West Africa

In March 2021 a panel of industry experts met to discuss the challenges and opportunities of riserless light well intervention (RLWI) in sub-Saharan African (SSA) and, half a year on from that spirited debate, as part of the Offshore Well Intervention West Africa 2021 conference the party reconvened to discern if anything has changed.

Sola Adekunle, CEO, Cranium Engineering reprised his role as host and began by outlining some global changes to the oil and gas market in this time. He noted that in November 2020 oil prices were sat at US$37 per barrel, rising to US$63 on 1 March. At this time, boarders were still more or less closed, lockdown restrictions were still in place and generally Covid-19 was having a huge impact on business.

Six months on, the pandemic is still here but with the distribution of vaccines in full flow the world has opened up, industries are recovering and, as of 4 October, oil prices had climbed to US$82.95 per barrel.

RLWI in a recovering market

During the last session the panellists explored the benefits of RLWI by commenting that operators can achieve the majority of their objectives at a much lower cost and this presented a significant opportunity to capture the low hanging fruits of oil production. Since then, Adekunle asked, has this been recognised in SSA? And has the region adopted this method of well intervention to alleviate it’s rapidly ageing well stock.

New member of the panel Paul Stein, Commercial Director of Baker Hughes, said, “Globally it is a bit mixed in terms of RLWI despite the oil price going up. We are certainly seeing more tendering and early engagement with clients in this space but there is a split in customers. Tried and tested customers have RLWI in their core business and some are consistently undertaking such campaigns.”

“However, particularly in West Africa there is a delay in operations taking place which is maybe a reflection on the downturn of capability and knowledge within untested companies. It is also a significant investment for operators to pitch internally and many companies do not have that pot of money set aside for interventions. Now is the time to support clients to realise the production gains that can be achieved; particularly in West Africa which has an ageing well stock. I believe RLWI has a big place in the region.”

While there has been hesitation to undertake RLWI campaigns, this has not been the case with BP. Matthew Vick, Senior Subsea Wells Engineer, BP, explained that his company had continued with these operations and had just wrapped up a campaign in Angola. For the future it had already started the leg work for another campaign in the future alongside major campaigns in the Gulf of Mexico and the North Sea. For his company, “Light well intervention has become a routine operation at this point.”

Feyisola Okungbowa, Executive Director, Baker Hughes, added that there was definitely a lot more upfront activity but this was not, as yet, really translating into actual business in the region.

She said, “We do have some operators in SSA executing currently but with the ageing stock that we spoke about last time the coverage is still not there compared to other regions. With the improved oil price we are having discussions on more oil creation and yet I am still wondering why we are not seeing the market use light well intervention ‒ a low hanging fruit which can be used to boost production.”

The panellists noted that perhaps there was an unrealistic expectation for this uptake to happen quickly and, in reality, senior executives need more time to truly understand the benefits of light well intervention. This education journey has not been helped by the long pause of operations during Covid-19.

Encouraging RLWI

With the challenges listed the panellists then turned to discussing how they can be mitigated to encourage more campaigns of this nature in the region. Picking up on education, Vick noted that the benefits of RLWI can be conveyed by communication within the industry. He said, “We love sharing out lessons and we like it when other operators share theirs. The more something is used the more efficient it becomes and this will drive uptake.”

In this vein, collaboration is also high on the list. Intervention campaigns can be very costly for less developed regions such as West Africa as often specialised equipment must be brought in and this might prove not economically viable if only a few wells are targeted. However, the panellists explained, this expenditure can be cut if split between several operators partnering on the same campaign. This would also result in longer campaigns which would, the longer they go on, drive efficiency and thus capture more value: Vick noted that the biggest return on value is usually achieved on the 5th/6th well onwards when engineers start to work through the kinks.

To achieve this, contracting strategies are paramount. Another new member, Vidar Sten-Halvorsen, Subject Matter Expert-Well Intervention at Havfram, noted, “It is important to have a clear agreement up front on who is doing what and how they are going to work together. Agree on contractual issues early and then everyone is in the same boat with the same agenda.”

Vick added, “A one-team mentality is critical and having that formally defined is very important. Make sure everyone is on the same page, has their relationships clearly defined and agree to it up front.”

Stein commented that Baker Hughes has a great track record in SSA with countries such as Ghana and is capable of conducting operations in other waters across the region as well. He noted that his company is more than happy to work with other service companies in order to unlock the RLWI commercial potential that SSA holds.

