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.
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.
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
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.”
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/
At the Virtual Offshore Well Intervention Europe Conference 2021, Neil Greig, Sales Manager at Helix Energy Solutions, showcased the Q7000 DP vessel and how innovations incorporated throughout its design has already delivered cost-saving and HSE benefits in its first few pilot outings.
As Neil pointed out, the Q7000 was born out of years of experience Helix has accrued from servicing more than 1,500 subsea wells. In terms of riser-based operations, the company has a track record going back to the 1990’s and the Q7000 is the latest in a long line of successful vessels including the Q4000, the Q5000, Siem Helix 1 and Siem Helix 2. All of these have similar capabilities and, in fact, the Siem Helix 1 and Siem Helix 2 have the same topside equipment as the Q7000 so, although the evolution has ensured the latest vessel has gained competency an efficiency, operating this vessel is not new territory for the company.
The Q7000 in detail
As Neil continued, the Q7000 is a self-propelled DP Class 3 semisubmersible that can move at 10.5 knots. In order to access subsea wells it uses the Intervention Riser System (IRS) which enables access to both convention and horizontal trees in depths down to 10,000ft/3000m but equally can be deployed in shallower waters to around 85m. Applications include coiled tubing, electric line, slickline operations, and the riser can be used as a conduit for cementing operations, well abandonment and tree change outs. As standard the system on Q7000 is rated to 10,000 psi but Helix have a 15,000 psi system should there be a requirement for use on HPHT wells. The 7-3/8 through bore diameter allows the ability to pull large OD crown plugs in horizontal trees.
The vessel has benefitted immensely from the Subsea Services Alliance, a strategic partnership Helix formed with Schlumberger to enhance their well intervention services. Due to the advances made from the alliance, the Q7000 no longer requires two separate crews for slickline and wireline which are never on deck together, as was often the case with older vessels, but instead brings them together in a multi-skilled crew. The result is a reduction in crew size from 14 to 8 people for these operations and for coil tubing and CTS/Testing, the crew size is brought down from 25 to 20. This results in remarkable cost savings to the client so that once the reductions and personnel transfers are calculated more than US$500,000 can be saved from a campaign of 100 days. Additionally, a smaller crew means reduced HSE exposure, which is of paramount importance in the current Covid-19 environment.
Operations in Nigeria
To demonstrate the capabilities of the vessel, Neil ran through the campaigns that it has conducted since entering operation in early 2020. In that year, it was commissioned by a major operator to carry out a five well campaign, starting in January, for a wide scope of work including water shut offs/zonal isolations, hydrate millings/CT clean up and remedial safety valve operations all with production enhancement objectives. These were conducted 65 miles off the coast of Nigeria in water depths of 1,210m.
Despite encountering inevitable challenges inherent with using a brand-new asset and having to manage Covid-19 implications which struck half-way through, the campaign was a resounding success with every stakeholder pleased with the performance. All five well operations were completed in a single IRS deployment with four subsea well hops and it took 25 less days than planned achieving 96.86% uptime.
When the Q7000 returned to Nigeria at the start of 2021, to perform another five well campaign further offshore and in deeper water (90 miles from land in water depths of 1360-1560m), Helix had to contend with a number of new logistical challenges due to Covid-19 protocols and the fact the vessel had to be taken out and re-established in Nigerian waters. Despite this, again the Q7000 ran a successful campaign effectively servicing the five wells across two separate fields. It did so with >97% uptime with three well hops and zero delays in mobilisation of tools and personnel.
Capturing value and reducing HSE exposure
From the testing and pilot campaigns of the Q7000 it was clear that the vessel has the ability to provide tangible benefits which Neil guided the audience through. One of the most obvious was the ability to use the IRS in a single deployment and run it between each well. Combined with the speed and manoeuvrability of the vessel, this meant that each run was achieved far quicker and single trips could be completed in hours not days. Additionally, as all the tools are changed at surface level, changing between slickline/E-line/coil tubing (which could take longer than a shift on a semisubmersible vessels) can be done in hours. Where riserless solutions are applied in deep and ultra deep water applications, there are significant time savings deploying the riser system once rather than running tools and equipment through the water column between each run. For a nine run total operation including two slickline and seven E-line this could usually take upwards of nine days, but using the Q7000 the operation was completed it in just over three.
