The Decommissioning Insight 2021, published by OGUK, will set out plants for what could be the biggest marine removal programmes ever attempted.
OGUK has suggested that an estimated 1.2 million tonnes of disused oil and gas installations (ranging from massive rigs to well heads sitting on the seabed) are to be brought to shore for reuse, recycling and disposal in the coming decade. The report indicates that operators will spend an estimated UK£16.6bn on the decommissioning programme which will support thousands of jobs both fiercely and in the supply chain.
Around 95% of offshore material is typically already recycled but now the focus is moving more towards reuse ‒ where component parts, or even whole structures, can be redeployed for new purposes with minimal modifications.
Another key aim of the programme is to establish the UK as a centre of excellence for decommissioning which will set British companies and workers in high demand. Across 2020 and 2021, 234 wells, 21 platforms and 50,000 tonnes of other underwater structures were removed around the UK, highlighting the resilience of the industry even during the pandemic.
Joe Leask, OGUK’s Decommissioning Manager, commented, “Decommissioning is more than a great challenge. It’s also a huge opportunity for UK companies to show their engineering skills, powers of innovation and ability to compete on a global scale.
“OGUK’s 2021 Decommissioning Insight report shows that over the last five years the UK decommissioning industry has improved its efficiency and cut its costs by an estimated 23%. So, we have done better but I think we can still do a lot more. If operators work together to create larger projects where we get economies of scale, then we can safely drive costs down even more.
“Decommissioning is also a key part of the UK’s transition to low-carbon energy and its aim of reaching net zero by 2050. This is partly because the installations being removed tend to be older and so generate more emissions relative to the oil and gas they produce. But it is also because of the growing opportunities for reuse, repurposing and recycling. This is already becoming common with forgings, pipeline valves, turbines and electrical kit. In the future some assets could be repurposed for new uses such as offshore wind and permanent storage of carbon dioxide by pumping it deep under the seabed.”
“This is going to be an exciting ten years – there’s a huge amount of work to be done and with £16.6 billion to be spent, there will be many opportunities for UK companies and workers,” Leask concluded.
Expro has launched Galea, the world’s first fully autonomous well intervention system, designed to maximise production while reducing intervention costs, HSE risks and environmental impact.
Galea replaces larger, conventional and more labor-intensive wireline rig-ups for a range of slickline operations such as solids removal, plug setting/pulling and logging surveys. It can be configured in a variety of operating modes to suit a range of applications onshore and offshore.
Max Tseplic, Expro’s Vice-President of Well Intervention, explained, “Galea maximises production while reducing operational overheads by using an intelligent, autonomous system to perform a variety of slickline operations.
“Frequent, routine interventions typically involve significant manpower and equipment, which are costly. Planning these operations is often restricted by the availability of hardware and crew. The environmental impact of regular interventions, and the movement of vehicles and equipment, are also significant, as is the HSE risk to crew in travelling to and from well sites and performing operations.
“Galea eliminates these challenges by removing the movement of people and equipment to the well site for each intervention. Remote control and 24/7 monitoring reduce HSE risk and allow production to continue in inaccessible areas. The reduced environmental impact of using Galea helps asset managers comply with environmental regulations.”
In fully autonomous mode, Galea deploys a tool string into the well either at regular intervals or as defined by the well conditions. In semi-autonomous mode, Galea performs a pre-programmed intervention sequence, initiated locally or remotely. A small, self-contained intervention package permanently located at the well site eliminates the need for a wireline unit or truck.
In manual mode, Galea enables quick rig-up intervention compared to conventional operations. When not in use, the system occupies a fraction of the well site or deck-space required for a standard slickline winch unit and PCE package.
Galea also has several fail-safe features to ensure containment and eliminate potential wire-breaks during operations.
During an introductory session on well intervention in the Mediterranean at the Offshore Well Intervention Mediterranean 2021 conference, expert panelists came together to share their thoughts, discuss the advent of technologies and explore the challenges involved.
Moderator Scott Clayson, Commercial Manager at Baker Hughes, provided an introduction to the session by commenting that the market ranges with fields from Spain to Italy with some subsea fields dating back 20+ years. There are fields off the coast of North Africa, Bulgaria and Romania which have added subsea production and, in addition, there has been an increase focus in the eastern Mediterranean where the subsea fields are around 9-10 years old. “Importantly based on some of the available data we have seen the majority of wells in the Mediterranean appear to be in peak intervention years in terms of their life cycle.”
Daniel Petrone, Life of Field Solutions Manager at OneSubsea, said that to explain the well intervention scenario in the Mediterranean region, he would have to divide it into East and West. “In the West, the arrival of well intervention in Tunisia, Algeria and Spain has been marginal. There have been some interventions in the past but in terms of well counts and offshore activities, they are marginal,” he added.