Okungbowa added that their local content strategy is second to none after spending the last three years training up local engineers. Because of this they have a great foundation from which to execute operations cheaper and faster, avoiding the need to bring in too many external personnel.

Finally, the panellists explained that with so many energy companies placing climate concerns high up on their agenda, light well intervention has the potential to help operators maintain production at a reduced carbon footprint.

Sten-Halvorsen said, “This is becoming more and more important from an operator point of view ‒ the footprint left behind after operations. Lighter vessels have lower fuel consumption and it is something that is really favouring this approach over the use of heavier units.”

A brighter future ahead?

Despite not as much uptake in the last six months as was expected, the panellists remained positive about the future of RLWI in SSA.

Sten-Halvorsen concluded, “Africa is the next big thing for well intervention and there is a huge price to win here going after intervention in West Africa.”

Stein added, “My aspiration is to be in a position to conduct multi-well campaigns in West Africa utilising the potential of light well intervention. The region could go from a place not really using this method to one that is driving. It has the potential to do that.”

Concluding another insightful session, Adekunle simply said, “It is the way to go. It is the future.”

At the Offshore Well Intervention West Africa 2021 conference, Ejimofor Agbo, Senior Completions Engineer at Newcross Exploration and Production, presented a case study outlining his company’s new approach to wax removal.

Ejimofor began by commenting that wax production presents one of the most challenging flow assurance issues when not addressed in the well completion design stage. The problem occurs when paraffins precipitate when the production system temperate falls below the wax appearance temperature (WAT). The resulting wax deposits that form can cause blockages which reduce production rate and flowing tubing head pressure and, in some cases, can take production from 2,000 barrels down to zero.

There are three conventional methods of solving wax problems, but each has inherent issues:

-Mechanical: Utilises wax cutters and scrapers for cutting the wax and also scraping it off the metal surfaces of the tubing. This is widely used and is cost effective initially but over time it can be needed at more frequent intervals which increases the cost and risk.

-Thermal: Downhole electric heaters are used to improve the heat retention capability of the crude so that its temperature remains above the WAT. A useful solution however there is a number of associated challenges such as availability of power sources offshore, the heating up of tubulars and formation damage.

-Chemical: Utilises chemical solvents to dissolve the wax molecules and allow the crude to be flowed to the surface. The problem with this solution is it has to be treated on a case-by-case basis which means information about the reservoir must be known and it can be costly overtime. There are also issues around availability of chemicals and initial completion design to accommodate for chemical injection valve

These are the standard wax removal methods but, Agbo continued, there are alternative approaches to wax removal, you just need to be able to think outside of the box.

An alternative approach

This is how Ejimofor and the team approached one of their wells suffering from acute issues with wax deposits which he presented to the OWI WA attendees in an informative case study.

The AK-40 Well, located in an ageing field, was completed in 1992 in two non-waxy reservoirs. However in 2005 the well was recompleted as the only drainage point in X1.0 reservoir containing waxy crudes with no provisions taken to cater for wax deposition. When the well was opened in 2006 it had an oil production rate of 1,142 BOPD but subsequent production gave 1,100 BOPD with intermittent wax cutting required every six months. The start-up rate post-wax cutting activity continued to drop and the duration of production dropped from six months to three months and continued until it only lasted for a month after wax cutting intervention.

Ejimofor said, “This called for a more effective wax mitigation strategy. We needed to do something different and think outside the box to resolve this issue.”

This began with laboratory analysis by which they discovered that a solution of 60% xylene and 40% diesel was the most effective at dissolving the wax with 98% dissolution achieved. Additionally, through an oil sample, they discovered the WAT was around 91.4⁰F while a dynamic model indicated the WAT was between 94⁰F and 95⁰F. Finally, through a bottom hole pressure and temperature survey they found that the estimated depth of wax precipitation was established at 3,300 ft which corroborates with breakthrough depth in previous wax cutting interventions.

With this information, the company then turned to deciding which alternative wax removal methods they should utilise, with two available.

The first was the Wax Inhibition Tool (WIT) comprising of nine dissimilar metals combined to form an alloy. This tool acts as a catalyst which enables a change in the electrostatic potential of the fluid. It changes the electrostatic potential and produces a polarisation effect at the electron level of the molecules which prevents scale formation, corrosion of metal and paraffin wax deposition. Crude is sucked into the holes in the tool and when in contact with the alloys to break up the long chain hydrocarbon molecules thereby making the oil ‘slicker’ and flow better.

