The Phase II plug and abandonment (P&A) campaign of the Chinguetti Field offshore Mauritania, which was stalled due to Covid-19 complications, has seen the successful intervention and barrier placement on all 15 wells since its resumption with projected completion of the entire abandonment scope by the end of the year, according to Expro and PETRONAS.
The Phase II P&A campaign
Phase II of the P&A campaign on the PETRONAS-owned Chinguetti Field began in late 2019, carried out by Pacific Drilling LLC, who had commissioned the help of Expro to provide an Intervention Riser System (IRS) and associated surface support equipment to be deployed from the Pacific Drilling drillship, the Pacific Santa Ana.
The award to Expro included a range of services such as the subsea well access system, surface flowhead, umbilicals, topside control equipment and IWOCS (installation and workover control system) package. Expro would also provide an onshore project management team to support Pacific Drilling throughout the project planning and execution phases. For their part, over the course of the 2019 summer, Expro carried out system integration testing on the equipment before shipping and installing it on the Pacific Santa Ana in Las Palmas in October 2019.
Expro, in turn, requisitioned for the campaign the support of Worldwide Oilfield Machine (WOM) who were contracted to provision the subsea well access system and a technical support team. This formidable team were contracted to complete the Phase II P&A project in Mauritania, which would take an estimated 360 days.
Covid-19 stalls progress
By late 2019 the campaign was in full swing (with the abandonment of the first well completed in December) so that by the end of March, subsea well access had concluded on nine of the 15 wells. Of course, then the Covid-19 pandemic struck and operators and oilfield owners across the world were forced to stall projects and forego operations as they dealt with closed borders, new quarantine rules, social distancing and keeping their employees safe. Such was the case on the Chinguetti field, where a strong start to the campaign made at the beginning of 2020 was drawn to a sudden halt with PETRONAS, due to the enforcement of travel restrictions, forced to declare force majeure on its contract with Pacific Drilling effective on 29 March 2020. Subsequently, Pacific Drilling agreed to leave the rig on stand-by at 35% of its contractual day rate until March 2021 and on the 31 March made sail for Las Palmas.
Keith Allan, Global Sales Manager at Expro, spoke to Offshore Network to reveal the challenges that his company faced during this difficult time, and how the rig was eventually returned to Mauritanian waters. He commented, “The main challenge we faced at that time was around travelling and personnel. Although we were shutdown at the end of March we still had some personnel in West Africa for a few months and faced challenges getting them home due to all borders being closed.
“We also had to keep skeleton crews on the vessel throughout the pandemic to ensure all routine and preventative maintenance was carried out on the equipment. They continued to perform to extremely high standards considering the global situation that meant extended trip durations, isolation periods and everything else that went along with travelling during the pandemic. The team were a critical part of the success of this project, providing a seamless operational start up when operations resumed.”
Returning to Mauritania
As Mr. Allan alluded, eventually there was light at the end of the tunnel and on 23 December 2020 the Pacific Santa Ana departed Las Palmas to resume the campaign in Africa. Since operations started up again in January, the subsea well access operations have been carried out effectively and efficiently and Allan proudly reported that as of 4 April the remaining six wells had been successfully intervened and Expro’s equipment offloaded.
Mr. Allan continued, “After the pandemic the six wells were challenging with regards to personnel movement, however all equipment and personnel continued to perform to an extremely high standard. One of the highlights for us was the ability to retrieve the Christmas trees with the IRS without requiring an additional run subsea. The IRS system’s compact nature combined with Pacific Drilling’s dual Derrick capabilities saved considerable rig time.
“This was Expro’s first venture into the IRS market therefore, we had to form new offshore and support teams to ensure we provided a quality service for the duration of the campaign. Our team’s skillsets were easily transferred to run this new system, and although we did employ experienced personnel, the crew was mainly made up of our people from the existing subsea product line.
