Middle East

With around 32% of wells suffering from well integrity issues globally (according to a previous estimate from the Society of Petroleum Engineers), CRA-Tubulars is preparing to enter the market with its Titanium Composite Tubing (TCT) technology to provide a unique, cost-effective and reliable solution that will help tackle this constant headache for operators.

Speaking to Offshore Network in an exclusive interview, Joost de Bakker, CEO of CRA-Tubulars, noted that while this issue has consistently been a thorn in the side of operators around the world, it is one that has been somewhat swept under the rug or at least not given the attention and investment it deserves. Traditionally, capital has been spent on short term, cheaper solutions and then the life-cycle is dealt with as it comes – with tubulars often replaced every couple of years. Now, however, this narrative is changing and many large oil companies are starting to change their philosophy to be more prepared early on and spend less on their wells in late-life.

“Volume wise, populations are increasing and wells are producing less. Because of this, the strategy of working over wells is becoming more unmanageable. In addition, HSE considerations are pushing companies to be more responsible when managing their assets from both a human and environmental perspective,” de Bakker remarked.

CRA-Tubulars’ TCT addresses these issues by offering a robust and highly corrosion-resistant solution for the global oil country tubular goods (OCTG) market. The product offers corrosion-free completion (titanium) with carbon fiber and aerospace epoxy superior tri-axial strength of the OCTG. It is API-5CT and NACE MR0175/ISO 15156 compliant, has a max operating temperature at 140⁰C and an 18,000 PSI burst. This cost-effective solution therefore offers significant advantages of the more traditional duplex or nickel alloy tubulars which are susceptible to corrosive elements and Stress Cracking Corrosion (SCC).

Meeting market demand

Explaining the company’s history, de Bakker said, “We were officially founded in 2019, however, this is a natural succession from a team of inventors and engineers who have been working in this field for more than 20 years. Composite and non-metallic tubulars have been developed a lot over the last 20-25 years but one area that could never be truly tackled was downhole corrosion due to direct contact with a reservoir and the corrosive elements such as CO2 and chlorides for example. Composite materials are not very good at performing as a barrier in this context and meeting the standards of barrier philosophies, hence the design with a Titanium liner acting as a permeation barrier to overcome this. The idea for our company and product came out of decades of experience and an intent to rectify this.”

CRA Tubulars are therefore fast-tracking the TCT to commercialisation as a replacement for nickel alloys which are traditionally used for the most challenging well conditions globally.

“At this point in time we have built and tested prototypes. Based on that and modelling we can build on the decades-long experience of defence and aerospace development because we are using the same materials that have been used for aerospace applications – essentially we have repurposed aerospace technology and turned it into a tubular form to meet the requirements of the harsh downhole conditions in oil and gas, CCUS and geothermal wells.

“We therefore do not need to test extensively ourselves as it has already been proven how the materials interact and perform in similar conditions (in terms of temperature and pressure) to how we are using them in downhole solutions. You could almost say that we have patented a fighter jet in tubular form for downhole applications and using it to meet the demands of the oil and gas community.”

With the prototypes been built and tested to extreme conditions, the next step is certification. For this, the company has found an international operator who is supporting it financially and technically in taking the product through this process. In addition, CRA Tubulars is working with several partners to do field testing by putting pieces of TCT in their completion strings. By doing so, the company hopes to build confidence in their product to ultimately benefit the community when the first commercially presentable product is supplied (which is expected by the end of the year).

Looking ahead to this time, de Bakker discussed what markets the company will first be targeting. He said, “At the moment, we are very much looking at competing directly with the nickel alloy market. This is a market worth several billions of dollars in sales per year and when you break these down you can see the majority of oil and gas nickel alloy use is in the Middle East (it covers about half the global market because of the high volume of wells and often very sour conditions). However, we don’t want to stick to that area alone.”

While the critical market is oil and gas corrosive belts, de Bakker suggested, there are also new areas such as carbon capture storage (CCS) which the TCT could thrive in. “Many oil and gas companies are looking to use their old assets for this purpose and the CO2 and other elements could prove problematic for nickel alloys and carbon steel pipes. We are getting a lot of interest from companies in this market who are looking to build their future CCS portfolio, predominantly from North America, Western Europe and Australia.”