Aside from capturing value, Neil also demonstrated how the Q7000 has been carefully designed with safety in mind to minimise the risk of accidents onboard. Working from height has been removed where possible and the risks inherent with manual handling have been designed out. Most notably the ‘walk to work’ system ensures that personnel can access the work site without needing harnesses and permits and their tools are safely deployed with automated systems.
The Q7000 has arrived with the full weight of Helix’s extensive knowledge base and experience and has been designed with the latest innovations to ensure it delivers maximum efficiency, delivers value and keeps its crew as safe as possible while doing so. It is no surprise that the vessel has already been hired to conduct more work in Africa in 2021 and potential abandonment scopes in 2022 and will not doubt see an extensive workload over the coming years.
To learn more about the Q7000, follow the link below:
https://www.helixesg.com/what-we-do/our-assets/q7000/
Paradigm, an upstream oil and gas technology and services company, has launched the i-Winch, a sustainable conversion service for adapting existing diesel hydraulic intervention winches to fully electric driven intelligent winches.
The i-Winch was developed from their fully electric driven and controlled E-Winch range, to address the challenges facing service companies to invest in new assets that offer lower carbon solutions.
“With the current pressures on oil and gas companies to reduce carbon emissions, the benefits of electric driven winch systems are clear. As with the uptake of electric cars with environmentally conscious consumers, so too are operators looking to satisfy their need to responsibly reduce emissions,” commented William Ash, Managing Director of Paradigm Technology Services, a division of Paradigm Group.
“We developed the i-Winch unit based on a philosophy of repurposing existing diesel hydraulic winches into fully electric drive units, using our proprietary drive system which eliminates the need for hydraulics in either diesel or electric hydraulic driven winches.”
Capturing value
Ash continued, “One of the major challenges for service companies currently is the investment costs involved in switching to electric driven units whilst they already have a fleet of conventional diesel hydraulic units on the books. For example, one of the most prolific winches on the market over the years is the ASEP SlimLine, a diesel hydraulic designed unit designed to last several decades. An i-Winch conversion to rebuild an old unit back to fully electric driven, will extend the life of the unit by at least 10 years, so not only extending the life of the unit but eradicating the need to repair or replace equipment.”
“In addition, the performance of the unit is improved and offers all the benefits of our E-Winch range with constant speed or tension control, remote control, automated jarring, zero-line breakage, and enhanced safety whilst being fully configured for remote operations, thus reducing the number of crew. We conservatively estimate US$15,000 annual maintenance saving per unit after the conversion whilst sustainably repurposing a significant portion of the material from the donor unit as part of the process”.
Ash concluded, “Operators are under pressure to significantly lower their carbon emissions right now, and we are proud that our values and global leading technology combine to offer a cost-effective solution here. The combination of our E-Winch or i-Winch units with our digitally enabled slickline platform system, Slick-E-Line, can transform conventional well intervention operations into a fully digitally enabled well intervention single package, that reduces runs, reduces costs and reduces carbon impact whilst enhancing real time control.”
For a relatively young company (Paradigm Group was established in 2009) the i-Winch unit is the latest in a strong line of solutions developed to minimise carbon impact and generate value for the energy industry.
Ocyan, one of the largest drilling contractors in Brazil with an offshore fleet in service for major operators in the area, has selected Kongsberg Digital’s SiteCom software to supply real-time drilling data from their rigs.
Ocyan’s rigs will be using Kongsberg Digital’s SiteCom solution to collect and convert data from different data sources making standard data available for Ocyan's main data platform Ocyan SMART. Besides the drilling control system, rigs are configured to receive marine data, data from dynamic positioning systems, ocean current meter systems and will be integrated with third parties for calculating drilling riser fatigue.
Kristian Hernes, SVP Digital Wells, Kongsberg Digital, commented, “As an operator, having access to complete, standard data in one system is a prerequisite to digitalise and automate processes in scale. Ocyan’s requirements for real-time data shows the robustness and versatility of SiteCom as a data collection software for the industry.”
