop initial IWR target inventories by applying efficiency on online integrated system Well Request Forms (WRF). Farid noted it was vital to monitor large well inventories as much as possible to consider whether they were in a first time, routine, non-routine, easy to moderate, complex or very complex requirement of intervention. The company assesses what they can gain from intervening on categories of production enhancement/idle well recoveries (PE/IWR), data acquisition (DA) and also well integrity (WI) issues with the intention to protect the baseline of EnQuest within approved UEC (cost allocated) and overall chance of success (CoS) as well as justifying their well plan throughout the year to meet on the annual production KPI target.

Sohan added, “We have dedicated production enhancement workflows and we try to do this in an integrated fashion. We try to engage with the operator from the start to ensure there is alignment on delivery as this is very important and try to use digital technology where possible to help us deliver overall solutions much quicker. In some examples, digital workflows can fast track workflows by 90%.”

Production enhancement challenges

Turning to the challenges and inhibitors of production enhancement, Riza noted that in North Sabah, where some Hibiscus assets are located, one of the biggest difficulties is actually bad weather which comes round twice a year (mid and end). This can make activity planning extremely difficult with limited periods for operations. This is combined with the fact that resources must be shared with other departments internally, such as crew, living quarters, supply vessels etc. Such problems highlight the importance of dedicated and efficient workflows even more.

The panellists also noted that well intervention activities have been severely limited by the occurrence of oil price drops which can disrupt the economic planning. Farid said, “Right now it is not economical for us to have E-line at the moment so we are opting instead to optimise the services of the IIWR/IWS integrated contract for coil tubing and slickline. We have managed to use it to fulfil all our objectives without neglecting on company annual barrel gain KPI targets. With this we perform on our objectives to redo baselines, check on adhoc active well requirements, perform our yearly well intervention campaign for PE/IWR and DA, and also perform well repairs for WI, etc. This strategy has allowed EnQuest to achieve on its targets for top efficiency, fast turnaround and allows for cost optimisation to deplete remaining reserves.”

Riza agreed and added that Hibiscus has had to scale down plans quite a bit as well as deferring campaigns (such as a coil tubing from last year to this). His company, too, has noted that E-line is no longer economic and has instead turned to performing operations with memory tools and performing perforation jobs on slickline instead. Yet, despite this, they have encountered a fair bit of success with reworked campaigns, such as three fishing jobs which were successfully completed recently, two of the aforementioned perforation jobs and two saturation logging jobs. There is one more perforation job planned for this year after saturation logging results were received last year.

Best practices and new technology

Sohan switched the conversation by asking the panellists to explain the best practices for carrying out production enhancement, especially in the challenging times the industry is going through. For his part, he said, “Schlumberger is increasingly being more focused on the development of new digital technology as enablers for production enhancement. You may be familiar with the buzz word WPO [well portfolio optimiser] which we have designed to improve production enhancement workflows to reduce time take for data gathering to selecting & ranking well candidates. This allowed a client to reduce the time taken to rank their candidates from four months to two weeks.”

Sohan also focused on new technology providing real time surveillance, powerful analytics and more which allow for predictive insights to help make better, more informed decisions. Farid added that at EnQuest, they are always open to trying new technologies and opportunities to perform more efficient well operations as long as they are economically viable, before opting for workover or drilling options, and have sharing benefits to develop more knowledge between all parties involved. They encourage and challenge contractors to become the leaders of the job, sharing KPI achievements on subsurface proven alignments mechanisms and sharing their technical expertise with the EnQuest crew so that they can perform better on the solution in the future. EnQuest is also always looking forward in order to share their experience for proven and clear direction on integrated workflows (IIWR/IWS) and for technical solution sharing on new technology for man-made gas shut offs that have been planned for the first time in the world.

Riza said, “One thing we do well is achieve cost saving through sharing resources via integrated planning with other departments. When one of them needs an additional vessel (such as a supply vessel), we look at what campaigns everyone has going on to see if we can share it out so we each do not have to acquire one separately.”

“Also, early planning and preparation is critical. We plan 6-8 months in advance for heavier activities. That is key to achieving most of our targets. It allows us to communicate up front early our entire annual plan to contractors so that they can align their resources in a timely manner to our requirements. In that way no one is caught off guard.”

The panellists also touched upon other best practices such as adapting multi-skilled personnel. For instance, at Hibiscus a slickline equipment mechanic is routinely mobilised to service and check the slickline equipment offshore but now they are multi-skilled as a slickline assistant also so they can form part of the slickline operating team. Not only does this save value but also reduces the need for additional people to be mobilised, which is especially important during Covid-19.