In recognition of this, de Bakker noted that the company has recently been awarded a Shell GameChanger contract for certifying TCT for applications in CCUS. The funding is for applications in CCS and Hydrogen. A representative from Shell GameChanger commented, "The Shell GameChanger programme offers the Shell organisation and the industry a reliable and cost effective alternative to conventional technology and contributes to an affordable and reliable low-carbon energy system – CRA Tubulars is part of this with their TCT technology."

Perfect timing

It appears that TCT could not be hitting the market at a better time. First and foremost, the economic squeeze caused by the pandemic is forcing oil and gas companies to pay closer attention to their finances. TCT in the long-term will save capital as the long-serving solution will mean wells can continue to produce for longer and at higher rates without requiring workovers.

Additionally, as de Bakker explained, because of the global political instability, the price of competitor product metals (such as nickel) has dramatically increased whereas CRA-Tubulars’ product markets are much more stable.

“Finally, in the Middle East there is a general push for developing a broader supply chain. A steel plant can cost up to US$150mn for nickel alloy products whereas a factor for ours, capable of producing 50 wells worth of material per year, would cost around US$8mn dollars. For competitors therefore it is more likely that manufacturing locations will be set up and distributed across the world (which brings additional costs and can take a long time) whereas we can have manufacturing fragmented where it is needed. This is very attractive from an in-country value perspective.”

Coming to the market

While de Bakker aims to bring a commercially presentable product to the market by the end of the year, he warned this is not a fixed point and, after that, volume manufacturing is of course a complex process and take time to deliver.

Nevertheless, the CEO is excited for the future and paid homage to his incredible team which has helped get TCT this far, and will no doubt help drive it in the future. Our founder has been in the composite business for more than 20 years and has built a team of shareholders which have a diverse field of experience. We have tried to attract the best in the field – for instance, our carbon fibre expert has a PHD in carbon fibre technologies and has worked extensively in the oil and gas industry for carbon fibre technology in downhole applications.”

De Bakker concluded with a nod to partners which he noted were incredibly important to how the company does and will work. “Independent parties have expertise and the critical structure that we, as a start-up, are lacking and will help accelerate commerciality for our benefit and the benefit of the end users.”

As demonstrated in September last year when the company received the global SPE ATCE rising star award for start up and new technology, CRA Tubulars is offering an innovative product that has the potential to offer so much value to operators. As a result, there is little doubt that many are keeping close watch of the company’s progress towards commercialisation and that it will lack suitors for potential partnerships in the future.

Norwell Engineering, a global well engineering and project management firm, has secured a multi-million dollar contract to deliver an integrated offshore decommissioning project in the UAE on behalf of operator Sinochem Corporation (Sinochem).

Norwell Engineering will develop the abandonment strategy for Sinochem’s UAQ Gas Field as well as detailed well and facilities decommissioning planning, tendering and procurement services, logistics, marine support and operational execution.

Mike Adams, General Manager of Norwell Engineering, said the company partners with client decommissioning teams to address technical, safety, environmental and legislative considerations.

He commented, “While the decommissioning sector is heating up with several well engineering firms active in the space, our experience and technical focus across the entire field provides operators with a different perspective – reducing risks and identifying efficiency savings during every phase.

“The wells are the most complex and costly element of an integrated decommissioning scope and this is what Norwell has specialised in for more than 30 years. Together, with our subsurface partners, and growing topsides decommissioning team, we are in an excellent position to support clients such as Sinochem with end-to-end project management of their integrated decommissioning scopes.”

Sinochem, is a leading, state-owned, player in the global oil exploration and production sector. The UAQ Gas Field was the first offshore gas field independently developed and built overseas by Sinochem. As part of the integrated project, Norwell will be responsible for developing the abandonment strategy, as well as detailed well and facilities decommissioning planning, tendering and procurement services, logistics, marine support and operational execution.

