Special Focus: Offshore Technology
All-electric systems are essential for the future subsea operations during the energy transition.
Matt Lamb
All around electrification. It’s how we live our daily lives and in certain spheres within the subsea oil & gas industry. There is a reason for all this talk. The use of electrified submarine control systems in place of hydraulic equivalents can help solve some of today’s most pressing issues.
Stay away from hydraulics. Subsea Electrification is not about removing significant hydraulics subsea infrastructure. We’ll get to that later. But when zooming in on hydraulic removal, in effect we take the basic principles of electrohydraulic-control (EMUX) subsea systems that are currently used for instrumentation, and low-power controls, but boost their power to provide primary-drive to perform more intense tasks, such as opening or closing major valves.
Fig. 1. Aptara manifold, electrified using a ball valve and the low-power rotary electric actuator.
Simply changing the function from hydraulic to electrical can bring benefits. The manifold can be removed from hydraulics to reduce CAPEX. Electrifying the choke valve can improve production control. Closed-loop self-contained gas lift valves can be used for carbon-capture utilization and storage applications. This will allow for greater control over the injection fluids and decrease OPEX.
The new electric systems eliminate a lot the high-grade stainless from manufacturing, transportation and installation of subsea umbilicals. Lighter-weight pipes with less low-pressure/high-pressure redundancy strip out both costs and carbon emissions from greenfield sites.
As piping volume decreases, so does the need to distribute and manage it through a manifold. Operators can go deeper and further with longer offsets for a lower cost than traditional hydraulic controls.
Interest is rising. This technology is not new. Vetco Gray, now part of Baker Hughes, built the first subsea electrical tree in 1994. However, it was never actually installed. It was 2006 when the first installation took place. This topic has been a hot topic in the industry since the early 1990s, though it is still a subject of much smaller industry circles. It didn’t gain much traction in the years that followed, due to the lack of industry willingness to take on new technology risks. Subsea electrification has been a slow but steady growth area for interest and engagement, despite its almost imperceptible acceptance. This is due to the need for:
- Electric actuators are used on compression stations where hydraulics are not available.
- Chemical injection metering valves using electric motors that have a great track record.
- Retrofitting electric actuators to operate ROV-operated valves on manifolds. Fig. 1.
These incremental steps, taken together, have decreased the risk profile of subsea electricity as perceived by the industry. TotalEnergies and Equinor both announced their plans to electrify all new systems.
The announcements of multi-million-dollar investments and fully funded joint ventures suggest that they are not the only ones recognizing the potential benefits of subsea electricity and the potential to address the current concerns of the industry. Industry specifications designers have already started to issue all electric regulations, requirements and documents. The American Petroleum Institute committee has committed to releasing drafts in the near-term.
Gathering evidence. Baker Hughes believes subsea electricity addresses operators’ main concerns in terms of capital, operating, carbon and other costs. This technology is now ready to be mainstream. However, it is not always easy to see the business case and it must be stated clearly: No new technology can be introduced without the required evidence, especially safety and reliability, even if the general opinion seems to be in favor.
So we set out to explore and analyze the potential savings, as well as how operations could be optimized when electrified control system technology is used instead of an electro-hydraulic approach. We chose a site we knew would be a good location for electric system installation, and instead of picking a spot that was already well-known, we worked together with partners to find a site suitable for a subsea installation. The SNEPCO Bonga Main Field, Nigeria’s first deepwater development of 1,000m or more, was chosen. It has been producing oil since 2005.
The study consisted of a single production line within Bonga Main. It includes two production manifolds and associated wells, wells, control systems, water-injection wells, and wells. The hypothetical project was evaluated as it would be for a subsea electrified new system. It was also compared with real-world specifications.
CAPEX savings. A thorough analysis revealed a 9% reduction in subsea equipment costs at system-level. These savings are a result of several factors. For example, umbilical system costs were 30% lower than electric systems. Control systems were 24% cheaper, and testing was 24% less. The small increase in cost of subsea production trees systems (less than 1%) was easily offset by savings in wellhead structures, distribution systems and intervention, as well as tooling. It is clear that the subsea electrical system beats traditional hydraulics in terms of CAPEX.
Given the number of variables, it is more difficult to calculate operational costs. However, the study shows the main benefit of the electric approach is the significantly shorter start-up times for trees. Operators can open multiple trees simultaneously using local energy storage modules (ESMs), which allows them to restart systems much quicker than the conventional method. These start-up times are shorter than what is practical, desirable, and safe. This is a case in which modeling outperforms reality. Operators will need this information when weighing up the potential benefits for their own fields.
Operational advantages. The study also reveals other areas where the removal and rotation of high-pressure fluid system components (HPU) can bring operators notable benefits. As repair demand decreases, system availability will likely increase. The potential to improve production availability is also possible, since hydraulic systems are often the main cause of downtime in subsea networks. Operators can also reduce leakage pathways, marine operations, and the risk of faulty or incorrect installation. All these factors lead to lower OPEX and greater production availability.
Operators will also see their inspection, maintenance, access and access requirements decrease. This will result in a reduction in the number of staffing requirements for interventions, particularly in hazardous areas. Fluid releases and their environmental effects, both topside as subsea, can also be eliminated by removing the HPU. Subsea insulation resistance reduction in electrical system is a concern. It is important to monitor the qualification and testing for electrical connectors.
The future is now. The report examined how subsea electricity can be improved by digital tools, which provide data access, visualization, monitoring and diagnostics as well as prognostics and prognostics. These tools will open the door to predictive maintenance. Subsea electrified systems would have all the actionable insights offered by digital infrastructure. This not only improves the availability of the system and supports de-staffed autonomous operations but also enables future-focused decision making to support the sustainability and longevity of the entire subsea system.
Operators are faced with tight margins, changing investment landscapes, an impending skills shortage, and unprecedented political scrutiny. There is very little room for experimentation. There is no future for business as usual. Operators and their suppliers must think differently in order to be free from these opposing pressures. They need the evidence to support this. Subsea electricty is now well-established. It is irresistible: Subsea electrification will be the future.
All-electric: Transforming to energy frontiers Baker Hughes views all-electric technologies expansion in the context of real cost and blue-economy consciousness and trust and interdependency from intelligences as a critical-enabler. The all-electric system is also a key component of the tapestry that will support the Baker Hughes energy-frontier transition.
Fig. 2. Example of a future topside-free, umbilical-free system using at-source renewables.
We ventured beyond the electrified center to create a full-electric system offering. We removed all chemical injection topsides and used electric surface-controlled subsurface safe valves (eSCSSVs). In an operational world with no hydraulics and a higher dependence on electricity, the traditional, tethered umbilical system and topside platform are less relevant, especially for long-offset or deepwater applications.
We believe that the zenith for an all-electric, truly topside-free system is possible by combining leading peripheral technology developments with supporting capabilities, renewable energy-generation at source and connectors. Fig. 2.This is the basis for laying out the possibilities for reconfiguring common system components to serve the energy frontiers just beyond the hydrocarbon horizon.
Matt LambSPS systems product manager for all-electric, deepwater and long-offset applications. He is responsible for developing and delivering innovative multi-generation system strategies that will allow the company to respond to current, future and frontier energy market demands. Previous posts for Baker Hughes included leadership roles in supply chain, operations/manufacturing and program director positions. His sector experience spans six-years. His previous 11 years of aerospace experience includes roles in supply chain, operations/manufacturing, and program director positions. Mr. Lamb holds charterships in both leadership and engineering disciplines and a first-class honors engineering degree.