Ejimofor added in some places they call it “the wonder tool”.

The other option was a Capillary Injection System which injects chemical solvent downhole to aid in the dissolution of wax molecules and allows the crude to flow to the surface. This can only be internally installed in the tubing string and can be used in various applications including liquid loading, scale control, salt control, corrosion control, and more.

The company compared the two and, in this application, found that the Capillary Injection System was not as viable as it would require a complex deployment, multiple items would be POOH, there was a high risk of plugging, it required preventative maintenance and there would be a high installation cost.

On the other hand, the WIT had an easy deployment, only one piece would be POOH, it carried a low risk of plug, there was low maintenance required and the cost of installation was lower. It was therefore the clear choice.

Execution and results

With their solution chosen Newcross turned to the next stage and carried out tubing integrity via mechanical wax cutting on slickline followed by wellbore clean up with solvent soak (of the xylene/diesel solution) across the entire wellbore. This ensured that before the WIT was installed the entire wellbore was cleaned of wax deposits. They then ran inhole and installed the WIT at 4,000 ft (600 ft below the WAT depth previously discovered).

Ejimofor commented, “Since we have done that, in the past eight months production has been the same and we have not needed to cut wax in this time. It is flowing on its own and management has been very happy with the results.”

At the Offshore Well Intervention West Africa 2021 conference, Todd Parker, CEO of Blue Spark Energy, explained how his company has developed a technology to utilise rapidly compressed, low-energy pulses to clear impediments in wellbores.

Since its first operation in 2011, Calgary-based Blue Spark Energy has focused on the electrification of intervention processes, including a new wireline tool that utilises compressed energy to generate a pulse for use in well intervention applications.

BlueSpark Technology utilises high-pulsed power by compressing electrical energy to create high power events. Abandoning the traditional use of power in well bore solutions, Blue Spark's solution reduces the amount of time energy is utilised in, thus increasing its output. As energy is further divided among smaller increments of time, power outputs become significantly larger.

The wireline solution utilises apprxoimately 1 kilojoule of energy compressed into a millionth of a second. This means that every time a tool is used, around 200MW is generated in a power pulse- manifested in a shockwave that can clear impediments, scale, organic materials or blockages. As well as impediment clearance, the wireline tool can be used for production stimulation.

Coaxial cables are often used for this application, with an external energy source supplying approximately 1 kilojoule (around two mobile phone batteries worth of power for an entire treatment).

Involving only a coaxial cable and power source, the solution has practically zero environmental impact, and offers a low-cost and low-footprint intervention compared to alternative methods, tackling several downhole challenges in wellbores.

Blue Spark Energy began its first operation in September 2011 and in that time it has been building up a track record to show the market that this is an effective and trustworthy tool which can solve a number of problems in the wellbore. Since 2011, the company has implemented more than 600 operations worldwide for more than 50 different companies.

Parker explained that of these 600 operations the company has acquired data from 267 oil wells. Of these, there was an average oil production increase of 262%. BlueSpark also collected data for 45 injection and disposal wells and the average change in production was a staggering increase of 413%.

In addition to being an effective tool for any type of well (including some applications within the geothermal space) Parker noted they have been working with some companies in their decommissioning operations. In this regard, the BlueSpark tool can be used for cleaning the casing prior to setting a barrier to improve the chance of it setting and sealing. This can reduce well abandonment costs by as much as 60% in complex cases and at least 20% in simpler cases.

Parker noted, “We are continuing to innovate and improve this technology. We think it is an excellent technology. This is a go-to solution and has a high degree of reliability in removing impediments affecting wellbore performance. We are now accepting more and more orders for it and we have multiple projects on the go today.”

VAALCO Energy, Inc. (VAALCO) has completed two workovers at the Etame field offshore Gabon and added a total of approximately 1,050 gross barrels of crude oil per day.

As part of the campaign, VAALCO’s hydraulic workover unit (purchased in early 2021) was utilitied to rapidly mobilise and replace electrical submersible pump units. It was able to do this more efficiently than a drilling rig, which had cost saving benefits.