Norwell will then deliver dismantling of the platform equipment before moving the platform onshore, where it will be handed over to the UAE government.

At the Offshore Well Intervention Middle East 2022 conference, representatives from BP provided a detailed case study on their successful rigless abandonment of a well in Block 61, Oman.

Aala Abbas, Wells C, I & I Engineer at BP, opened the session by explaining the background of the operation. She noted that the well was drilled back in 2016, targeting the Amin formation and appraising the northern concession of Block 61. The formation is of tight gas which required hydraulic fracturing to produce, and the well was intervened post D&C immediately where the targeted zone was perforated and break down was attempted. This, however, was unsuccessful and, after attempts were made to re-stimulate in addition to extensive testing, the decision was finally made to permanently abandon the well as part of the oil and gas ministry requirement.

“Conventionally, wells P&A jobs are performed via a drilling rig which is very efficient, has a low-risk profile, is fairly straightforward but costly,” Abbas commented. “Hence, we looked into different methodologies and benchmarked them against the rig option which was projected to take 11 days and a cost of one [given as a comparative figure].”

“The second methodology was a hybrid option where the rig and rigless would be used. It would entail killing the well via coiled tubing before setting a plug and cementing the wellbore via a rig. The P&A job was expected to take approximately 12 days of operation at a cost of 1.23. This is quite high but would save rig time.”

“The other option, and the one we selected, was P&A completely through rigless. The well would be killed via coiled tubing before the setting of the plug and perforation above it would be conducted via E-line. It would then be cemented in the wellbore via the cement unit. The total duration of this methodology was approximately 22 days, and the planned cost was 0.73 with zero rig time. There were, however, disadvantages in it being non-standard, relatively higher risk profile and it was the least experienced method.”

The rigless operation, once selected, was divided into four main stages. The first was to isolate the reservoir by pumping cement via coiled tubing covering approximately 530 metres from the well TD to above the pay zone. BP then tagged the cement to confirm its placement and quality via coiled tubing and, post tag, they displaced the well back to one SG before inflow testing the plug and pressure that up to 8,000 psi. 

The next stage included setting a copperhead bridge plug across the packer to isolate the shallowest reservoir section and then pressure tested to 7,000 psi. Initially they ran with tubing punch but this was unsuccessful and so they ran with 2-7/8” perforating guns, perforating just above the packer to allow reverse circulation later for the cement job. The injection test was successful with a circulation rate of six barrels per minute.

Continuing the presentation, Sultan Al Abri, Wells C, I & I Engineer at BP, commented, “For the third stage we had to confirm that we had sufficient circulation of cement through the perforation and so, to stimulate that, we pumped a high viscous pill which confirmed the circulation and capability to receive cement through the perforations. After that, we reversed circulated the cement from the A-annulus up the tubing while applying positive pressure on the tubing to avoid having cement free-falling from the annulus. The cement was then given time to cure before running slickline tag to confirm the cement placement and the quality of the cement which was successful. 

In the fourth and final stage, the tree was removed, and the tubing and wellhead were cut using a thermal cutter at the surface. The remaining void, from tubing to the annulus side, was pumped with cement using a cement unit with a PVC pipe. After the abandonment the barriers in place included cement across the Amin formation, 15K copperhead bridge plug across the packer depth covering the shallowest reservoir, cement in A-annulus from packer to surface, cement in B-annulus from 13 3/8” shoe to surface, and cement in 4 ½” by 5 ½” tubing from the copperhead bridge plug to the surface.

This was a non-standard operation for the company, and they therefore had some challenges. These included:
• An inability to establish circulation through tubing post tubing punch as the punch tool was not fit for purpose. To remedy that in the future they would select a perforation gun instead. 
• Longer WOC duration as the shallowest section BHST was not incorporated into the lab test. In the future the company would therefore ensure lab tests would be performed in a more representative environment and the cement recipe would be optimised. 
• Incorrect pumped cement volume due to on site pre-job recalculation using incorrect capacities. This could be avoided in the future by ensuring all changes to the programme are managed by MOC process. 
• Inability to cut the tubing due to an inadequate gas weld cutter. The lesson learned from this was to use the plasma cutter for tubing cut. 