“On a management level, it worked well. We had project managers onshore in Mauritania working from the Pacific Drilling offices to provide support for the operations duration," Mr Allan added.
Eyes set on the future
With the initial P&A of the 15 wells on Chinguetti Field the campaign has nearly reached its conclusion with some more work required to mop up the heavily lifting that has just been completed. PETRONAS, in a statement to Offshore Network, have confirmed “The campaign is progressing as planned and is projected to be completed by the end of this year.”
With vaccine distribution picking up speed across the globe and with the industry continuing to show the resilience and ability to work round the restrictions whilst maintaining the safety of their employees (as this campaign showed), there seems little reason to doubt this projection.
For Expro’s part, aside from some equipment remaining onboard for operations in a month or two, their role has been played to fruition and has marked a successful venture, which has overcome some serious challenges in the process.
As Mr. Allan concluded, “This was our first venture into the intervention riser system market, and we were able to carry out the campaign with no non-productive time (NPT) incurred. From an Expro point of view this has been a very successful project and something we are very proud and grateful to have played our part in. The success of this project has led to another contract award for a client in Australia, for a very similar scope of work and will commence in early 2022 once the equipment has completed a maintenance campaign in preparation for the work.
Welltec has announced the agreement of a long-form contract (LFC) with Saudi Aramco which, following an extensive approval process, will see Welltec deliver completion products and services across the Saudi Aramco portfolio in any environment.
“Welltec began installing WAB metal expandable packers for Saudi Aramco in 2014 as part of a technology trial, and the award of a LFC demonstrates how far we’ve progressed since then,” said Kevin Wood, Well Completions Sales Director for Welltec Middle East.
Wood added, “Confirmation of this award represents a major step in our partnership with Saudi Aramco which also enables us to continue along the path of exemplary service quality in the execution of completions. With more products being qualified through Saudi Aramco this year, and the addition of an in-country Welltec manufacturing facility, it’s greatly appreciated that Welltec have been recognised through this award.”
More to come?
The approval procedure for this agreement has been extensive and thorough, and such a high standard of qualification brings with it the benefit of an expedited process for the establishment of future agreements between the two companies.
Hani Sagr, Area Vice President for Welltec Middle East, explained, “The LFC is the highest level of contract in the Saudi Aramco procurement processes. It provides the best possible foundation for the provision of our technology and services to Saudi Aramco, enabling us to continue growing our partnership as well as our overall presence in the region.”
“The qualification process included a number of site visits, inspections and audits, with full and detailed reports covering the entire Welltec organisation with particular focus on our manufacturing process,” added Sagr, who also noted that it was in December 2018 when proceedings began in earnest.
“This is not only an excellent recognition of the great teamwork between Welltec and Aramco, it also highlights our commitment to the IKTVA programme geared towards in-Kingdom value creation,” Sagr concluded.
The combination of this award and the continued expansion of in-house manufacturing at local level serves as an excellent platform for the future and continued growth in neighbouring countries. The agreement also comes in a strong period for Welltec which has seen an admirable financial period in the face of Covid-19, the penning of deals with companies such as Petronas, and a change of executive who has promised to expand the company’s business potential to new heights. To read more on Welltec’s progress, click here.
In an operational and financial update, Hurricane Energy plc, a UK-based oil and gas company, has provided an update on production from its Lancaster field and Early Production System (EPS) and net free cash balances.
The Lancaster (EPS) consists of two wells tied back to the Aoka Mizu floating production storage and offloading (FPSO) vessel, a relatively new system with first oil achieved in June 2019. Hurricane Energy has now reported that between Q4 2020 and Q1 2021, oil production shrank from 1.17mnbbl to 1.01mnbbl, with an average oil rate of decline of 12,700bpd to 11,200bpd.
