Latest News

• Region: West Africa
• Date: June, 2021

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/

• Region: All
• Date: June, 2021

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.

• Region: Latin America
• Date: June, 2021

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.”

• Region: North Sea
• Date: June, 2021

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:

https://engage.3m.com/CSSinOG_Digital-EN?utm_term=tebg-amd-oilgas-en_gb-edu-cssinog-one-web-na-register-5a-jun22-49661

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

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.

• Region: Gulf of Mexico
• Date: June, 2021

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.

• Region: Middle East
• Topics: Integrity
• Date: June, 2021

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.

• Region: North Sea
• Date: June, 2021

Aker Solutions has delivered another steel substructure for the largest industry project ever in Norway, the Johan Sverdrup field.

For phase 1 of the project the company previously provided three platform jackets and, with this jacket for phase 2, four out of a total of five have now been built and delivered on time and budget from Aker Solutions’ yard in Verdal, Norway.

Through the frame agreement entered into in 2014, and in international competition, Aker Solutions was awarded three out of four jackets for the first phase of the project. The first delivery was the riser platform jacket in the summer of 2017 which was the largest and most complex platform jacket delivered from Aker Solutions to date. It was delivered alongside the first visible installation at the new Johan Sverdrup field centre. In March 2018, Aker Solutions delivered the steel substructure for the drilling platform, and in July of that year the process platform substructure was delivered.

Now Aker Solutions has announced that the process platform substructure for phase 2 is en route from Verdal.

Sturla Magnus, Executive Vice President and Head of Aker Solutions' topside and facilities business, said, "This is an exciting and important day for us. Through great cooperation with Equinor, we have delivered all four of these platform jackets at the agreed quality, time and budget. I am very pleased that our customers confirm that we are a supplier that offers an attractive combination of technical expertise and cost-effectiveness.”

In total, the deliveries from Aker Solutions in Verdal make up about 90% of the total weight of the substructures for the combined phase 1 and 2 of the Johan Sverdrup field. More than 100,000 metric tons of steel will be delivered from Aker Solutions' facility in Verdal, including the piles that attach the jackets to the seabed. In addition, Aker Solutions’ facility at Stord has delivered a topside as well as a large module for the Johan Sverdrup field.

Erik Stiklestad, Aker Solutions’ Yard Director at Verdal, commented, “We have extensive experience in providing the customers with complete and seamless deliveries. In recent years, we have also increased industrialisation for how we execute projects. This, combined with long-term relationships in the supplier market, makes it possible for us to offer flexibility to our customers. We are now delivering as planned despite a year of major challenges with Covid-19. Together with our employees and partners, we have found good solutions that enable us to deliver the jacket to our customer Equinor without serious injuries during the execution.”

• Region: Gulf of Mexico
• Topics: Decommissioning
• Date: June, 2021

At the Deepwater Decommissioning Gulf of Mexico 2021 Virtual Workshop, Thore Andre Stokkeland, Head of Global Sales Archer Oiltools, Archer, chaired a panel to explore the latest innovations permeating the plug and abandonment (P&A) and decommissioning markets, and what the best practices are for getting new technology recognised by the industry.

Stokkeland began by noting that new technology is inherently designed to reduce risk and improve efficiency and asked the panel to outline some of the benefits which can be achieved for P&A and decommissioning operations through the implementation of these innovations.

Bart Joppe, Well Abandonment Leader at Baker Hughes, focused on the significant cost and time saving that can be unlocked through the utilisation of new technology. Providing an example of this, Joppe described an innovation Baker Hughes brought to the North Sea after they identified an opportunity in the market to remove subsea wellheads more cost-effectively. Traditionally, these have been removed by using a drill pipe-deployed cutting and pulling system from a rig, semisubmersible or a drillship which can be costly while other methods often have similar limitations.

Baker Hughes designed a solution to use a chemical cutter on a wellhead clamp and then power all of it with a ROV. The ROV and the crane wire are the only two things on the water and on deck the only equipment is the bottom-hole assembly. Once this is overboard there is no equipment on the surface. Using this technology, the subsea wellhead can be cut and pulled by two people from any vessel as long as it can deploy the tool overboard. This is a much more cost-effective solution especially for remote wells where getting a rig on location would cost a lot of time, effort and money as well as generate a lot of emissions.

Reducing emissions

Picking up on emissions reduction, the panellists noted that this had fast-become a serious concern of the industry and, therefore, technology that could help operators limit their climate impact was becoming of paramount importance.

Gabriel Barragan, Well Abandonment Advisor, Chevron, said, “We all know that operators are on a strong push to look at carbon emission reduction, with significant pressure from governments, shareholders and customers to do so. It is something pretty fresh and it is still developing now. At Chevron we are brainstorming ideas on how to achieve this such as reducing the risk of fugitive emissions and reducing idle time for rigs. While diesel engines are idly running, emissions are being produced, so reducing this time is a great opportunity. At some point we will come to service providers and see where there technology can help us in this aspect.”