“Despite the challenges, we delivered the abandonment job with an extra one day than planned but with a 27% less cost than initially expected. For individual service lines we had well testing delivered at about 90% of the planned cost at eight instead of ten days duration; slickline was conducted at the right cost but took an extra half day; coiled tubing was delivered at 65% the planned cost and ran for three and half days instead of five; cementing was completed at about 60% of the projected cost at approximately the same amount of time; and tree removal took the same amount of time as expected,” Al Abri concluded. 

“The only service line that we exceeded the planned cost and duration was E-Line and that is attributed to the NPTs mentioned earlier where extra runs were required.”

At the Offshore Well Intervention Middle East 2022 conference, Mustafa Adel Amer, Senior Petroleum Production Technology Engineer and Well Integrity Management at BAPETCO, guided the audience through an expert case study focused on well production and methane abatement.

Adel Amer began by explaining the latest goals set out to reduce methane emissions whereby, at COP26, more than 100 countries signed the global methane pledge to cut methane emissions by 30% by 2030. Methane emissions are now at the centre of climate discussions and the abatement of them is, and will become, key to the competiveness of fossil fuels in the future.

The upstream sector, Adel Amer continued, is assumed to contribute around 80% of the methane emissions in the industry, with the majority of this coming from venting operations. Given the global desire to abate methane emissions, it is therefore of paramount importance for operators to reduce this without affecting production rates.

In pursuit of this, Adel Amer presented a case study from his company which focused on treating liquid loaded gas wells in a method that reduced methane emissions and saved significant money.

Adel Amer said, “Liquid loading in a gas well is the inability of produced gas to produce the entrain liquids from the wellbore. Over time, gas velocity decreases and liquids in the well will impact the lift performance that reduce or even stop gas production.”

“Turner discovered the liquid loading could be projected by a droplet model illustrating when droplets move up or down depending on the velocity relative to a critical velocity.”

Adel Amer explained that is common to use VLP to diagnose liquid loading where, in practice, critical velocity is generally defined as the minimum gas velocity in the produced tubing required to produce with low probability of liquid loading risk.

“With the Turner approach, the droplets accumulate in the large ID section but bubble flow takes place at the very low gas flow rate, you need very low gas rate usually at the far left end of the VLP curve. In many cases you don’t see the size of liquid columns that you would expect to balance the drawdown when the well is shut in for cycles.”

Mustafa, in his presentation, presented technical analysis showed that wells that operate in their unstable, hydrostatic dominated, part of their VLP suffer from increased liquid holdup along the entire well.

“We therefore need to focus on increasing velocity across the entire well,” Adel Amer remarked.

In order to do so BAPETCO showed a solution performed on an old well located in an onshore gas field with over 10 wells suffering from liquid loading and run under manual unloading cycles. The well chosen was an old one, beyond 17 years of operation, which had a five inch completion. The task was to end the cyclic behaviour of wells to increase production and eliminate methane emissions.

Considering the context of the field and the company in terms of near wellbore damage after well killing and the well integrity manual that mandate having operable sub-surface safety value in all gas wells, the best solution as Adel Amer said, “was to run a velocity string without killing the well while maintaining the sub-surface safety valve operable and without reliance on a snubbing unit.”

They began by conducting surveillance to select the best candidate wells through in-house developed python code that analyse reservoir data, production data, well history, and well integrity history to gain insightful analytics of the well integrity failure history, potential gain, clearance of the well etc. They then selected candidates and examined the potential in terms of possibility of success and expected gain.

Once done, they went to the PIPESIM to model the surface network and make sure production gains coming from fixing the intermittency of the gas wells would not be constrained by network capacity or connection with other high pressure wells in the network. 

The modelling results indicated that inserting 2 7/8 inch completions reduced the risk of liquid loading over the completion string and maintained liquid loading velocity ration favorable for stable gas production.