The company has identified the decline in oil production in 2021 is a result of:
•The decision to reduce production from the 205/21a-6 well (the ‘P6 well’) in November 2020 for reservoir management purposes, which resulted in a reduced rate of increase in water cut
•Natural decline in the period
•A temporary reduction in the production rate in early March 2021, which required an unscheduled well intervention
Hurricane Energy continued by stating that production efficiency during the first quarter of 2021 was 95%, exceeding its planning assumption of 90%. The first quarter outturn compared to a production efficiency of 99% in the fourth quarter of 2020, with the sequential decrease explained by the unplanned well intervention.
As part of the Hurricane Energy’s periodic well testing programme for reservoir management purposes, the Lancaster field is currently producing from both the P6 and 205/21a-7z wells. Immediately prior to the testing programme, the field was producing from the P6 well alone at a rate of c.11,600 bopd on artificial lift via electric submersible pump, with an associated water cut of 28%.
Despite the unscheduled operations, the 21st cargo of Lancaster oil was still lifted on 17 March 2021 with the 22nd cargo already sold and due for lifting between end April and early May 2021. Additionally, despite the drop in production and the impact of Covid-19, Hurricane Energy reported that as of 31 March 2021, it had a net free cash of US$127mn, compared to US$106mn at 31 December 2020.
Chevron U.S.A. (Chevron) has awarded Worley, a global provider of professional project and asset services in the energy, chemicals and resources sectors, an engineering and procurement services contract to provide brownfield modification services for one of its deepwater production facilities located in the Ballymore oil and gas field, Gulf of Mexico.
Ballymore is a large oil and gas field drilled by Chevron in 2018. It is located in the Mississippi Canyon area of the Gulf of Mexico, in water depth of 6,536 feet. Chevron is the operator and holds a 60% working interest in the prospect, with Total owning the remaining 40%.
Worley will provide engineering and design services for the integration and subsea tieback of the Ballymore oil and gas field, support both the subsea and topsides designs and will also provide procurement services for topsides.
The topsides services and project management will be executed by Worley’s US Gulf Coast team, with Intecsea executing the subsea portion of the project. Intecsea is part of Worley’s Advisian consulting business and is a world leader in subsea systems, offshore pipelines, floating systems and overall field development. Support will also be provided by Worley’s Global Integrated Delivery office in India.
Chris Ashton, Chief Executive Officer of Worley, commented, “As a global professional services company headquartered in Australia, we look forward to helping Chevron meet the world’s changing energy needs and continuing Worley’s longstanding global relationship with Chevron.”
Cooper Energy have, in their most recent quarterly report, confirmed more details for the abandonment work they have organised with Helix Energy Solutions in Australia with the announcement that they have acquired the Q7000 light well intervention rig to decommission the infrastructure in the Basker, Manta and Gummy (BMG) fields.
Earlier this year, David Carr, Senior VP of International Business at Helix Energy Solutions was joined by a host of panellists for the OWI webinar on decommissioning in Australia, where discussions focused on the substandard state of decommissioning in the region. In the session, Carr said that Cooper Energy had selected the Q7000 to perform operations for them in Australia in 2022, a move which they hoped would be the catalyst for getting on top of the decommissioning project in the country.
Cooper Energy have now confirmed this work in more detail with the announcement that the Q7000 will enter Australia waters with the first task of carrying out the decommissioning of the BMG fields, located in the Gippsland Basin. This will involve the decommissioning of seven wells and associated subsea infrastructure (pipelines and control umbilicals).
The Helix Q7000 Safety Case, a key permissioning document, has been submitted to the regulator (NOPSEMA) and is currently under review. The plan is that other regulatory documentation, including the Environment Plan and Well Operation Management Plan, will be submitted in Q4 FY21.
The BMG abandonment project is currently in the Front End Engineering Design (FEED) stage, with activities focused on selecting optimal methodologies and technologies for safe and cost-effective delivery of the decommissioning objectives. Details of scope of works, timing of execution and cost estimates will be announced at the final investment decision (FID), which is being considered in FY22.