He added that one of the areas that have seen more activity in the East is Libya. “It has some offshore fields. The activity is potentially there, and geopolitically apt too. There is definitely a significant market in that country,” Petrone remarked.
Speaking about rigs, he opined that Israel and Cyprus are relatively new areas, where intervention is just starting to pick up but it is still a new market. “Egypt, which has a good number of dry tree wells, has also seen a major development from companies in subsea interventions. In terms of wells, a significant market is gathering more attention in Egypt.”
From an architecture point of view, one can find a mix of all in this area. “Dry tree wells, platforms and drilling rigs can all be found here. There is a lack of intervention vessels in the East but geographically, it is more accessible,” he added.
Agreeing to Petrone’s views, Mohammed Omar, Subsea Completions and Workover Engineer at Rashpetco, said it is indeed quite a similar situation in these areas.
Voicing her opinion on the subject, Fiona Robertson, Senior Product Manager, Systems & Technology at Baker Hughes, said, “It is interesting to hear details about well intervention in the Mediterranean by splitting them into two halves. The western Mediterranean region is perhaps more developed. However, new companies have tried their luck on the eastern side too. The West might be heading towards a lesser intervention situation and focusing more on the plug and abandonment process. The majority of vessels in the East are rigs with very few light well interventions.”
Based on his experiences with offshore wells and fields in Egypt, Abdullah Moustafa Mohamed Hegazy, Senior Production Technologist, BAPETCO, noted that the challenges that arise during recompletion include data availability and formation damages.
Robertson said, “There has definitely been a consideration for future intervention work at the initial point. When we have drilling wells in the past and we are learning as we go forward. When the Macondo disaster happened, the BOP (blowout preventer) caused so many problems and yet we use it as a primary safety device. There is a lot of well safety that also comes in to the picture.”
While speaking about planned and unplanned interventions, Petrone said, “If you have some sort of monitoring, you can foresee if things are going wrong. Then you can transform your unplanned into planned intervention.”
Technology as the key
The panelists were all on the same page regarding their opinions on technology being vital for interventions and being helpful in the future. “It is important to go digital to understand early signs of something going wrong. One can monitor if something is deteriorating,” Petrone said, while adding that it is important to anaylse data as it helps plan interventions better and time them better too. “Especially, when it comes to removing people from offshore activities, potential, and financial gain, technology comes in handy. It won’t solve intervention problems, but if you are aware early on, you can save money and time before it gets worse,” he commented.
Abdullah Moustafa added, “The reason to adopt technology should be the time factor as it can help save time. Some technologies are not available in the Mediterranean but outside the region, they are commonly used. Mechanical interventions have proven to be effective but sometimes we can’t use them, especially when they are multiple zones.”
An environmental focus
Speaking about reducing carbon emissions, Abdullah Moustafa said, “We should try to minimise the amount of hydrocarbons released. This is one thing all companies should try to achieve. All companies need to transition to green energy, even the major oil companies in Egypt.”
Elaborating solutions for the carbon footprint problem, Robertson said, “If we use more light well interventions, it will reduce the carbon footprint as there is lesser fuel used, fewer individuals on board, and the operations are quicker. If we move away from rigs that could also help us reduce our carbon footprint.”
Adding his views to the issue, Petrone said, “The footprint of an intervention is lower than drilling a well. We are looking at decarbonising operations by making more electrical equipment, diesel powered ones, by removing people from offshore projects, and less flights which means less helicopter fuel to be burnt. In addition, if interventions are planned well, they can be completed quicker and will result in a much lesser carbon footprint.”
Pharos Energy plc, an independent oil and gas exploration and production company, has announced that the Hoang Long Joint Operating Company has successfully completed its 2021 TGT well intervention and development drilling campaign.
Ed Story, President and CEO of Pharos Energy, commented, "I am delighted to announce that the first phase of the infill development drilling programme in TGT has finished, with all four wells testing at rates in line with or ahead of pre-drill expectations. The campaign was completed ahead of schedule and under budget.
“The well intervention programme conducted earlier in the year also delivered rates above expectations. Together, these two operational campaigns have increased production capacity and will ultimately improve recovery from the field. They also support the further activity set out in the Full Field Development Plan designed to optimise field oil & gas recovery and a submission request for a five-year contract term extension.
The initial flow of the four development wells of 8,800 bopd exceeded the predicted combined initial oil rate of 5,650 bopd by 3,150 bopd.
Well interventions and a gas lift optimisation programme earlier in the year resulted in an initial TGT production gain of 3,200 bopd. The six wells with additional perforations showed a gain of 1,800 bopd, the four wells with water shut off gained 900 bopd and eight wells where demulsifier injection was applied gained 500 bopd.
The TGT field gross production rate on 17 November 2021 was 14,800 boepd, but would have been approximately 19,800 boepd without the impact of the compressor fault mentioned below.