Kevin Squyres, Sales and Service Deliver Manager, Archer, added to this by noting how there are a lot of indirect emissions which are only just being seriously identified as a low hanging fruit to reduce carbon footprint. Saving just a day or two of rig time, for example, is great for the environment. In regards to P&A, when dealing with wells drilled in the 1960s to 1980s the cement technology and care was not there. It is difficult to deal with these nowadays, but new technology can help clients fix these wells.

Stokkeland said, “The industry was very much focused on time saving and cost saving in environments when the rig cost was high. Now we look to reduce rig times not just for the cost saving but also for the emissions savings. Solutions are getting smarter and we can now perform more operations in one run than we could just a few years ago. That will be the way forward, to reduce footprint, reduce rig time and reduce the amount of people on the drilling rig.

Delivering new technology to the market

While at all times there is plethora of new technology being developed, often many fail at the first hurdles or are unable to make an impression on operators and so do not live up to their potential. The panellists therefore explored how providers can ensure that these innovations can make an impact on the market and help operators achieve the value they are designed for.

“Technology development starts by identifying the challenge you want to resolve and how you can address it most effectively. It is really important to understand how the perspective of the operator, customer and regulator as well as ensuring that you are selecting the technology for the right application. There have been lots of innovations where the trial did not work because the right application was not selected,” Joppe commented.

“Also, don’t develop technology and then try and solve the most complex scenario you can think of. Instead build a staircase, select multiple wells of different levels of complexity in a step-by-step testing process and learn as you go.”

Barragan noted, “Take advantage of industry events such as these. Present a technology, do some networking and get contact information from the appropriate people. It is important to understand their well management portfolio which will build your case and value proposition to that operator. Explain at what stage you are in the development phase, is it an early concept? Has a prototype been tested? Or perhaps it has been trialled multiple times. It is important to be transparent about the technology, and this includes being up front about its limitations.”

Squyres echoed these thoughts by noting that in regards to Archer’s Stronghold systems his company tried to be as open and transparent as possible. He said, “If a client comes and says we have this dual casing which is larger than we have done before we won’t just sit there and say we can do anything. Of course we want to say that but it is important to take time, and ensure you have your calculations, case histories and risk assessment as well as ensuring regulators and stakeholders are on board.”

Stokkeland added, “It is about patience and learning. As they say, Rome was not built in a day and it is the same with new technology. You have to learn, you have to go through hurdles sometimes before you end up with a field proven product.”

• Region: North Sea
• Date: June, 2021

Offshore technology supplier Osbit Ltd has reached a key milestone in the assembly of a new well intervention tower system for FTAI Ocean.

The FTAI Ocean Smart Tower System now stands at 40 metres (its full height), after the top section of the tower on to the lower section was installed in a complex lift operation.

This involved hoisting the top section of the tower by crane and holding it in place on the lower section, while the sections were welded together. With the two sections joined together, the final fitout of hydraulic, control and electrical parts can now take place.

The FTAI Ocean Smart Tower System

The system, currently under construction at Wilton Engineering Services in the UK, will facilitate integrated riserless and riser-based well intervention operations on FTAI Ocean’s flagship DP3 vessel M/V Pride. When completed, it will weigh 1,300 tonnes and be capable of operating in water depths up to 1,500 metres.

It integrates a series of innovations derived from Osbit’s experience in developing well intervention and offshore handling equipment to improve operational safety, flexibility, and accessibility:

-The tower’s vertical Open Water Intervention Riser System (OWIRS) racking system improves deck safety by reducing the need for access around the well centre to handle OWIRS joints, while its small footprint optimises deck space, for more effective equipment storage.

-The system integrates the existing vessel crane into the full deployment system, providing up to a 250-tonne active heave compensated capacity. Additionally, the system offers an active and passive heave compensated platform for building, operation, and recovery of OWIRS, and riser based or riserless intervention systems in 1,500 metres and 3,000 metres respectively. The heave compensated platform is able to support coil tubing, slickline and e-line operations and provides safe and efficient personnel access via an integrated walk to work system.

-The system is fitted with both guide wire and pod wire systems which, alongside the deck skidding system, minimises the need for crane lifts, increases operating windows and enables equipment to be directly loaded into the well centre.

-Also incorporated is Osbit’s Integrated Logistics Support (Osbit ILS) software technology, which offers detailed data insight and asset performance analysis.

Steve Bedford, Director at Osbit, commented, “This system is the culmination of our extensive expertise and strong reputation in the design and build of cutting-edge well intervention and offshore handling systems. We remain committed to utilising our capabilities to support our clients in enabling safer and more efficient offshore operations.”