The Q7000
The Helix Q7000 light well intervention rig has been specifically designed and built for intervention on subsea wells and abandonment activities. It is one of the newest vessels of its type, and benefits from the latest technological advances in well intervention, bolstered by its participation in the Subsea Services Alliance and array of equipment provided by Schlumberger. Its features include:
-IMO-certified Class 3 Dynamic positioning System
-Intervention Riser System, IRS 6, designed by Helix which enables access to both vertical and horizontal subsea trees in depths from c.85m to c.3000m
-Variable load capacity of c.3,000t
-ITF (Integrated Tension Frame), IRS maintenance tower, allowing for walk-to-work and safe access to well control equipment
-Large flush deck with skidding system for well intervention support equipment and tubular storage. Increasing operability by reducing reliance on offshore cranes
-Below deck twin work class ROV systems with harsh weather deployment capability
-Bulk fluids storage and pumping systems
-Wireline, Slickline, coiled tubing and cementing pumping spreads (Schlumberger).
Petronas, a global energy solutions company, has awarded an exclusive three-year contract to Welltec, a provider of robotic well solutions, appointing them as sole provider of downhole conveyance and powered mechanical services in the eastern and western regions of Malaysia.
Commenting on the contract, which officially commenced on 1 April, Espen Dalland, Area Vice-President for the Asia-Pacific Region at Welltec, said, “It’s a great team effort that has led to the award of this exclusive long-term contract with Petronas, and Welltec has demonstrated a strong ability to deliver – even through a challenging 2020 – high quality services in a safe manner to the largest assets in the country at a very cost-effective rate.”
“This winning combination is the foundation for Petronas awarding us an even larger work scope for the next three years, where we will continue to deliver world-class technology and services.”
Confirming a strong relationship
The new deal covers the entirety of Petronas’ intervention operations, highlighting the confidence that the company has for Welltec’s fleet and technological capabilities which has been manifested across a successful and longstanding relationship.
Alex Nicodimou, Vice-President of Sales & Marketing at Welltec, added, “This is a fantastic win for us. Petronas is a key customer in the region who over recent years have moved more and more towards an integrated approach for interventions. The fact they have provided us 100% of their intervention work speaks volumes about their belief in our technology and ability to deliver. We’re looking forward to continuing to support them to the best of our abilities.”
Welltec continue admirable performance
The award of such a promising contract should be of no surprise to anyone who has tracked the progress of Welltec over the last few months. The company reported a revenue decline of less than 15% in 2020, which was comparatively low compared to the rest of the industry and also maintained operating earning margins close to 40%, which was among the best across the industry. At the start of the year the company also announced a substantial agreement with Equinor for the long-term provision of integrate wireline services to key platforms across the Gullfaks and Stratfjord fields which will run for at least five years, with the potential to run for more than ten.
The company will also seek to continue this strong performance under new leadership as Founder and CEO of Welltec, Jørgen Hallundbæk, has announced his retirement from the management team to be replaced as CEO by Peter Hansen, the former COO of the company.
Preparing to facilitate what he believes will be a bright future for the company, Hansen commented, “Together with our global teams, I look forward to continuing to contribute to the development of Welltec. We are global leaders in our service and products categories and are determined to strengthen our positions further. We have expanded our business potential by investing in geothermal and carbon capture and storage technology development. Combined with our core services and products, we believe that this creates a solid platform for the future.”
The Tui oil field, located 50km offshore Taranaki Coast in New Zealand has been marked for decommissioning since production ceased in 2019, and it appears progress is finally being made on the project.
The Tui oil field
The Tui oil field started production in July 2007 with a healthy production capacity of approximately 50,000 barrels of oil a day. In March 2017 Tamarind Taranaki increased its stake in the Tui oil field permit to 100% and spent the next few years attempting to improve oil recovery to extend its life. Unfortunately in November 2019 an oil sheen, caused by a damaged subsea flowline, was observed alongside the floating production storage and offloading (FPSO) unit, the Umuroa, and so production from the field was ceased.