The results of the drilling and intervention activity support additional opportunities as set out in the Full Field Development Plan (e.g. nine contingent wells and an extensive well intervention programme), which could support a TGT license extension request to December 2031.
The Hoang Long Operating Company Management Committee has also approved two additional TGT wells and 13 well interventions (ten firm additional perforations and three water shut-offs) in the budget for 2022 on 17 November 2021.
The New Zealand Ministry of Business, Innovation and Employment (MBIE) has entered into an agreement with Helix Offshore Services Limited, a subsidiary of Helix Energy Solutions Group, for the plugging and abandonment (P&A) of the wells in the Tui Oil Field.
This is part of Phase 3 of the Tui Oil Field decommissioning.
“Helix was awarded the contract after a competitive procurement process to select a supplier that met MBIE’s objectives of a robust technical solution, flexibility in timing, competitive pricing and a commitment to working with iwi and local stakeholders,” said MBIE Tui Project Director, Lloyd Williams.
“Helix is widely recognised internationally as one of the largest and most capable contractors for well intervention and abandonment, and we are looking forward to working with them to complete the final phase of the decommissioning."
“Helix’s proposed vessel to carry out the work, the Q7000, is a state-of-the-art unit which is optimised for well decommissioning and features specialised equipment required to complete the work safely and efficiently,” added Williams.
Wharehoka Wano, CEO of Te Kāhui o Taranaki Trust, remarked, “We are very pleased the project has secured a highly competent contractor for Phase 3. This gives us every confidence as Taranaki Iwi and the hapū of Ngāti Kahumate, Ngāti Tara, Ngāti Haupoto and Ngāti Tuhekerangi as kaitiaki, to fulfil and maintain our responsibility and obligation of ensuring the mouri of our environment and cultural resources are protected and enhanced for future generations.”
The disconnection and demobilisation of the FPSO Umuroa, the first phase of the decommissioning of the Tui Oil Field, was completed in May 2021. In October 2021 the contract for the second phase of the decommissioning process, the removal of the subsea infrastructure, was awarded to Shelf Subsea Services Pte Limited. It is anticipated this phase of the work will be carried out in the summer of 2021/22 or alternatively in the summer of 2022/23.
MBIE has submitted an application for marine consents with the Environmental Protection Authority (EPA) for the removal of the subsea infrastructure and the plugging and abandoning of the Tui wells. An independent board of inquiry is considering MBIE’s application.
Subject to EPA granting the marine consents, it is anticipated the plugging and abandonment work will be carried out from late 2022.
At the Offshore Well Intervention Mediterranean 2021 conference Alex Nicodimou, VP, Sales & Marketing, Well Intervention Welltec, hosted a session exploring the challenges and opportunities facing P&A operations in the region.
Nicodimou opened the session with a presentation explaining that the Mediterranean covers a diverse landscape in terms of geology, operating environments, cultures, languages, etc and that the way companies perform work across the region can vary considerably.
He noted that one of the reasons the region is such an exciting area, is that there are so many fields at different stages of development, and is home to some of the largest gas fields in the world which have yet to be drilled. For the latter he added, “There is a fantastic opportunity for P&A as for the first time, we have a region where wells can be planned with the world’s best practices and learnings incorporated from the very start. This is something that Welltec has been trying to address and incorporate through new technology.”
Nicodimou commented that new solutions are being developed to bring efficiency and cost saving to P&A operations, not to mention adapting existing technologies to be applicable to P&A ‒ something Welltec has found a lot of success in.
One area that has brought a lot of attention in the topic of well abandonment is carbon capture storage. Paolo Nunzi, Operations Support Manager ENI, said they have been harnessing this in the North Sea offshore UK. He said one of the most important things to consider in regards to CO2 storage is proximity to the coast as longer distance means more cost and (perhaps ironically) more CO2 produced in the process.
On the topic of new technology, Nicodimou asked if there was a current gap in the technological landscape.
David Dempsie, P&A Task Force Leader Repsol, replied, “Certainly within Repsol our aim is rigless technology. We feel it is perhaps not a missing technology but one that has the capacity to be applied beyond the traditional norms.”
He added that Repsol is looking to undertake a campaign for subsea abandonments within the next two to four years and is looking at rigless technology as a potential solution. He remarked that ultimately risk and economic considerations are what will influence this decision to utilise this technology and undertake such campaigns.
Coming into the conversation, Neil Greig, Sales Manager Helix well Ops (UK) Ltd, said, “We are looking at new technology in-house and working with other companies to develop rigless technology. We are confident we can get it to a place in the future where rigless can be used, even in more complex wells.”