To hear more from the panellists including further discussion on best practices and procurement models, follow the link below:
https://www.youtube.com/watch?v=QMZvLeiv5p4

• Region: North Sea
• Topics: Integrity
• Date: June, 2021

Speaking at the Virtual Offshore Well Intervention Europe Conference 2021, Bruce Trader, President of MADCON Corporation, guided an audience through his company’s Structural Composite Retrofit (SCR) process, developed to restore the structural integrity of conductors and well casings as well as providing long term corrosion protection.

Trader explained how the process was conceptualised after a major international oil and gas company requested a process to restore the integrity and provide long term corrosion production for their conductors and surface casings as they had been experiencing several years of less than optimal performance. The company had numerous conductors that all were suffering from severe corrosion and required an immediate solution.

For this to be a success, the company issued several key mandates which MADCON had to fulfil including:
-Restore the original design capacity
-Allow future work
-Minimal to zero hot work
-Long term corrosion protection
-Ease of installation in the splash zone
-Meeting regulators compliance
-No cofferdam required
-Fit within the existing conductor guides
-Conduct the work from vessels or the platform and not require a barge or rig
-Eliminate the need for future maintenance.

When the operator hired a third party engineering company to analyse and validate the method MADCON put forward, they assumed that there was no remaining conductor wall or inner string pipe capacity and that the composite section had to be designed to take the full axial and bending load.

Trader explained the basic SCR process which they followed to help the operator, which begins by, if the surface casing is not already grouted, grouting the surface casing annulus to a select elevation (in this case 2-3 metres below the water). This consists of installing a plug to isolate the annulus and putting on epoxy grout before finishing with cement grout all the way up to the wellhead (there is no need to grout to the mud line as the corrosion is not severe a couple of metres below the water). If there is a large length of unsupported casing a reinforcement cage made may be required before, in the final step, a fibreglass jacket is installed to be pumped full of epoxy grout from the bottom up.

As one of the key mandates was to install in splash zone, the materials were all lightweight, composite and easy to install. In more than thirty years of conducting these operations MADCON has recorded zero incidents for the divers involved.

In order to keep hot work (and by extension expense) down, MADCON also took pains to make the repair within the existing conductor guides. The platform had a tight space which posed a challenge but this was able to be overcome and today the company’s repairs only add 1-3 inch in overall diameter meaning they can perform repair work within most existing guides out there saving time, money and eliminating hot work. The company additionally captured more value by performing the work without the use of a rig or large barge as they are able to perform the repairs with relatively small vessels of opportunity or even the platform itself.

Summarising this job, Trader said, “We were able to achieve all the mandates stipulated by the operator including, once the repair was done, eliminating future maintenance so that 27 years (and counting) after the repair everything is still in perfect condition.”

Reliable performance

After gaining a formidable reputation for this kind of work, operators even began commissioning the company for wells that had corroded so much to the point where the surface casing had collapsed. But, as Trader demonstrated with a string of case studies to conclude the session, this was not an issue but something they have now come to specialise in.

For one well, for instance, prior inspection posted no abnormal operational conditions but an inspection from MADCON identified that in fact the well had in fact collapsed and had to be shut in. The company then dissected and removed some of the conductor pipe and identified that the conductor to surface casing was open at a certain elevation and, without anyone knowing, it had been slowly corroding the surface casing to the point that it failed. While supporting the well with casing jacks, the MADCON crew of 8 techicians were able to perform full structure repairs from the platform, from -3 to +20 metres, in just 12 days. Once done the operator was able to get his well back online and producing again.

Trader said, “This process can be modified to restore any capacity that the operator might need and we have been successfully using it to restore original design capacity and provide long term corrosion protection on hundreds of wells.”

• Region: Asia Pacific
• Date: June, 2021

Presenting in a virtual webinar, Bhargava Ram Gundemoni, 3M Global Solutions Specialist Ceramics & Glass, Ceramic Sand Screens, showcased how operators can enhance their production from marginal fields through the use of ceramic sand screens. Using a case study to highlight how an Operator in Asia achieved a 70% cost saving compared to chemical sand consolidation methods, Ram presented the technology and application detail.

Beginning the presentation, Ram stated that marginal fields can pose a variety of challenges to operators which can have disastrous economic and HSE consequences if not properly operated. For one of the field/assets in Asia, Operator A had to contend with low reserves, ranging from just 0.05BCF to 2BCF natural gas production per reservoir zone; high operational costs due to offshore and near shore delta locations; complex geography such as stacked thin-bed reservoirs and unconsolidated and poorly sorted sand distributions; and the fact that hotspotting erosion is often a high risk. Many of these are common challenges that operators must overcome, which they must do in a safe and cost-effective way. It is for this reason that selecting the right sand control completion is absolutely imperative.