“As a business, it is rewarding for us to see this world-class piece of kit successfully coming together and we are very much looking forward to delivering the completed system to FTAI Ocean.”

Jon Attenburrow, Managing Director at FTAI Ocean, added, "This is a great achievement, for all involved in the design, build and assembly of the Smart Tower System, in these difficult times. We are pleased the build has been carried out safely and professionally to date, and look forward to the successful completion of the world class Well Intervention Tower.”

To hear more from Osbit and industry experts on the latest technology and best practice relating to well intervention, be sure to attend the Offshore Well Intervention Europe Virtual Conference 2021 which is accessible via this link: https://www.offsnet.com/owi-eu/register.

• Region: Gulf of Mexico
• Date: June, 2021

At the Deepwater Decommissioning Gulf of Mexico 2021 Virtual Workshop, a panel of industry experts discussed the essential considerations when conducting plug and abandonment (P&A) operations in order to mitigate risk and enhance efficiency.

Opening the session, Kenneth Bhalla, Chief Technology Officer at Stress Engineering Services Inc., explained that even in the last couple of decades the design of subsea wells have dramatically changed, which can raise multiple complications to operators looking to conduct P&A operations if this is not properly taken into consideration. He commented, “If you look at wells which came into operation 20-30 years ago, typically they were drilled with a fourth generation blowout preventer (BOP). Relative to fifth and sixth wells, the stack has gotten taller and heavier going from 600 Kips to more than a 1000 Kips. The wellhead and casing system are going to be see much larger loads, whether that is static loads or dynamic loads and the loads of the BOP stack need to be accounted for during P&A operations.”

“Also to note is the conductor casing, which typically today are 36” x 2” X80. Going back 20-30 years ago these wells were designed with X56, 36” x 1” for example. Your conductor casing is lower yield as well as lower stiffness. In addition, if you look at conductor casing design today we push the first connector as low as possible to reduce the fatigue loads. When dealing with the P&A of wells drilled 20-30 years ago we have a different type of well design where the connectors are not as deep as they are today and are thus susceptible to potential fatigue damage and overload as well. You need to understand the fatigue damage caused by prior operations as well.”

Following this, Alex Lawler, Drilling/ Completions Engineer at LLOG Exploration, added that there truly are generational differences between the designs of wells and what was fit for purpose even a decade ago is completely different environment to today. For example, he outlined the production packer generations which can affect everything. If the packer needs to be removed, the operator needs to understand if it is a shift to release or cut to release as well as other considerations such as what the cut zone is, for example.

Therefore, in order to carry out a P&A operation safely and effectively, it is paramount when planning to understand these differences, understand them early, and understand them thoroughly. It is also important to remember that you may require some specific tools designed for the well, and often these have been discontinued since drilling. Sometimes these could be in another part of the world, and if this is not planned for it could cause real problems down the line.

Getting the right information

With older wells that have often changed owners several times, the information and documentation is frequently unavailable. It can therefore be incredibly difficult to find out everything you need to know before planning a P&A operation.

One way to mitigate this is to speak to engineers who have worked on the well previously (preferably those who were involved in drilling and production) and have them on board for the operation. Bhalla said, “I have been involved in a couple of different instances where two particular operators had a number of fields that they stopped development on but they knew they would come back in a year or two for P&A. They knew the people and the rig would change, so what they did was create a file around the wells based on the experience of their engineers there and people involved in earlier campaigns in order to identify future risks.”

Sometimes, especially with much older wells, it is not possible to contact past engineers. If this is the case, the panellists commented that you just have to go back to basics by going to the public records or seeing if you can get information from past operators. By identifying which rig performed the initial drilling, if there were any recompletions, and as much about its life as possible you can patch together some information on the well. The more that can be gathered, the safer and more efficient the P&A will be.

Planning contingencies

The participants continued by emphasising that it was absolutely fundamental contingency plans were put in place, as you are planning to fail without them.

Lawler said, “You are gutting an old house – there are going to be a few surprises. Do as much planning ahead of time and plan those contingencies, because they are going to happen. They are essential if the operation is going to be a success. What we have discovered to be very beneficial is approaching BSEE (or whichever local regulatory body you are dealing with) early. They want to make you attempt to isolate the zone, but if you say you have concerns and point out your contingencies to them you may not get immediate approval but it will not surprise them when the contingency comes up. When the contingency is needed, you will usually need approval very quickly, it could even be a matter of hours, and you will be more likely to get quick approval as they are aware of it.”

Dave Mantei, Subsea Manager at Murphy Oil, echoed these sentiments by adding, “I cannot emphasise how useful early engagement with regulatory bodies is for getting early direction so that when, at 2am the calls comes in and the contingency is needed, that are already on the same page. That is absolutely key in conducting a P&A operation.”