He added that rigless can also bring massive benefits when it comes to data gathering. “You can go out with a rig and not know what you are going to encounter when you go into a well. Data gathering is essential to deal with all eventualities. You could arm a light well intervention vessel with a few extra tools; make it a swiss army knife, and go out with the minimum expectation of getting the tree cap off. Then, if accomplished, you can see if you can get access down to the reservoir to the required hold up depth and if so, see if it is a candidate for doing some pre-abandonment work such as plug and lubricating.
“If you manage to achieve all that you can finish the whole well completely rigless. Worst case scenario you have identified for a rig exactly what it will encounter and it can arrive with all the tools in the box. There are a lot of benefits from doing up front data gathering.”
Dempsie said, “We have a diverse portfolio so we can look at how to apply new technology in a stable environment, perhaps onshore. The biggest risk is if you take the technology offshore, you have all your eggs in one basket and if it does not work first time the appetite disappears. We have to be mindful and service providers need to understand this risk as well. We try to have a balance so we can support and encourage but ultimately, we have to step forward. We won’t see change in our performance unless we instigate change ourselves.”
The future of P&A in the Mediterranean
In terms of appetite for P&A work, Greig commented that the Mediterranean is more difficult as there has not traditionally been enough work to justify a permanent vessel in the region. So every instance when someone has a well which is a candidate brings significant transit costs. “We have only been in the Mediterranean once (2015) but we have been speaking to people for years. We have just not managed to generate enough interest to make it work.
“We need a catalyst to grow around. We think there is a big opportunity to collaborate and we get some vessels into the region. The alternative is we tie our North Sea boats up between October and February which historically happens in UK. What would be favourable is to take these boats into a region more suited to winter months.”
Luca Martini, Well Engineering Manager ENI, touched on collaboration as a way to facilitate further work in the region. He said, “What we try to do is put together our [operators] needs and get a single vessel performing campaigns in line in order to share mobilisation costs. We have regular meetings every three to four months with other operators to pick this up and see if there are any opportunities for synergies but we should be speaking more.”
Riserless Light Well Intervention (RLWI) is proving to be a cost-effective method of intervening in West Africa’s offshore wells, using suitable support vessels instead of rigs.
A panel of industry experts came together at the Offshore Well Intervention West Africa 2021 conference to discuss the risks posed by RLWI and how the industry is perceiving new technologies driving the uptake of such activities.
Chiwuike Amaechi, Principal Subsea Intervention Engineer of SNEPCo, said that value realisation is one of the key risks that need to be considered when picking an intervention method. “Categories for this include production enhancement and well integrity. The economic threats are mainly around the fears of obtaining the projected production gains which would justify the investment into the intervention,” he added.
Elaborating on the challenges related to environmental safety, he said it is difficult to clean out a well in a purely riserless intervention. “How do you ensure that you do not release any hydrocarbons to the environment, particularly in places where there are strict regulatory requirements and organisations that have a zero spill policy? These are some of the roadblocks that we face in the implementation of riserless interventions,” Chiwuike said.
Oladapo Ajayi, Division Geounit Manager of Reservoir Performance in Nigeria and West Africa, Schlumberger, also gave his insights on the topic from a well service company’s perspective. He said they usually look at factors like water depth, climate and most importantly, the commercial aspect. “There’s always the triple constraint – time, cost and quality of the performance. In terms of time, the schedule and planning are important and when we say cost, we mean the budget we are looking at.”
According to Andrea Sbordone, Business Development Manager for TIOS, the risk associated with RLWI does not increase alongside depth. “We see RLWI as a better option from an environmental perspective, as the impact is significantly lower and the number of people needed is less too,” he said, adding that operators who have not used RLWI before have now become much more comfortable after using it once.
Moderator Thomas Angell, Director of Offshore Network, said that the idea of ‘horses for courses’ might have changed in the last 5 to 10 years in the intervention field, and Sbordone opined that flexibility is important, and one should be prepared for surprises. “In the last 15 years, the kind of operations you can do on e-line have been increasing, the gap (with coiled tubing) is reducing slowly.” Agreeing with his co-panelist, Oladapo Ajayi said that indeed the gap has reduced in comparison to previous years.
As new technologies have entered the market, the panelists stressed the idea that these need to be properly tested before they can be utilised. “We do need to see technologies matured somewhere else. It is always good to have seen it work beforehand and find out the success rate as well as what failed for learning,” informed Chiwuike.
Sbordone noted that, in terms of downhole solutions, new technology is released every year which is deployable from a riserless light well intervention vessel such as sealing technologies for example. In terms of conveyance he added there has been big steps taken forward and riserless coil tubing solutions, for instance, are making significant progress to be field-proven.
“Last year, we did a campaign of riserless coiled tubing coring in Norway, in water depths up to 3085 m. We deployed riserless coil tubing 14 times. This confirms that water depth is not an issue for riserless coil tubing. Times are changing and people are becoming more adaptable to new technologies.