Traditional Sand control

Operator A was struggling to achieve economic viability for their fields. Previously, it had used traditional methods of sand control for their marginal fields such as multi-zone single trip gravel packs, chemical sand consolidation, or metallic stand-alone screens. The operator had found that such approaches each had drawbacks relating to high cost (often related to additional rig time being required due to the increased complexity), HSE risks (especially using chemicals), loss of productivity before the reservoir life had been depleted, increased chance of hotspotting and difficulty achieving sand mapping due to wide reservoir sand facies. All these led to higher capex, longer payback times and generally lower returns.

Technology unlocks application scope through material change

To economically unlock marginal well production across the field, new sand control technological advancements needed to be considered. Operator A therefore selected the 3M ceramic sand control solution to enable a standardised field wide approach.

The solution featured a much simpler design with ceramic rings (with spacers on one face) stacked on top of each other to create v-shape gap openings to enable any particles stuck to be pushed into the tubing. The rings were stacked onto a base pipe with two end caps with a pin and box connection on each side which was then covered by a metallic shroud for protection during transportation and downhole running. This was a monobore completion approach which addressed the complex geography of heterogeneous reservoir sand properties by having one solution and was easily installed via a slickline rigless deployment. Ceramic parts were chosen due to their excellent corrosion and erosion resistant properties.

Across the field, 13 installations were implemented and all achieved sand-free production rates. Max production achieved was 4.4mmscfd with 36ft/s insitu velocity of gas (Vg) at perforation hole which was the reservoir production limitation compared to 13ft/s when using sand consolidation method in the past. Additionally, the operator reported the successful implementation of stand-alone screen application for volume shale (Vsh) greater than 35% with further deployments currently being made to address expansion of the application scope to Vsh less than 35%.

Operator A achieved a 70% cost saving compared to chemical sand consolidation methods. Further enabled simplified approach, optimising right through drilling to completion with lower capex, faster ROI and higher production rates achieved the fast and simple deployment (only five and a half days) enables the execution of a higher number of reservoirs per year, it was successfully proven to safely retain and control post frequent restart of wells and it addressed the challenge of erosion and hotspotting. Ram also noted that the solution met the full lifetime of each reservoir which, in these cases, ranged from six to nine months with no failure of the sand control.

Offshore Network took the opportunity to speak with Ram in order to understand this innovative technology in more detail:

Do any specialist personnel need to come out to deploy the solution or are you able to direct this?
It is a simple Stand-alone screen design which can be run like an industry Stand-Alone Screen deployment. 3M provides guidelines for handling and run-in hole (RIH), for the Operators and Service provider. 3M can support well on paper (WOP/IWOP) to onshore support as identified.

How compatible is the ceramic solution with different types of cables?
In terms of deployment, ceramic sand screen has already been successfully deployed on wireline, slickline, coil tubing and on a pipe. This offers operators flexibility and cost-effective approach in deployment to meet the operational and application needs.

Can you give some more details relating to the cost saving which can be achieved?
By using ceramic stand-alone screen deployment via slickline unit, Operator A mitigated the need of coil tubing, pumping of chemicals, time required for deployment and curing of chemicals. Operator A calculated this saving contributed 70% against the chemical sand consolidation methodology.

There are other cases globally, where operators have benefited from running 3M Ceramic Sand Screen as a stand-alone system which has demonstrated faster returns on investment to cover the costs. Ceramic sand screens offer an alternative downhole sand control methodology as a simple Stand-alone screen method, which enhances production improvement, operational simplicity and reduced HSE

How much this solution has been utilised in Asia and how has Covid-19 affected this?
This technology was first introduced in the field in 2010 and, since then, we have more than 110 deployments globally with the majority of them (more than 50%) in Asia.
Covid-19 really disrupted the market, with project sanctioning taking longer, and higher focus on cashflow.

Do you imagine this technology will become more widely utilised in the future?
Yes, we are confident that this technology is a “game changer” in the way operators control downhole sand, whilst enhances productivity. Maersk Oil stated, “This technology has the potential to completely change the way mechanical sand control screens are being developed.”

Additionally, Operator A said the technology was an “eye opener" (post deployments and production successes in multiple wells) to safely tackle and push boundaries of shallow sandy reservoir production in a challenging economical context. Foreseeing wider applications in near future subsurface sand control…”

To learn more about 3M Ceramic Sand Screens visit: https://www.3m.com/3M/en_US/oil-and-gas-us/ceramic-sand-screens/