The longest producing ESP unit at Etame was replaced and upgraded in the workover of EEBOM-2H which increased production from about 500 gross BOPD (255 BOPD net) to approximately 1,400 gross BOPD (715 BOPD net).

Additionally both the upper and lower ESP units at the ET-12H well were replaced and the ESP design was configured at the same well. This restored production to 1,800 gross BOPD (920 BOPD net), an increase of approximately 150 gross BOPD (80 BODP net) compared to the average rate prior to the workover.

George Maxwell, VAALCO’s Chief Executive Officer, commented, “We are pleased with the results from these workovers, in particular, the 1,050 gross BOPD of additional production. We purchased the mobile hydraulic workover unit earlier this year to allow us to quickly and efficiently react to ESP failures and to proactively prevent ESP failures as we deemed necessary.

“This allows us to maximise production and even incrementally increase production, which is particularly attractive in the current price environment. We will continue to efficiently operate at Etame which generates strong cash flow to fund our accretive strategic initiatives.”

At the Offshore Well Intervention West Africa 2021 conference, Rafael Bastardo, Vice President of Global Sales, Silverwell, outlined his company’s Digital Intelligent Artificial Lift (DIAL) system, designed to eliminate production uncertainty, instabilities, deferment and operational costs.

As Bastardo explained, gas lift production optimisation is crucial to the future of the offshore oil and gas industry enabling operators to capture real value on their associated assets. ExxonMobil, for example, stated that they evaluated a 22% average oil gain using an optimised gas lift programme.

Traditional legacy Injection Pressure Operated (IPO) gas lift systems (in use for a long time within the industry) have narrow operating windows, injection depth limits, difficulties in assessing lift effectiveness, requires intervention to optimise, and is very sensitive to well dynamics. For this reason, Silverwell developed and released the DIAL system.

DIAL is a production optimisation system which integrates in-well monitoring and control of gas lift well performance with surface analytics and automation. Each DIAL unit has up to six independent injection orifices (with different port sizes) which can be individually opened and closed from the surface without requiring a drop in casing pressure. The suite of tools is connected to the surface via a tubing encapsulated conductor (TEC) that provides power and communications. This allows for continuous optimisation of gas lifted fields, remotely and without intervention.

To mitigate the challenges experienced by legacy IPO systems, DIAL boasts keys features such as patented binary actuator technology; variable orifice size at any depth; pressure, temperature and flow data; remote monitoring and control; intelligent field-wide management; and no deviation limitation.

These allow operators to capture key benefits such as:
-10% to 40% uplift
-Reduce +20% gas consumption
-Mitigate instabilities
-Deeper injection
-Reduce OPEX by 20% to 30%
-Reduce HSE risk
-No deviation limit
-Multi-million dollar NPV increase
-Eliminate intervention (does not require slickline to operate or adjust).

Unit Specification:
-A collapse pressure rating of up to 6,000 psi, with a 7,500 psi pressure rating coming soon
-10,000 psi burst rate pressure
-125 degrees Celsius max rated temperature, with a 150 under development and testing
-Concentric and slimline profile
-Multiple units per well
-Binary Actuation Technology
-Maximum choked flow rate of 6mmscfd/unit
-Electron Beam welded construction.

Bastardo noted that operators can acquire real time data from each unit, control each valve independently through a sophisticated surface control system and see key information such as the status for injection rate velocity, critical flow indicators and recent events that occurred during logging operation. Operators without SCADA can use radio or satellite communication to send the DIAL system data directly to cloud services which can be accessed remotely.

Silverwell are currently in the process of advancing the technology even further and will soon release units with a fully automated gas lift production optimisation system, drawdown control and water cut management and mitigation of injection pressure instabilities.

A reliable solution

The technology is relatively new (came into the market in 2016) however the trial phase is now complete and there are 15 wells installed with DIAL units globally. They are expected to be installed in 23 wells offshore by Q1 2022.

DIAL units are designed for a lifetime of over 10 years and, Bastardo added, the estimated savings from eliminating intervention was “immense.” He presented several business cases where, in each case, the technology had been very well received by the operator and had achieved substantial returns on investment.

Bastardo added that the best candidate for this technology were those with high frequency or high-cost interventions, assets with dynamic reservoir conditions, deviated wells and ones with constrained surface injection capacity.

In 2022, Silverwell is looking at releasing the system for subsea applications with pressure rating of 10,000 psi.