“15 years ago, if you asked a coil tubing provider to put coil tubing through open water as a pumping downline in 2,000 m, they would be apprehensive to agree. However, slowly the industry started doing it and now it is pretty much the standard,” he added. There has not been a change in the technology used, what has changed is its acceptance and the operators’ confidence in using it.
Stressing on the need for true competency and integration for achieving efficiency, Sbordone said crew integration is important. “This integration is not just for equipment but also for people. The crew working on different parts of the operation should know each other’s work and coordinate the activities to achieve high efficiency.” Chiwuike agreed, highlighting there are significant benefits in efficiency and cost that service providers have been able to bring by offering an integrated solution with vessels that incorporate a complete light well intervention package executed by a core crew that have developed experience through various campaigns.
He added the appetite for RLWI is increasing in West Africa, noting that there were three RLWI campaigns ongoing in West Africa in 2019 in three different countries for three different operators, with three different suppliers. “We believe intervention activity is increasing and will continue to do so.”
Oladapo Ajayi said, “Light intervention is the way, in terms of the efficiency that we gain. There is a full appetite for this kind of work and, for me, technology is the main thing to drive this. Digital can open a new horizon of growth in offshore intervention business and help identify candidate wells, provide a complete portfolio of intervention options to select the optimum solution as well as being able to ensure a predicable successful outcome.”
“The advancement in the digital space provides opportunities for the ability to better risk assess operations and, therefore, make calls on probability of success during the planning stages. Thus, more digital operations ahead of time can be utilised to better improve efficiency of the actual operations. In addition, better planning and utilisation of assets should result in cost reduction. All of this is only possible based upon information sharing between operators and service providers being the key,” he continued.
Angell concluded, “There is now a real understanding of the difference between cost and price and value. These are three things we understand really well known when it comes to complex well programmes.
“The providers out there are the right ones to make this a reality. It would be great to return next year for this conference and listen to some of the projects that everyone has done in that window.”
Helix Energy Solutions Group, Inc, an international offshore energy services company, has joined Trendsetter Engineering, Inc. in a global partnership to provide integrated hydraulic intervention services for subsea wells and flowlines.
The new partnership will integrate Trendsetter’s 15,0000 psi Subsea Tree Injection Manifold (15K STIM) and experienced personnel into Helix’s state-of-the-art fleet of well intervention vessels including the Q4000, Q5000, Q7000, the Seawell, the Well Enhancer as well as two chartered monohull vessels; the Siem Helix 1 and the Siem Helix 2.
Mike Cargol, VP of Rentals and Services for Trendsetter Engineering, commented, “This collaboration with Helix allows us to streamline contracting, improve operational efficiency and mitigate the operational and financial risks typically associated with hydraulic intervention operations. Although the initial focus is hydraulic intervention, we are excited about what the future holds for Helix and Trendsetter and look forward to collaborating further in order to provide additional value-added services to our clients.”
Jonathan Rourke, General Manager of Helix’s Subsea Systems Intervention Group, added, “We are delighted to have reached this agreement with Trendsetter Engineering, representing a collaboration between two industry leaders with expertise, experience and capabilities in the global well intervention market. This partnership will expand Helix’s intervention capabilities to further provide cost-effective and efficient alternative solutions to our end clients, and further reduce financial risks.”
Neil Greig, Sales Manager at Helix Well Ops, presented at the Offshore Well Intervention West Africa 2021 conference to showcase the Helix Q7000 DP Class 3 semisubmersible vessel which has continued to prove its capabilities across multiple campaigns in West Africa.
Greig noted that Helix has accrued a lot of experience with well access and has successfully entered more than 1500 wells globally. The company has an impressive fleet featuring the Q4000, Q5000, Siem Helix 1 and the Siem Helix 2 vessels all of which are capable of a wide variety of applications. It is through their practice with these vessels that Helix has been able to launch themselves effectively into campaigns in West Africa with the Q7000 (which has similar topside equipment to its siblings) and has achieved efficiency from the start.
Greig explained that the newest vessel was delivered as part of the Subsea Services Alliance between Helix and Schlumberger and so benefits from the expertise of both companies. By leveraging their combined knowledge, they have been able to reduce the crew size from wireline and slickline from 14 down to 8 and have reduced the coil tubing crew by 5. If an arbitrary figure of US$1000 per person per day is taken for crew cost this translates to savings of at least US$1mn per 100 day campaign. This is not too mention the cost savings of reduced crew changes, helicopter transfers and bed spaces etc.
The Q7000 is suited to deepwater applications down to 3,000 metres but is also designed to work in shallower water with an 80 metre range. The Intervention Riser System (IRS) on board enables access to both convention and horizontal subsea trees in depths down to 10,000 feet and is capable of applications including coiled tubing, electric line, slickline, cementing, well abandonment and tree change outs.