In practice, to run the velocity string without killing the well, without snubbing units and while having operable sub-surface safety valve, the operating included:
• Rigless inspection of the existing five inch completion and settling an isolation packer with surge disk.
• Workover to run the 2 7/8 inch and set an upper packer below the sub-surface safety valve. 
• Rigless coiled tubing to unload the brine and break the surge disk. 

Adel Amer said, “This was completed successfully and the project converted the well from one with a fluctuation intermittent behaviour to a more stable state. The stability of production increased to 2.5MMSCF/D after applying the velocity string, up from a 1.5MMSCF/D the day before the project.”

The project helps to achieve various positive results including:
• Cost reduction: the cost of using workover rig to run the 2 7/8 inch tubing inside the existing 5 inch completion was only 10% of a snubbing unit with payback time of 5-6 weeks.
• Increased the gas production rate by 1.5 times and condensate production by 3.8 times.
• The monthly reduced GHG emissions per well is equivalent to 4.4mn miles of passenger vehicle emissions. 
• Reduced workload on production operations from elimination of manual unloading.
• Maintained compliance with well integrity standards.

Abel Amer concluded, “We now have a new way of dealing with intermittent gas wells which is less expensive, does not kill the reservoir and maintains an operable sub-surface safety valve. Even though liquid loading is a dynamic process, using PIPESIM provided very useful clue to estimate the liquid loading velocity ratio which was among the main design parameters.”

Abel Amer can be contacted through his LinkedIn profile here. 

Marine and lifting equipment specialists Motive Offshore Group (Motive) and subsea and decommissioning equipment rental specialists Hiretech Limited (Hiretech) have joined forces to bring superior technology and service solutions to the Middle East.

Motive, with its UAE hub and existing catalogue of subsea marine and lifting equipment services, is bolstering its current suite with Hiretech’s extensive rental fleet of decommissioning and subsea technology, bringing much-needed consolidation and in-market offshore services support for the region.

Graeme Chalmers, Regional Manager Middle East at Motive Offshore Group, commented, “Having worked with Hiretech for many years, we’re thrilled to formalise our partnership. Harnessing our skills and insights, developed in-step with Scotland’s trailblazing strides in the oil & gas and offshore wind markets, we understand the importance of market consolidation when it comes to keeping costs low and are looking forward to offering greater levels of support from our Middle East base.

“2022 is a big year for Motive. This partnership marks the next stage of our journey, and we are looking forward to continuing to expand our global footprint through increasing sales by 15% in this key region.”

Along with the technology and equipment, Hiretech will also deliver a comprehensive training programme to Motive’s engineers and technicians, enabling seamless delivery of products and technical support.

Andy Buchan, CEO, Hiretech Limited, remarked, “Hiretech has historically served the Middle East region from the UK. This new Middle East partnership puts our equipment in country, significantly reducing mobilisation times and costs for our Middle Eastern clients, with the additional advantages of utilising the extensive commercial, logistical, technical and equipment support available from the Motive FZE team.”

In a unique case study, Thunder Cranes has explained how it provided lifting support for coiled tubing operations in offshore Dubai, UAE, with cranes designed for portable use and ease of assembly & disassembly on offshore installations. 

During planning for the coiled tubing operations it was determined that there was insufficient space to accommodate all of the coiled tubing equipment on the platform deck that was located directly over the wells identified for intervention.

As a result Thunder Cranes needed to make use of an adjacent platform, located 50 feet away, and so the company designed a lifting plan using two cranes and both platforms to carry out the lifting support required for the project.

For the purposes of the case study, they were named "Platform A" and "Platform B" and the company provided a summary of the steps carried out:

• Using the existing platform jib crane Thunder Cranes lifted the component parts of the 20 ton crane (TC20) from supply vessel to Platform A.
• Once TC20 was rigged up and load tested it then lifted the component parts of the 90 ton crane (TC90) from supply vessel to Platform A.
• After the TC90 was rigged up it rigged down the TC20 and lifted all of the TC20 components from Platform A to Platform B.
• TC20 was then rigged up on Platform B.
• TC90 was able to pick up the coiled tubing reel, with a long enough boom to be able to hook to the coiled tubing pipe and pull it over from one platform to another to be run through the injector.
• Over on platform A, working in tandem with the TC90, the TC20 lifted, rigged up, and helped support the coiled tubing injector.