The planned decommissioning project
With production at an end, it was time to retire the field and so a decommissioning programme was planned to enact this. This would require the demobilisation of the FPSO Umuroa and the plugging and abandonment (P&A) of eight subsea wells and associated subsea structure.
Initially, the first phase of decommissioning included FPSO disconnection and removal, cleaning of flowlines and safely leaving them on the seafloor with additional vessels required for handling flowlines, umbilicals, mooring lines and tugs to hold the FPSO in place during disconnection operations.
The second phase of the project included the P&A of wells to avoid the leakage of hydrocarbons into the marine environment, as well as the removal of the remaining subsea infrastructure.
The New Zealand Government takes over
These plans, however, would never come to fruition as on 11 November 2019, the field operator Tamarind Taranaki announced that it may be insolvent and swiftly put the company into administration, with liquidation following in December 2019.
With the operator unable to carry out the decommissioning, the New Zealand Government received the Tui assets and picked up the project to remove the Umuroa FPSO vessel and decommission the field. The Ministry of Business, Innovation and Employment (MBIE) therefore signed an agreement with BW Umuroa Pte Ltd (BWU), the owner and operator of the Umuroa, to demobilise and disconnect the vessel from the Tui field before carrying out P&A and decommissioning work on remaining associated infrastructure.
An update on these operations has been provided by Lloyd Williams, Project Director for the Tui oil field decommissioning, in an interview with ‘Stuff’. Williams commented that since work began in January, following an underwater survey of the infrastructure, around 14km of flowlines have been successfully flushed.
Now this has been completed, attention has turned to disconnecting the production lines (flowlines, umbilical cables and gas lift lines) from the FPSO vessel. Work began in late March and once completed, the lines will be lowered to the sea floor before the mooring system anchoring the Umuroa will be detached.
Williams continued that this will allow the Umuroa to be removed from the field, which is expected to occur in May. New Zealand Petroleum and Minerals have also noted that four vessels have already been selected for this task, with two already arriving at the port of Taranaki.
Outlining the next stages Williams comments that once these phases had been carried out it would then be time to completely remove the subsea equipment before, finally, the P&A of the five production and three exploration wells can be undertaken.
Aquaterra Energy, a leader in global offshore engineering solutions, has secured a five-year deal with a major Middle Eastern operator to provide green and brownfield riser analysis so that, combined with other recent project wins in the Middle East, the company will now deliver an estimated UK£1mn of riser analysis work over the five-year period.
Acting as a primary riser analysis supplier, Aquaterra Energy will manage and deliver multiple scopes of long-term work using its in-house analysis teams. Located in Abu Dhabi and Qatar, the contracts incorporate a wide range of recurring brownfield riser analysis projects, with future greenfield opportunities. The brownfield platform modification projects include slot recovery, slot addition and assisting development of inspection programme of existing conductors.
Coping with ageing infrastructure
Martin Harrop, Riser Analysis Manager at Aquaterra Energy, commented, "With the region shifting its focus to ageing infrastructure, there is a growing appetite for experienced riser analysts amongst operators. As the operations are often non-standard, we have been working closely with our client's engineers to find solutions to challenging operational concerns. Our analysis has generated many cost-saving, operational and decarbonisation benefits for our clients in the region.”
Andrew McDowell, Operations Director at Aquaterra Energy, added, “The Middle East is embarking on its next stage as an oil and gas producing region. Operators are now continuing to invest in new projects but also finding themselves with a glut of legacy assets coming to end-of-life from earlier generations of investment. To safely and efficiently maximise output, our expert riser analysts are perfectly placed to support operators with both green and brownfield projects. With a long-term contract in place, I see this as the start of a major period of growth for us in the region.”
Ashtead Technology, an integrated subsea technology and services provider, has penned a deal with Zetechtics, a leader in subsea control systems for ROV tooling intervention, to offer customers a range of new ROV tooling technologies.