The benefits of the SiteCom solution include safer and more efficient drilling due to a clear “bigger picture” of activities from data monitoring; accurate positioning provided by real-time information used in conjunction with historical and plan data; reduced risk of stuck pipe from the monitoring of casing runs; and confirmed cementing with the quality of cement placement monitored by integrated well-site data.
Rodrigo Chamusca Machado, Technology and Innovation Manager, Ocyan, added, “SiteCom is helping Ocyan to have a reliable and robust system onboard, connected to multiple sources and different protocols, converting data to WITSML standards in order to meet our client’s requirements.”
As part of the Offshore Well Intervention Virtual Offshore Well Intervention Europe Conference 2021, Charles Sanders, Business Development Manager at 3M, explained how 3M’s Ceramic Sand Screen Systems can provide operators and service companies with a competitive advantage and better risk/reward profile for well intervention operations.
Sanders opened the session by describing the basic design of the ceramic sand screens. The equipment is made up of a perforated base pipe with ceramic rings placed over on top. These rings have ridges that create a profile and provide the sand control. The solution comes in modules of 1.5m length and is available in a range of different sizes.
Alongside a host of benefits, the ceramic sand screens have been designed to reduce and potentially nullify three main areas of risk: erosion, economic and reputational.
Explaining these, Sanders noted that because the through-tubing of the sand control solution has been designed with reduced tubing size there is a perception that it is therefore higher risk as it amplifies the erosional forces at previous economic flow rates. But this is only the case with standard screens using inferior material which are severely limited by their susceptibility to erosion. With such equipment, when dealing with erosive material, the operational velocity must be kept fairly low otherwise the well life can be greatly shortened.
By replacing the traditional materials with ceramic, which is highly resistant to erosion and corrosion, the root cause of these problems are addressed which completely changes the traditional rule of thumb to indicate whether a screen can be run.
Sanders commented, “The material change in our sand screens means we can push the intermediate boundary so that conditionals viewed as high risk with traditional materials are now low risk. We have deployed into harsh environments far and excess of what the rule of thumbs are. This will enable us and operators to be more competitive and change the risk/reward landscape.”
A well that is producing to its full potential, unhindered by solids production, is a future revenue stream for both operator and service company. In this way the ceramic sand screen reduces the erosion risk, as explained; reduces the economic risk, by offering enhanced produce rates as well as limiting the cost of failure; and reduces reputation risk both on a corporate and personal basis, as 3M’s proven track record with this technology means you can be confident when deploying it.
Ceramic Sand Screen case studies
To demonstrate the capabilities of the ceramic sand screens, Sanders guided the audience through three case studies where the technology has been deployed.
The first was covering an underperforming gas well in the North Sea where it was not feasible to do a frac pack. There were no sand management facilities on the platform and the estimated velocity in perforations was 100 ft/s. 3M deployed their ceramics sand screens for the frac operation at 3 screen joints using rigless on E-line single run through the riser. This resulted in no proppant flow back for all six sub sea and two platform well applications, high rates of 35 MMSCFD, and increased longevity of the well life with all still producing today with no sand control failure.
After this success, 3M wanted to deploy their technology to enter into different zones and were commissioned to provide a cost effective solution to maximise production from a well in a shallower zone with downhole sand control in Egypt. This well had high gas rates, high influx velocity and impingement velocity through short net target zone. Hot spotting was also a major concern. Ceramic sand screens were chosen to address these challenges, and via a rigless wireline deployment, they were placed across the perforation zone in two wells and two wells above the perforation zone inside the tubing. This added 15 MMSCFD of gas to the asset, achieved sand free production rates and the company subsequently reviewed the technology to replicate it as the primary sand control method in other applications. As a result of these benefits the operator was able to capture more than US$12mn in first year of average production.
Finally, Sanders described an example in Norway where the ceramic screen was used for OH SAS completions in high corrosive and high rate gas wells. The solution in this case was specifically designed to address client specific OH challenges. Once deployed the sand screens eliminated the technical challenges and risks of gravel packing HPHT conditions, reduced the operation risk and avoided the cost of pumping services. Subsequently, the well was able to achieve its target rate of 106 MMSCFD.