In the case, the company rigged up and load tested two days within seven days thank to the TC clamping method, the modular design of the cranes, and the highly experienced staff. 

In the project, TC20 and TC90 cranes enabled the coiled tubing work to begin ahead of schedule and was a safe & cost effective solution compared to alternative methods.

Claxton, the lead brand of Acteon’s drilling and decommissioning segment, is set to acquire decommissioning personnel and assets from Oceaneering.

The agreement was signed recently with the anticipated closure date of 30 March, 2022. Certain staff in Norway will transfer to Claxton, along with decommissioning assets, including well and pile abrasive cutting and recovery systems and associated tooling. Also included in the deal are conductor drilling, pinning and cutting systems, diamond wires saws, dredges and various ancillary equipment items. This equipment will initially be deployed from Acteon’s bases in Norway, Dubai and Aberdeen.

In addition, Oceaneering is establishing a master services agreement where Claxton will provide services to support the company’s wider scopes. This could potentially include its multi-client Rig Chase decommissioning campaigns.

Sam Hanton, Acteon Drilling and Decommissioning Segment Managing Director, commented, “The deal will increase our capacity, the range of technologies at our disposal and our decommissioning expertise, and reinforce Claxton’s position as one of the leading global suppliers of offshore cutting services.”

Luke Pirie, Director of Offshore Projects Group, Oceaneering, added that the deal allows the company to strategically focus on its integrated solutions offering while ensuring access to decommissioning services through a partnership and the new master services agreement with Claxton.

Jordan Whyte, Head of Commercial & Business Development at Gulf Marine Services (GMS), explained to Offshore Network how the company is facilitating more efficient heavy well intervention operations to save time and costs.

In the Middle East, attention is firmly fixed on increasing production. While the energy transition has threatened to shake confidence, key players have reaffirmed their faith in the oil and gas market in the years ahead by looking to increase production – Saudi Arabia’s Aramco has signalled its intention to increase oil production to 13mn bpd (up from 12mn bpd) and ADNOC is aiming to boost capacity to 5mn bpd (up from 4mn bpd).

Within the region, Whyte explained, one of the most favoured ways of increasing production is to workover existing wells using the likes of jack-up barges to re-stimulate wells in shallow waters. It is for this reason that of the 12 barges GMS currently has in the Middle East, around half are presently engaged in some form of well service operations (there is another barge in the North Sea working in renewables).

“Covid-19 dramatically delayed a lot of contracts of course but, subsequently, these have been reactivated. Now it is in overdrive, driven by these production targets and allied to the large population of existing shallow water platforms; the simplest and most efficient ways to reach these is by using jack-up barges. While we are not downhole engineering experts, we are the medium to carry out these operations and currently have high utilisation levels due to the production boom,” Whyte said.

GMS’ Evolving Capacity

Standing apart in GMS’ fleet is the Evolution self-propelled, self-elevating well intervention barge which was commissioned back in 2017. Fitted on board is the bespoke cantilever workover system, delivered in collaboration with Norwegian-based Dwellop.

This unit skids hydraulically from the main deck of the barge out of the back end for the best part of 50 ft; has a light weight drilling derrick that comes complete with top drive system; and has a high level of automation such as a pipe handling system that will pick pipe up off the deck and feed into the top drive before running in hole. There is also an automated iron roughneck on board and everything is run from a driller’s cabin on the side of the unit so that pipe can be tripped in and out of the well at significant speeds (up to 1,000 ft an hour). Below the deck is also a full Mud System with everything normally associated with a drilling rig; enhancing the vessel’s capacity.

Whyte remarked, “In a sense it is very similar to a jack-up rig but it is a hell of a lot lighter and thus can skid out over a platform much faster (typically only 30 minutes). There is some transverse movement which means we can also skid left to right in order to workover adjacent wells without having to necessarily move the barge itself. When we do have to skid back, rig down and move elsewhere, we can typically do so and be ready to work at another location within 24 hours. This is significantly faster than a jack-up rig for example which can take the best part of two to three days and even more if the weather is poor. Not to mention the fact no tug-boats are required to get it to the next location due largely to our clients comfort operating Evolution in DP-2 mode when approaching platforms. As a result, the Evolution can workover up to three or four times as many wells per year compared to a typical non-propelled drilling jack-up in any given field.”