The deal gives both organisations the scope to add further specialist equipment based on demand and will allow Ashtead Technology’s nine customer service hubs to offer an array of torque tools, control systems and associated peripherals from the subsea control systems specialist.
Ashtead Technology noted this was part of their strategy to continually develop and expand their capability to meet the diverse needs of their customers around the world, who operate in all areas of the global energy industry.
David Mair, Business Development Director for Ashtead Technology commented, “These new technologies offer improved performance, reliability and efficiency, as well as a greater level of user-friendliness. Zetechtics has 27 years of experience for us to draw on and this collaboration is set to add undeniable value to our customer’s operations.”
Alan Duncan, Commercial Director of Zetechtics, added, “Customers prefer to use modern, easily-supported equipment, with the type of technical features they would have access to if buying new. We are excited to collaborate with Ashtead Technology and by introducing a wide range of new equipment to the market in this way will enable their customers to unlock the potential of our market-leading solutions.”
At Hannover Messe, April 12-16, Bosch Rexroth will present the SVA R2 Subsea Valve Actuator, a disruptive innovation for electrically actuating valves in the subsea process industry.
The SVA R2 is the world’s first electric actuator that can replace conventional hydraulic cylinders with field-proven safety technology and without taking up additional space. The integrated electric controller offers precise motion control and, thanks to condition monitoring and a safety spring, the SVA R2 satisfies Safety Integrity Level (SIL) 3 in accordance with IEC 61508 and IEC 61511.
The actuator minimises energy consumption and is geared toward delicate ecosystems. The functions, operating life and safety of the actuator have already been successfully tested in accordance with international standards and when the SVA R2 is used in subsea factories at a depth of up to 4,000 meters, hydraulic pipes or power units are no longer required. The electric supply pipes which are already installed for sensors are adequate to ensure the reliable operation of the actuators.
Changing the subsea process industry
Up until now, the operators of process systems have mainly relied on hydraulic cylinders in order to open and close subsea valves with a quarter turn and a defined force. With offshore installations, for example for oil and gas production, these cylinders are supplied by a central hydraulic power unit with hydraulic pipes several kilometres in length. This solution uses a great deal of energy in order to compensate for the cumulated losses and it cannot control the movement with precision. To date, plant engineers and operators have still relied on hydraulic cylinders because they are the only components to offer field-proven safety systems with a mechanical spring in a compact design (the electric actuators which are currently available do not have such a safety function as this is not possible given the size and weight requirements). Additionally, approaches designed to ensure safety using subsea batteries cannot guarantee the reliable closing of valves over the required operating life of up to 25 years.
For the agile development of the SVA R2, the Bosch Rexroth team worked closely with a number of suppliers and operators of offshore installations, as well as international universities. The new module comprises a pressure-compensated container that contains an electric drive, a motion control system and a safety device – and can replace the hydraulic cylinders previously used on a 1:1 basis. It requires only one cable for the power supply and communication. The SVA R2 is designed to actuate valves reliably with the power supply that is commonly used for subsea sensors. Switching to compact and safe electric actuators means that hydraulic pipes (several kilometres in length along with the associated power units and controllers) are no longer required.
The Subsea Valve Actuator is designed for high volume production, has proven robustness and reliability and is suitable for applications above and below water such as hydrogen production, CO2 storage and general applications in the oil and gas process industry. This innovative new technology has been nominated for the prestigious Hermes Award and, after its premiere at Hannover Messe in April, the first pilot tests are due to start in the third quarter of 2021 before being offered to Bosch Rexroth’s global client base.
Safe Influx has announced that the rig trial of the industry’s first ever integration of Managed Pressure Drilling (MPD) and Automated Well Control technology has been completed following months of preparation by Weatherford, Safe Influx and Finesse Control Systems.