The story so far
Greig explained that so far the Q7000 has performed three campaigns with Exxon Mobil, Total and Chevron (all in Nigeria) and is currently in the field under contract from SNEPCo.
In the first project, the vessel successfully delivered a five well campaign with scopes of work including the acquisition of reservoir data, water shut offs / zonal isolations, hydrate milling / CT clean up, and remedial safety valve operations. This was performed some 65 miles from Nigeria in more than 1000 metre depths.
At certain points of the campaign instead of fully recovering the IRS it was lifted free of the well and then the vessel moved to the next location with the IRS held at depth, this reduced time for deployment recovery operation significantly.
The campaign had a number of challenging ‘firsts’ for Helix involving a Nigerian crew with a bran new system and an untried IRS. Greig was happy to report that all the personnel and equipment involved performed flawlessly and at a time when Covid-19 was disrupting travel.
The highlights of this project included:
• First deployment of the new IRS, which was left in the water for 70 days straight.
• Five wells in a single IRS deployment.
• Project executed in 25 days less than planned.
• 96.86% uptime (1,752 hours or 73 days).
• Four subsea well hops.
• Zero LTI, walk to work, no lifts across deck.
• First coiled tubing hydrate milling in Nigeria.
• Zero delays in mobilisation of tools and personnel.
For the second project early in 2021 Helix was tasked with performing work on five wells across two fields. The scope of work included TRSSSSV lockout and WRSSV install on three wells, acid stimulation on CT across screens and acid stimulation on CT across screens followed by well clean up (flaring). These were conducted in ultra deep water down to 1560 metres, 90 miles off the coast of Nigeria.
Once again all involved performed exceptionally well with highlights including:
• >98% uptime.
• Three subsea well hops.
• Zero LTI walk to work and no lifts across deck.
• First well clean up test on Q7000.
• Zero delays in mobilisation of tools and personnel.
• Improvements in vessel efficiencies.
Greig concluded, “The Q7000 is something between a rig and a light well intervention vessel. It can’t drill a new well, it is not sized for that, but it is sized for more efficient heavier intervention campaigns. With rigs, when they go into intervention mode you need to get the associated equipment brought on. The Q7000 achieves huge efficiency advantages by having the equipment already there and bunny hopping between wells also saves time and money. Additionally, being able to swap between services is also a real benefit.
“There is nothing specific I can share for work in the future involving this vessel, but ‘build it and they shall come’ mentality seems to be working. There is currently a huge appetite to go after oil and if you have an asset in the field to do that its going to make sense people will wan to use it. We are certainly seeing an increase in work and this is great for everyone involved.”
Welltec has launched a fully revised and transformed design of the pioneering Well Tractor conveyance solution, the Well Tractor 212 CVT, equipped with Continuous Variable Tractoring technology.
To make operations faster and more efficient than ever before, the new CVT system automatically maximises speed and power at all times, optimising every conveyance run.
Welltec VP Sales & Marketing, Alex Nicodimou, commented, “The Well Tractor remains a key service that we provide, it’s the foundation of everything that we do in conveyance and a solid base for our powered mechanical interventions platform. It’s what started the entire domain of interventions on wireline.
“Now our engineers are bringing something special to the market that will ensure we continue to lead in conveyance solutions.”
In addition to the new Continuous Variable Tractoring system, the new Well Tractor offers a whole host of innovative functionality and performance features, including a heavily revised electronics package that is rated to higher temperature demands within a more robust architecture. It also allows for full two-way surface control that can send commands to the tool downhole and receive diagnostics back at surface.
Traditional conveyance platforms are driven hydraulically by a pump, and in many cases, that downhole hydraulic pump is a shared asset that powers multiple wheel sections downhole. The Well Tractor CVT is configured so that each wheel section has its own power unit. These new hydraulic units and wheel sections are shorter and more powerful than ever before, resulting in a system that operates as multiple individual tractors downhole with inherent redundancy, without compromising on overall length. In the event that any one section meets a restriction of any kind, the other sections remain free to power themselves without any detrimental effect.
Building on more than 25 years of knowledge and experience, the Well Tractor CVT is the next phase in development of Welltec’s conveyance technology.
In March 2021 a panel of industry experts met to discuss the challenges and opportunities of riserless light well intervention (RLWI) in sub-Saharan African (SSA) and, half a year on from that spirited debate, as part of the Offshore Well Intervention West Africa 2021 conference the party reconvened to discern if anything has changed.
Sola Adekunle, CEO, Cranium Engineering reprised his role as host and began by outlining some global changes to the oil and gas market in this time. He noted that in November 2020 oil prices were sat at US$37 per barrel, rising to US$63 on 1 March. At this time, boarders were still more or less closed, lockdown restrictions were still in place and generally Covid-19 was having a huge impact on business.