In the build-up to the Offshore Well Intervention West Africa conference, Offshore Network spoke to Silverwell Energy, a global provider of Digital Intelligent Artificial Lift (DIAL), as the company prepares to deploy its first systems to the region in 2022.

Explaining the inspiration behind the solution offered by the company, which will be making its way to West African waters soon, Abdel BenAmara, Vice President for Silverwell’s Middle East and Asia Pacific regions, stated “The majority of the world’s gas lifted wells are under-optimised. This incomplete production optimisation, coupled with excessive intervention costs and risks, presents an opportunity to re-imagine gas lift well design and operating principles. It has been estimated that addressing this opportunity delivers a production uplift approaching 20%. Optimising gas lift systems with existing technology is typically time consuming, costly and risky.”

BenAmara elaborated on the subject of well intervention and commented that frequent interventions are required with associated lost and/or deferred production. Traditionally it was not possible to make on-demand in-well adjustments to gas lift injection depth and rate to address these challenges. Further, it’s not easy to make data-driven decisions about these adjustments to assure continuously maximised and stable production.

Silverwell has therefore sought to overcome the production constraining limitations of existing gas lift technology with the development of their digital in-well integrated interventionless gas lift optimisation system called DIAL (Digital Intelligent Artificial Lift).

BenAmara continued, “The system consists of multiple DIAL units, tubing conveyed and installed along with the tubing string during a workover operation. Each DIAL unit can include up to 6 independent injection orifices, each individually controlled from the surface, with a large spectrum of gas injection rates. The operator can vary the gas injection rate by opening or closing valves, in any combination, which can each have a different port size, giving the operator a huge range of possible injection rates.”

“The system is controlled by a Surface Control System (SCS), connected to all DIAL units, in a multidrop configuration through a single downhole electrical control line (TEC) which is typically ¼” in diameter. DIAL units are spaced using maximum available surface gas injection pressure, without any pressure drop required between each station, since the opening of the valves are digitally controlled and not impacted by downhole pressures or temperature. The upper units in the completion are typically used for well unloading requirements and the lower units are the operating units - used to adjust gas injection depth and rate based on reservoir pressures and other well parameters. Each DIAL unit is also equipped with pressure and temperature sensors giving full visibility of the well’s downhole conditions.”

DIAL systems in operation

DIAL systems were successfully installed in America, Middle East and Asia Pacific regions, and these deployments resulted with average oil production gains of 10 - 20% for single string completions and 40%+ for dual string completions. Other benefits also included gas consumption reductions and significant OPEX savings by avoiding intervention costs typically required for gas lift operations.

Silverwell will be deploying its first systems offshore West Africa in 2022, with a Major IOC, marking the start of its operations in the region, with ambitious development plans beyond these initial deployments.

BenAmara added, “This disruptive technology has the potential to revolutionise gas lift operations in West Africa, which is one of the major artificial lift techniques used in the region. By digitising gas lift operations, and eliminating well intervention requirements, it will enable gas lifted wells to reach their full potential.”

To hear more about the offshore well intervention opportunities and challenges in West Africa, follow this link: https://offsnet.com/owi-wa

About Silverwell:

Silverwell is the global developer, manufacturer, and installer of digitally intelligent gas lift production optimisation systems for the oil & gas industry. They are a leader in automation of gas lifted production and apply patented technology so that more data for less uncertainty in production management decisions enables more production with less intervention.

Silverwell is certified to ISO 9001:2015 Quality Management System and ISO 45001:2018 Occupational Health & Safety.

Expro, a leading international oilfield services company, has successfully completed an integrated plug and abandonment (P&A) contract valued at more than US$20mn for a subsidiary of PETRONAS, PC Mauritania 1 Pty Ltd (PCMPL), which manages offshore operations in Mauritania, West Africa.

The well intervention scope of the P&A project utilised Expro’s integrated Open Water Intervention Riser System (OWIRS) for successful intervention and barrier placement on 15 wells for PCMPL’s Chinguetti Field Phase II works. The system’s compact nature provided considerable time savings by retrieving the subsea trees without an additional run. This was further enhanced by the efficient parallel deployment of the OWIRS and rig blow out preventor from the auxiliary well and primary well centre through the rig’s dual derrick capabilities.