George Coltrin, D&C/ Wells Advisor at Endeavor Management, commented, “A couple of things which can help with these operations is foresight when drilling. When you plan new wells, especially development projects, it is worthwhile putting in the effort to think about the impact on the P&A. Obviously this is not a big driver in the choices you are making at that moment as you are thinking more about well integrity and production, but it is still a driver which should be considered and will help later on.”

“Also, often it seems when we are dealing with P&A is that it is planned more piecemeal. When an operator is drilling a series of exploration wells and need a gap filler P&A is often used to fill this. But we can get into a lot more when considering all the P&A obligations as a portfolio. In an ideal world, operators would get a rig and conduct a whole P&A programme. As an industry we are more efficient with things we do on a regular basis; operations not done for a while tend to be not as efficient as workers have not used the tools for a while or perhaps not ever. So doing a whole P&A campaign would avoid problems and make operations much more efficient,” Coltrin added.

All about the people

Finally, the participants emphasised the importance of people, noting that having competent and experienced employees will ensure P&A operations are conducted much more effectively and safely as, at the end of the day, they are the ones on the front line who will be conducting the operations.

Coltrin said, “With new rigs and equipment what we can do today is incredible. But I would prefer to have mediocre tools with great people rather than mediocre people and great tools. Therefore focusing on people is really one of the best things you can do. If you are trying to reduce the risk of operations, good communication between the office team and rig team is essential, and the best way to do this is get people in the office who have experience on the rig, who know it and have relationships with the engineers out there. You need to put time into the people who are on your team, otherwise you might get teams with mismatches, and risks can be the result.”

• Region: Gulf of Mexico
• Date: June, 2021

At the Deepwater Decommissioning Gulf of Mexico 2021 Virtual Workshop, Kevin Squyres, Sales and Service Delivery Manager, Archer, presented the Stronghold systems: the latest set of innovations from Archer Oiltools which offer an economical effective alternative to traditional methods of plug and abandonment (P&A).

Squyres explained how, by eliminating the need for milling, Archer’s Stronghold systems have the capacity to deliver more efficient P&A operations. When used in conjunction with Tubing Conveyed Perforating (TCP) products and new charge developments, the systems give economical and safe execution of operations providing time and cost savings for customers. The systems have been tried and tested in multiple environments across the globe including, the Gulf of Mexico, Alaska, the North Sea, the Middle East, Asia, and Australia.

Going into more detail, Squyres outlined the three tools for barrier verification and setting which make up Stronghold systems.

Barrier Verification
Archer Oiltools’s verification solutions consist of the Stronghold Defender and Stronghold Fortify systems:

-The Stronghold Defender test system enables operators to efficiently perforate and test an annular barrier. It functions in three steps by first perforating the casing or liner, then verifying the integrity of the annulus, before finally placing barrier material inside the casing.

-The Stronghold Fortify system provides a reliable verification of annular integrity in just one trip which consists of perforation of the casing, testing the integrity of the annulus, verifying the annulus integrity with a unique pressure verification system and cementing across the perforated areas.

Barrier Setting
The Stronghold Barricade system, the main focus of Squyres presentation, perforates, washes, and cements the annulus in order to create a rock-to-rock barrier to achieve permanent caprock integrity.

Usually, this can be achieved in just one trip, which consists of perforating the section, at which point the guns drop automatically; thoroughly washing the perforated annular section, moving down and up if required; placing spacer fluid in the annulus using the calculated pump and pull method; and placing the barrier material using the same technique, once the blank casing is reached the ball will automatically shear out. At this point the pumps are stopped and the operator will pull above expected top of cement to circulate/reverse out any residual cement in the drill pipe.

Squyres explained that in the Gulf of Mexico frequently rat holes are not available and so two trips may be required, but even if this is the case a lot of time and cost can still be saved against a lengthy cut and pull or section milling operation for example.

To demonstrate the benefits of using the Stronghold Barricade system, Squyres outlined a case study from the Gulf of Mexico where an operator needed to set a 330 ft cross sectional cement barrier in 13 3/8” x 20” casing which had no cement in place. The well was located in more than 6,000 ft of water depth and required a barrier placed just above the 20” casing shoe. The operator wanted a barrier to be deployed in order to prevent a cut and pull.

To meet this challenge, Archer deployed the Stronghold Barricade system after working with a local provider to ensure they had the right TCP charge performance. The tool successfully washed and cemented the 330 ft long interval with even rates at 1200 lpm. A successful test thereafter showed the operation was a success and the operator was able to move on with the completion of the P&A.

By using this method, the operator was able to capture value and time by avoiding a cut and pull. Off of the successful completion of this operation, Archer has now been commissioned for several more projects in the region with this client and indeed several others.

Globally, more than 200 P&A plugs have now been installed using Stronghold systems which have delivered 99% operation efficiency, achieved US$250mn in customer savings, and saved 190 tons of CO2 emissions per barrier.