Six months on, the pandemic is still here but with the distribution of vaccines in full flow the world has opened up, industries are recovering and, as of 4 October, oil prices had climbed to US$82.95 per barrel.
RLWI in a recovering market
During the last session the panellists explored the benefits of RLWI by commenting that operators can achieve the majority of their objectives at a much lower cost and this presented a significant opportunity to capture the low hanging fruits of oil production. Since then, Adekunle asked, has this been recognised in SSA? And has the region adopted this method of well intervention to alleviate it’s rapidly ageing well stock.
New member of the panel Paul Stein, Commercial Director of Baker Hughes, said, “Globally it is a bit mixed in terms of RLWI despite the oil price going up. We are certainly seeing more tendering and early engagement with clients in this space but there is a split in customers. Tried and tested customers have RLWI in their core business and some are consistently undertaking such campaigns.”
“However, particularly in West Africa there is a delay in operations taking place which is maybe a reflection on the downturn of capability and knowledge within untested companies. It is also a significant investment for operators to pitch internally and many companies do not have that pot of money set aside for interventions. Now is the time to support clients to realise the production gains that can be achieved; particularly in West Africa which has an ageing well stock. I believe RLWI has a big place in the region.”
While there has been hesitation to undertake RLWI campaigns, this has not been the case with BP. Matthew Vick, Senior Subsea Wells Engineer, BP, explained that his company had continued with these operations and had just wrapped up a campaign in Angola. For the future it had already started the leg work for another campaign in the future alongside major campaigns in the Gulf of Mexico and the North Sea. For his company, “Light well intervention has become a routine operation at this point.”
Feyisola Okungbowa, Executive Director, Baker Hughes, added that there was definitely a lot more upfront activity but this was not, as yet, really translating into actual business in the region.
She said, “We do have some operators in SSA executing currently but with the ageing stock that we spoke about last time the coverage is still not there compared to other regions. With the improved oil price we are having discussions on more oil creation and yet I am still wondering why we are not seeing the market use light well intervention ‒ a low hanging fruit which can be used to boost production.”
The panellists noted that perhaps there was an unrealistic expectation for this uptake to happen quickly and, in reality, senior executives need more time to truly understand the benefits of light well intervention. This education journey has not been helped by the long pause of operations during Covid-19.
Encouraging RLWI
With the challenges listed the panellists then turned to discussing how they can be mitigated to encourage more campaigns of this nature in the region. Picking up on education, Vick noted that the benefits of RLWI can be conveyed by communication within the industry. He said, “We love sharing out lessons and we like it when other operators share theirs. The more something is used the more efficient it becomes and this will drive uptake.”
In this vein, collaboration is also high on the list. Intervention campaigns can be very costly for less developed regions such as West Africa as often specialised equipment must be brought in and this might prove not economically viable if only a few wells are targeted. However, the panellists explained, this expenditure can be cut if split between several operators partnering on the same campaign. This would also result in longer campaigns which would, the longer they go on, drive efficiency and thus capture more value: Vick noted that the biggest return on value is usually achieved on the 5th/6th well onwards when engineers start to work through the kinks.
To achieve this, contracting strategies are paramount. Another new member, Vidar Sten-Halvorsen, Subject Matter Expert-Well Intervention at Havfram, noted, “It is important to have a clear agreement up front on who is doing what and how they are going to work together. Agree on contractual issues early and then everyone is in the same boat with the same agenda.”
Vick added, “A one-team mentality is critical and having that formally defined is very important. Make sure everyone is on the same page, has their relationships clearly defined and agree to it up front.”
Stein commented that Baker Hughes has a great track record in SSA with countries such as Ghana and is capable of conducting operations in other waters across the region as well. He noted that his company is more than happy to work with other service companies in order to unlock the RLWI commercial potential that SSA holds.
Okungbowa added that their local content strategy is second to none after spending the last three years training up local engineers. Because of this they have a great foundation from which to execute operations cheaper and faster, avoiding the need to bring in too many external personnel.
Finally, the panellists explained that with so many energy companies placing climate concerns high up on their agenda, light well intervention has the potential to help operators maintain production at a reduced carbon footprint.
Sten-Halvorsen said, “This is becoming more and more important from an operator point of view ‒ the footprint left behind after operations. Lighter vessels have lower fuel consumption and it is something that is really favouring this approach over the use of heavier units.”
A brighter future ahead?
Despite not as much uptake in the last six months as was expected, the panellists remained positive about the future of RLWI in SSA.
Sten-Halvorsen concluded, “Africa is the next big thing for well intervention and there is a huge price to win here going after intervention in West Africa.”
Stein added, “My aspiration is to be in a position to conduct multi-well campaigns in West Africa utilising the potential of light well intervention. The region could go from a place not really using this method to one that is driving. It has the potential to do that.”