Expro’s onshore project management team, based in Kuala Lumpur and locally onshore in Mauritania, supported PCMPL throughout the project planning and execution phases. Expro provided a range of integrated services, including the subsea well access system, surface flowhead, umbilicals, topsides control equipment and installation and an intervention workover control system (IWOCS) package for controlling both the OWIRS and Xmas tree systems. Worldwide Oilfield Machine (WOM) worked closely with Expro as an alliance partner providing the subsea well access system and a technical support team.

Graham Cheyne, Expro’s Vice President of Well Access and Subsea, commented, “The OWIRS system is a highly reliable compact system with an extensive track record in riser to surface subsea well access operations. This system performed over 250 functions during the project with 100% operational uptime and no non-productive time (NPT) incurred. To further demonstrate its reliability post operation, a gas testing programme of work was successfully performed on completion of the 15 wells, prior to any post job maintenance being carried out and before readiness for the next project.

“This campaign was our first venture into the intervention riser system market. Despite the logistical and HSE challenges created by the global pandemic, we are proud to have demonstrated our technology’s success and integrated ability for these types of subsea P&A operations, supported by our team’s extraordinary performance, commitment, flexibility and dedication to PCMPL.

“The campaign’s success, combined with our continued expansion of our subsea well access offering, has helped us to secure several new contracts across Asia and Australia, enhancing Expro’s already strong presence in the subsea well access market.”

Sustained growth expected

Expro’s second quarter results show that the company delivered solid financial and operational performance, including 13% sequential revenue growth globally, and particularly strong growth in its Europe and sub-Saharan Africa (ESSA) and Asia regions, as demand increased for production optimisation services.

Mike Jardon, Expro’s CEO commented that the company is seeing “strong signals of a multi-year recovery” and is expecting sustained growth across all of its businesses and geo-markets.

“We currently expect at least modest revenue and margin momentum for Expro over the next couple of quarters, driven by an overall increase in international activity, and positive trends in well testing and production services and well intervention and integrity services, in particular,” he said.

“Beyond the next couple of quarters, an expected recovery in offshore development across geographies reinforces our confidence that Expro is well-positioned for sustained growth, which we believe will be driven by increasing demand for subsea well access services and more complex well construction services, respective strengths of Expro and Frank’s International with whom we announced a definitive merger agreement on March 11, 2021.”

As the Offshore Well Intervention West Africa conference draws near, Offshore Network spoke to David Carr, Senior Vice President – Helix Well Ops (UK) Ltd. to gain a preview of the well intervention market and appetite in the region, and the latest on Helix’s activities there.

The Q7000 continues to shine

Carr began by discussing the Q7000, a DP Class 3 semisubmersible well intervention vessel that arrived in Nigerian waters for its pilot project at the start of 2020. Carr stated, “The first operator was an international major in Nigeria with whom we had scheduled to conduct a five well campaign. We had a new vessel, a new crew, a new well access package and we were working in a new country, and yet we completed the campaign around 25 days quicker than expected.”

“This vessel has been operated since it’s inception as a fully integrated package, utilising the services of Schlumberger, our partner in the Subsea Services Alliance.”

“During the last well, the pandemic hit, so unfortunately we had to return to Tenerife, however we continued conversations with Total, Chevron and Shell in Nigeria over Teams. Before the end of last year, we mobilised the vessel again and completed a five well campaign for Total and one for Chevron. In the last few weeks, we have begun a campaign for SNEPCo which is from five to seven wells. It is most likely we will finish the current campaign in early Q4 2021 and stack the vessel in a nearby port before recommencing operations in January 2022. After that, we are in discussions with two other major operators and a potential third to keep Q7000 in country, so we will be doing projects there next year as well.”

“After these projects are completed, the Q7000 will move on to Australia, but to do so we go right past Angola. We are in discussion with a couple of operators to do some work in the country during the second half of next year before moving on,” Carr added.

Carr also took time to explain how the Q7000 crew is rotated in the wake of the pandemic by noting that before members were rotated monthly but now, due to Covid quarantine rules, they do six week stints away from home in order to isolate. He noted that the company has been massively helped by their policy of utilising local content ‒ around 65% of the Q7000’s crew is Nigerian, and those crew do not have to go through international protocols, just Helix’s.