Sanders added that the velocity encountered on these wells (such as 100 ft/s at the North sea operation) was huge and something that could not even be considered by traditional sand screen methods and yet 3M’s solution coped effectively and has even been tested in environments of up to 200ft/s. This represents a significant step change.
Sanders stated, “When you remove the risk perception the high risk opportunities open up. I have focused on erosional environments and benefits here but there is a whole range of advantages that this solution offer such as reduced operational complexity and HSE risks, proven productivity and minimised solids production, rationalising and standardising effective control design in the field, and can save you up to four to six times of CAPEX requirements over a conventional rig operation.”
Concluding the session, Sanders offered the audience the opportunity to challenge 3M with their well sand problems which they would be happy to look into and address if they can. As Sanders added, “these don’t solve every problem, but they sure do solve a lot of them and we would love to see how we can help deliver better performance for your assets or well intervention services.”
Another opportunity to learn more
On Tuesday, July 6th 2021, 3M will be demonstrating in more detail how the Ceramic Sand Screen Systems can offer effective sand control and long term productivity for your wells in a free online webinar.
Starting at 10:00 am BST, 3M will discuss whether the current sand control practices used in oil and gas production contribute enough to meet productivity targets and energy policies, and explain how 3M’s ceramic sand screens can eliminate the need for complex sand control methods. This will be followed by a Q&A session where you can ask your questions anonymously. If you register and can't make it to the webinar, a recording is available after the event.
To sign up, follow the link below:
A report by Rystad Energy has predicted that with Australia about to see the largest-ever wave of offshore development wells reaching the end of their producing life, the decommissioning market in region is set for a huge uptick.
The report shows that Australia’s number of ageing wells nearing retirement will jump from 160 (today) to more than 440 by 2026, with a further 172 offshore exploration wells waiting in the queue.
As a result of this, the Australian decommissioning market may exceed a total of US$40bn a figure which could even double, depending on how many decommissioning projects materialise.
“Recent developments have made it more difficult for operators to sidestep decommissioning obligations by selling ageing assets, as the market appetite for such assets is drying up. Many producers will have to deal with the issue in coming years, with ExxonMobil having the lion’s share of liabilities in Australia,” said Jimmy Zeng, senior analyst at Rystad Energy’s upstream team.
Rystad Energy’s analysis of the P&A potential takes into account the production status of each operator’s offshore wells, the likelihood of producing fields ceasing output in the coming five years, wells that have been already suspended but not yet abandoned, along with partially abandoned wells. While development wells make up the bulk of the total, exploration wells are also in need of P&A to a lesser extent.
It is estimated that 890 offshore wells in total were drilled in Australia before 2015, of which 108 have been permanently abandoned. Of the 782 wells not yet abandoned, Rystad identified a group of wells that we consider good candidates for P&A activity in the years ahead. Filtering out wells that are more likely to be identified for upcoming P&A, 440 wells are P&A candidates, the majority of which are in the Gippsland Basin.
The report continues by noting that the dominance of the Gippsland basin is to be expected given the legacy of offshore development in the region, driven by ExxonMobil and BHP’s Gippsland Basin Joint Venture (GBJV). Within the Gippsland group, most wells are located on fixed platform facilities, while in other basins the distribution of facility types is more mixed. New resource developments in the Gippsland Basin are becoming more capital intensive, but the outlook for P&A opportunities in the area should prove attractive to service suppliers.
In the North Carnarvon Basin group, Rystad has identified an age distribution that shows non-producing wells are relatively ‘younger’ than those in the Gippsland, with the majority being no more than 20 years old. Even so, various measures intended to ensure operators fully decommission facilities and wells are likely to provide a tailwind for service suppliers seeking P&A mandates in the North Carnarvon basin as well – spurred by the industry controversy over Northern Oil & Gas’s inability to fund its decommissioning of the Northern Endeavour FPSO and associated wells.