A series of pre-agreed tests were successfully performed on Weatherford’s test rig in Houston, to demonstrate and verify the integration and functionality of both systems.
A "game changer" for the industry
The combination of Weatherford Victus intelligent MPD and Safe Influx’s Automated Well Control system provides automated secondary well control, which will allow wells to be drilled and constructed with the highest level of efficiency and integrity. As a standalone application, the MPD system can detect, control and circulate out an influx, which is within the well’s operational envelope.
If the parameters within the well’s operational envelope are exceeded, the Weatherford MPD system sends a series of real time signals to the Safe Influx Automated Well Control system which then commences the Automated Shut-in sequence: space out, shut down the top drive, shut down the mud pumps, and finally shut-in the BOP.
“We are delighted to have successfully completed the rig trial of the integration of MPD and Automated Well Control systems. The combination of the Safe Influx patented technology with Weatherford’s comprehensive portfolio of MPD products provides a game changer for the industry. We are confident that this is a reliable tool which has the ability to mitigate risks and enhance efficiency and safety in well operations, to prevent the loss of life, minimise environmental impact, deliver substantial cost savings and protect company reputation,” commented Bryan Atchison, Managing Director at Safe Influx.
Fraser Dunphy, Managing Director at Finesse Control Systems who build the Safe Influx equipment and developed the logic programming, said, “It has been great to work with Safe Influx and Weatherford on this ambitious and innovative combination of technologies. We have been involved with this project since its initial phase and we are thrilled to see this integration working on the rig trial. The successful results reveal the value of combining technologies, knowledge and experience to create a cutting-edge solution to the oil and gas industry.”
The rig trial is part of the Memorandum of Understanding (MoU) signed by Weatherford and Safe Influx in September 2020. Under the MoU, the companies will cooperate globally to focus on revolutionising well integrity during the construction phase by bringing to market the integration of MPD solutions and Automated Well Control technology. This integrated offering will automate the mitigation of drilling hazards, while drilling in the most efficient manner possible.
Halliburton Company (Halliburton) will offer Optime Subsea’s (Optime) innovative technologies as a service across its global portfolio as part of a new strategic alliance.
As part of the agreement, Optime’s innovative Remotely Operated Controls System (ROCS) will be applied to Halliburton’s completion landing string services. The companies will also collaborate to offer intervention and workover control system services leveraging Optime’s Subsea Controls and Intervention Light System (SCILS) technology, a remote digital enabled system that compliments Halliburton’s subsea intervention expertise.
The alliance will facilitate umbilical-less operations and subsea controls for deepwater completions and interventions delivering increased operational efficiencies while minimising safety risk through a smaller offshore footprint.
Daniel Casale, Vice-President of Testing and Subsea at Halliburton, commented, “We are excited to work with Optime and leverage their technologies within our existing subsea completions and intervention solutions. Our alliance advances remote capabilities and provides a capital efficient solution, allowing customers to reduce safety risk, operational footprint, setup and run-time.”
Jan-Fredrik Carlsen, CEO of Optime Subsea, added, “We believe that strong mutual alliances across the vertical supply chain drives continuous improvements needed in our industry. By solidifying this relationship with Halliburton and combining their well-established, reputable service and technology capabilities with Optime’s innovative controls and intervention technology, more customers will have access to these cost-efficient subsea solutions.”
Another step forward for Subsea Optime
The collaboration with Halliburton marks another step in Optime’s short but impressive history, since its foundation in 2015, as an integrated system and service provider with the capability to optimise well interventions and completion operations. Recently the ROCS, perhaps their most successful offering, proved its worth when it was deployed during a completions operation for a production well for Aker BP on the Ærfugl-field on the Norwegian Contintental Shelf in late February. The operation was a success and optimised operations with noticeable reductions in HSE risks and overall cost. Now the ROCS (and the rest of Optime’s offerings) has the opportunity to perform on the global stage, and this partnership with Halliburton will help the company expose its services to a wider customer base.
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