Carr added, “Nigeria is a very good place for local talent. The offshore oil industry has been established in the country for more than 40 years, so in terms of getting quality wireline, deck, or downhole service crews, the region is well supplied. We comply with the local content rules in the country, enforced by the Nigerian oil regulator (NAPIMS), but we don’t just comply by hiring cooks and cleaners, etc. Instead we hire and train DP officers, junior vessel engineers and more. All of the Schlumberger’s crew are Nigerian. We had nearly 30 Nigerian crew members fly to Singapore before the Q7000 set sail, so they knew the vessel, procedures and safety protocols well before arriving in West Africa.”

Collaboration

Helix has established a strong relationship with NAPIMS by providing opportunities for local Nigerian engineers, and imbuing them with transferable work skills to remain in the region. This relationship is essential when finding new opportunities for their vessels.

As Carr explained, “We speak to all the operators in the region, but not necessarily at the same time. NAPIMS does though, because it has an interest in increasing production for the whole of Nigeria. NAPIMS allows these operators to spend OPEX money on well intervention and they encourage this type of work to be taken up.”

“Additionally, each operator is ultimately aiming to increase production for themselves, whereas NAPIMS is trying to do it for the whole country. Through collaboration and discussions on where campaigns can fit in together they can all do this more effectively, but it is the NAPIMS that is the glue to bind them all together.”

Carr also added that Helix are not the only LWI service company working in the region and highlighted that while his company competes with many others, all are keen to see success continue within the segment. He commented that the last thing he wants is for them to have a bad job and that some of them are doing fantastic work ‒ such as Oceaneering who are working with BP in Angola currently.

The challenges and opportunities of West Africa

The success of the Q7000 in Nigeria has shown that there are opportunities to be found in the region, and by operators communicating and attracting such vessels to the region they have the chance to enhance well production and increase the well life of the rapidly ageing subsea wells located there.

However as Carr noted, the region can be a challenging place to operate. He said, “What typically kills well intervention work in West Africa is the transit cost of the vessel all the way from Europe or Gulf of Mexico (GOM). If you want to use a vessel in West Africa, you will probably have to sail it from the North Sea, which is very expensive. When we brought the Q7000 here, we agreed to pay for mobilisation but we needed to get a guaranteed amount of work to recoup this cost. Again, this is where collaboration between operators becomes necessary. When operators discuss and work out how the vessel will be utilised, it provides the opportunity to remain in the region longer.”

A promising future?

It is no secret that sub-Saharan Africa will have one of the oldest average ages of wells in the coming years, and as energy demand increases in line with the population, well intervention is predicted by many to have an important role in the region’s future. Weighing in on this subject, Carr said, “Nobody predicts the price of oil will reach such a height that exploration to replace reserves will be high on the agenda of many operators. As we know, companies like Total, Shell, BP are making big transitions into renewable energy and they will not want to be putting masses of capex into new exploration and development.”

“They are going to have to maintain their reserves by managing the wells they have; essentially, well intervention is going to have to be a big part of this. Unfortunately, the obviousness of that statement does not always translate into money being spent.”

“Adding to this, the well interventions that we (and our competitors) are doing now are reactive ‒ fixing things that are broken. What we need is a more European model of proactive work. Going into wells that are producing and making them more efficient. Doing well intervention earlier in their life so that they can maximise economic returns and continue production for many years to come.”

Rig vs riserless

One hot topic that has been debated in the region is the use of riserless over riser-based solutions for well intervention activities, with some touting the former as the answer to West Africa’s ageing well problem.

Carr took a more measured approach and commented, “There is an impression in the market that riserless equals cheap and at times this may be true. But we find that in the deep waters of West Africa, with the complexity and lack of supply chain in the area, sometimes it is less practical. With the riser vessels there is more contingency which leads to better outcomes in a place with less predictable wells. One of the criticisms of riser-based is it takes long to deploy the system and get onto the well, this is true if it is only deployed once. However, Helix often does multi-well campaigns and have the ability to deploy the system once, before hopping over to the next well and not recovering it in-between. In such cases it is every bit as fast as a riserless package.”

“At the end of the day it is going to be a combination of the two, and our intention is to have both capabilities in the region. In fact, in the future our intention is to bring one of our large monohulls from Brazil to be permanently stationed in West Africa. Our vessels (Siem Helix 1 and Siem Helix 2) currently in Brazil have each done more than 50 jobs each in deep water and complex geologies so they should be well suited. With those vessels we anticipate we can have riserless and riser-based capabilities. If we can get a minimum commitment from one or more of the operators in the region this will come to fruition,” Carr concluded.

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