Concluding another insightful session, Adekunle simply said, “It is the way to go. It is the future.”
At the Offshore Well Intervention West Africa 2021 conference, Ejimofor Agbo, Senior Completions Engineer at Newcross Exploration and Production, presented a case study outlining his company’s new approach to wax removal.
Ejimofor began by commenting that wax production presents one of the most challenging flow assurance issues when not addressed in the well completion design stage. The problem occurs when paraffins precipitate when the production system temperate falls below the wax appearance temperature (WAT). The resulting wax deposits that form can cause blockages which reduce production rate and flowing tubing head pressure and, in some cases, can take production from 2,000 barrels down to zero.
There are three conventional methods of solving wax problems, but each has inherent issues:
-Mechanical: Utilises wax cutters and scrapers for cutting the wax and also scraping it off the metal surfaces of the tubing. This is widely used and is cost effective initially but over time it can be needed at more frequent intervals which increases the cost and risk.
-Thermal: Downhole electric heaters are used to improve the heat retention capability of the crude so that its temperature remains above the WAT. A useful solution however there is a number of associated challenges such as availability of power sources offshore, the heating up of tubulars and formation damage.
-Chemical: Utilises chemical solvents to dissolve the wax molecules and allow the crude to be flowed to the surface. The problem with this solution is it has to be treated on a case-by-case basis which means information about the reservoir must be known and it can be costly overtime. There are also issues around availability of chemicals and initial completion design to accommodate for chemical injection valve
These are the standard wax removal methods but, Agbo continued, there are alternative approaches to wax removal, you just need to be able to think outside of the box.
An alternative approach
This is how Ejimofor and the team approached one of their wells suffering from acute issues with wax deposits which he presented to the OWI WA attendees in an informative case study.
The AK-40 Well, located in an ageing field, was completed in 1992 in two non-waxy reservoirs. However in 2005 the well was recompleted as the only drainage point in X1.0 reservoir containing waxy crudes with no provisions taken to cater for wax deposition. When the well was opened in 2006 it had an oil production rate of 1,142 BOPD but subsequent production gave 1,100 BOPD with intermittent wax cutting required every six months. The start-up rate post-wax cutting activity continued to drop and the duration of production dropped from six months to three months and continued until it only lasted for a month after wax cutting intervention.
Ejimofor said, “This called for a more effective wax mitigation strategy. We needed to do something different and think outside the box to resolve this issue.”
This began with laboratory analysis by which they discovered that a solution of 60% xylene and 40% diesel was the most effective at dissolving the wax with 98% dissolution achieved. Additionally, through an oil sample, they discovered the WAT was around 91.4⁰F while a dynamic model indicated the WAT was between 94⁰F and 95⁰F. Finally, through a bottom hole pressure and temperature survey they found that the estimated depth of wax precipitation was established at 3,300 ft which corroborates with breakthrough depth in previous wax cutting interventions.
With this information, the company then turned to deciding which alternative wax removal methods they should utilise, with two available.
The first was the Wax Inhibition Tool (WIT) comprising of nine dissimilar metals combined to form an alloy. This tool acts as a catalyst which enables a change in the electrostatic potential of the fluid. It changes the electrostatic potential and produces a polarisation effect at the electron level of the molecules which prevents scale formation, corrosion of metal and paraffin wax deposition. Crude is sucked into the holes in the tool and when in contact with the alloys to break up the long chain hydrocarbon molecules thereby making the oil ‘slicker’ and flow better.
Ejimofor added in some places they call it “the wonder tool”.
The other option was a Capillary Injection System which injects chemical solvent downhole to aid in the dissolution of wax molecules and allows the crude to flow to the surface. This can only be internally installed in the tubing string and can be used in various applications including liquid loading, scale control, salt control, corrosion control, and more.
The company compared the two and, in this application, found that the Capillary Injection System was not as viable as it would require a complex deployment, multiple items would be POOH, there was a high risk of plugging, it required preventative maintenance and there would be a high installation cost.
On the other hand, the WIT had an easy deployment, only one piece would be POOH, it carried a low risk of plug, there was low maintenance required and the cost of installation was lower. It was therefore the clear choice.
Execution and results
With their solution chosen Newcross turned to the next stage and carried out tubing integrity via mechanical wax cutting on slickline followed by wellbore clean up with solvent soak (of the xylene/diesel solution) across the entire wellbore. This ensured that before the WIT was installed the entire wellbore was cleaned of wax deposits. They then ran inhole and installed the WIT at 4,000 ft (600 ft below the WAT depth previously discovered).
Ejimofor commented, “Since we have done that, in the past eight months production has been the same and we have not needed to cut wax in this time. It is flowing on its own and management has been very happy with the results.”
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