ExxonMobil leads the way in its decommissioning liabilities, with a rapid increase in the number of wells likely to cease production over the next five years. While this is a high-cost endeavour, most of these wells are platform-based, where per-well abandonment costs are likely to be significantly lower than for subsea wells.
Furthermore, regulatory pressure on ExxonMobil to decommission these wells has increased significantly lately.
Outside of ExxonMobil’s high well burden, operators Santos, Woodside, BHP and Vermillion Energy will also experience growing decommissioning obligations in the next five years. Woodside and BHP have mostly subsea wells in this category, which could mean their decommissioning bills will be higher on a per-well basis. Woodside recently communicated its intention of starting abandonment of up to 18 subsea wells on the Enfield field from 2022 to 2024.
While this could be a very costly development for operators in the region, it opens up a huge opportunity for service providers and companies involved in decommissioning operations who could see many campaigns coming their way as these wells continue to age.
Interventek, a subsea well intervention technology specialist, has been awarded a repeat order from Trendsetter Engineering in Houston, to supply additional 6-3/8”, 15,000psi, open-water Revolution shear-and-seal valves.
The contract comes on the back of Interventek supplying an initial set of the advanced subsea shear-and-seal safety valves in 2020, comprising single and dual cavity variants, and successful systems integration testing within Trendsetter’s new 15,000psi, TRIDENT Modular Subsea Intervention System. Trendsetter is now aiming to roll out further systems to service growing demand in the well intervention and subsea completions market and will use Interventek’s offerings to do so.
The Revolution valves
The Revolution valves are specified for sour service deployment, with dynamic valve bore components, utilising high strength, corrosion-resistant alloys. They benefit from Interventek’s compact design, which allows integration within more modern, lightweight systems, to achieve greater cost and efficiency savings through operational flexibility. The Revolution valves also separate their internal cutting and sealing components for improved performance, whilst meeting rigorous API-17G qualification criteria and being suitable for use in challenging subsea environments.
Mike Cargol, Vice President of Rentals and Services at Trendsetter, commented, “Trendsetter has worked closely with Interventek to achieve our objective of bringing innovation to intervention. Interventek’s compact Revolution valves have proved to be the ideal match for our lightweight and modular Trident systems, enabling us to achieve the goal of delivering HPHT intervention solutions while also realising system size and weight reductions of up to sixty percent when compared to competing systems. The result of this combination is a robust system which can be mobilised rapidly to any geographic region, reconfigured quickly to accommodate hydraulic, riserless light well or open-water risered interventions, and be integrated into a vessel or rig of opportunity with no bespoke modifications. The bottom line is enhanced safety, increased operational efficiency and reduced cost, especially for HPHT applications.”
Gavin Cowie, Managing Director at Interventek, added, “Our continuing partnership with Trendsetter is enabling many operators to realise significant efficiency gains in their subsea intervention operations. The compact, versatile design of our Revolution valve technology provides a great advantage for integration across a range of safety systems. It exceeds the highest industry standards and is suitable for open-water, in-riser and even surface applications. Despite challenging times across the industry, demand for our technology continues to grow and we are grateful to be working with such like-minded, forward-thinking innovators as the team at Trendsetter.”
Interventek’s open-water Revolution valves use the same shear-and-seal technology as the company’s field proven, in-riser safety valves. All products are available in variants to suit a range of system specifications, operational applications and well conditions. The company develops such technology in pursuit of their goal to deliver the best-in-class solutions at half the cost but twice the performance.
At the Offshore Well Intervention Middle East and North Africa 2021 virtual conference, Neil Ferguson, Business and Sales Development Manager, Well Intervention and Integrity at Expro, demonstrated Expro’s two latest developments in well integrity developed to unlock value for operators.
Ferguson began by noting that it is an exciting time to be involved in well integrity, an area which is attracting more interest from the industry each year. At Expro, ten years ago the main focus of the Well Intervention portfolio was production optimisation, whereas now 50% of its portfolio is well integrity related. To this end, Expro has recently introduced two new technologies to add to their product offerings to serve this market.