“We are trying to bring down the costs of all brownfield workover operations and the Evolution offers flexibility and cost saving due largely to the superior marine efficiencies.”

The Evolution was purpose built for P&A and workover scopes but can also perform some drilling operations. Whyte noted that it is really only limited by the amount of tubular piping that can be carried on deck (and a few others such as top drive torque capability and hook load) and the 200t crane on board means it even has the ability to remove small jackets although that has not been done to date.

In once case study provided by GMS, the Evolution was contracted by an Arabian Gulf NOC for a well intervention scope covering various operations. The barge jacked up alongside a similar vessel to transfer well services equipment (which was moved across and commissioned in a record two days) before sailing to the platform tower, jacking up and deploying the cantilever system. The unit was ready to commence operations with three hours (saving 90% rig time) and rig up of well services equipment was completed in 31 hours (achieving 15% time saving). Following this, rig down of well services and preparation for the barge to move was completed in just 14 hours.

On the Horizon

Currently the Evolution is performing legacy work for Qatar Energy (QE) on a field which was previously operated by Occidental Petroleum for around 25 years. The former owners used a more traditional method of workover which QE continued until GMS suggested that the Evolution would be more efficient. In the 18 months since then, the Evolution has been proving its worth and this is without even reaching its full potential.

“In truth we are not even at the stage where we are using Evolution at 100% of her capability but we are certainly working towards that. As it gets more tried and tested and both the crew and client gains confidence, we will be more prepared to tackle more difficult workovers and remediation projects. But it is fair to say that, so far, it is going well and QE appreciate the marine efficiencies being achieved,” Whyte noted.

Pushing, the Evolution to greater heights is just one of the targets on the horizon for GMS, Whyte continued. The company has recently taken a big step in its digital journey by signing a contract to install an enterprise resource planning system which will provide the company with an interconnected system across its operations, giving it the ability to upgrade internal procedures; integrate vessel operations, maintenance, procurement and inventory control, alongside crew and payroll management; and centralise data for better visibility. Whyte surmised that while it will not be fully up and running for a couple of months yet, the company has already started to feel the benefits (most notably in the real-time communication between offshore and onshore) which is a promising sign for the digital road ahead.

Another exciting development is through the delivery of a lighter cantilever system which the company is looking to push across the line for commercial use. This is, as it says on the tin, a lighter version of the system which can be used for all well services which do not require tubing to be pulled from the well.

Whyte said, “It can skid out just as far and can be retrofitted to existing vessels. There is a lot of interest from NOCs for this and we are looking for more opportunities for the cantilever system and its lighter cousin. As the rig rates continue to rise and move away from barges, we think our offerings will become increasingly more attractive to operators for both heavier and lighter workover operations.”

Finally, Whyte concluded by noting that the company is keeping an eye on other regions for which its fleet could be deployed with regard to well service and workover operations.

“West Africa is finally waking up to well servicededicated barges; in the North Sea there is some increased activity in terms of P&A; and there is interest from regions such as Asia and Australia to bring in some of our barges. The Evolution is capable of operating anywhere with water depth of around 70m and has proved herself in other regions such as the North Sea before,” Whyte continued.

“We put no barriers on where we work as long as the economics work out. That being said, such is the boom and demand here that, at the moment, we are very focused in the Middle East region. The Evolution itself has been working in Qatar for the last two years and fingers crossed we expect her to continue there for some time.”

OWI ME 2022

GMS will be speaking further on this at OWI ME 2022 on the 28-29 March 2022 in Dubai, UAE. Register here or reach out to Rachael Brand on the details below for more information:

Rachael Brand

Project Manager, Offshore Network

t: +44 (0) 20 3409 3041

e: This email address is being protected from spambots. You need JavaScript enabled to view it.