Fibre Optics Enabled Slickline
As Ferguson continued, fibre optics is nothing new to the industry and has, for many years, been permanently deployed in wells to monitor wells and identify problems. However, having this installed from the start of the well’s production is, for one, very costly (could amount to around US$500,000) and can also cause problems down the line. For instance, if an operator is relying on these fibre optics 10-15 years after installation the equipment may not function as effectively, with the fibre darkening for instance, meaning operators may not get the correct results they need when they need them.
Expro, therefore have introduced Distributed Fibre Optics Sensing (DFOS) Slickline which is able to be deployed into a well using a standard slickline unit. The DFOS Slickline service means that an operator only needs to deploy the fibre optics when and where they need it, rather than having it permanently installed from the start of the wells life. Expro has the capability to retrofit the fibre into the well for a few hours, get the required results and then it can be redeployed onto the next well – a development with the capacity to optimise capex at the start of a well’s life and opex throughout its life. The DFOS Slickline is capable of diagnosing a range of issues such as tubing to casing leaks, flow behind casing, gas lift valve leaks, leaks at packers, leaks at casing shoes, sustained casing pressure and sand protection.
Ferguson said, “One thing our solution partners worked hard on is our ability to process data on site. Traditional fibre optic can generate terabytes of data per day – we didn’t want to just hand our customers a hard disk of this at the end of the job, so having visualisation and analysis on site was very important to us. Therefore, as part of our offering, we reduce and streamline the data so it is easier to transmit and interpret – we can reduce 2.5 terabytes of raw data into a 30mb manageable file.”
To emphasise the capabilities of this technology, Ferguson demonstrated its use in some case studies. For instance, in the North Sea, DFOS Slickline was used to assist a customer suffering from a tubing to annulus communication issue. The DFOS Slickline was rigged up on the well and took just over 1 shift to perform a survey, before being pulled out again. DFOS Slickline has two embedded fibres; one for distributed temperature sensing mode and the other for distributed acoustic sensing mode, with acquisition from both fibres occurring simultaneously. While the DFOS Slickline was being pulled out of hole the data processing and visualisation task began, the DTS data processing and visualisation task taking just one hour, with the DAS data processing and visualisation task taking just three.
The well integrity issue was swiftly identified as a side pocket mandrel having a faulty gas lift valve leaving the operator free to pursue remediation activities immediately, with the intervention equipment still rigged up onto the well. In this way a customer’s shut in well (which was costing around 2,000 barrels per day in lost production) was swiftly restored to production. Because the DFOS Slickline is so efficient, the operator can go from deployment to remediation in the same intervention and campaign.
Octopoda
Ferguson then turned to the Octopoda Well Integrity Solution, featuring offerings such as line plug services, sealant services and wellhead multi-tools. The crown jewel, however, is the annulus intervention (AI) service, this innovative technology enables intervention into a live annulus with a hose, this to remediate well integrity issues by the pumping of fluids and resins.
In one case study that Ferguson outlined, Octopoda AI was run into the annulus to remediate a fluid barrier. The customer had issues with plugged bleed-off line due to a high viscocity mud in the B-annulus. A subsequent influx of gas into the B-annulus caused a problem which resulted in the well being shut-in. It was estimated that a traditional lubricate and bleed operation would take around 12 months to complete, so the customer called Expro, who was able to design a tailor-made solution with a 6mm hose and tailor made well spring tool to enable intervention into the B Annulus.
To remove the sustained casing pressure, the annulus fluid was displaced with 1.5SG brine. During the operation the annulus intervention system was deployed to a depth of 49m depth below the B-annulus gate valve, a total volume of 40,000 litres of 1.5SG brine was pumped, there were no spills or incidents reported, and the operation was successfully completed with the well flow being reinstated in 25 days.
Octopoda AI can be used in a variety of applications including the removal of sustained casing pressure, spotting of resin for casing integrity remediation, corrosive fluid displacement, preparation for P&A operations and environmental and groundwater protection. Ferguson stated that some of the benefits included cost effective well recovery by restoring well integrity, efficient footprint and personnel requirements, rapid mobilisation of the technology, and a reduced requirement for a workover rig or heavy duty equipment.
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