Special Focus: Offshore Technology
All-electric systems are essential for the future subsea operations during the energy transition.
Matt Lamb
All around electrification. This is how it appears and feels in our daily lives, as well as within certain spheres, of the subsea petroleum and gas industry. There is a reason for all this talk. Using electrified subsea controllers instead of hydraulic equivalents could help to solve some of today’s most pressing issues.
Get 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 by ball valve and low power rotary electrical actuator.
You can get benefits by simply changing some functions from hydraulic or electric. 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 can be stripped of hydraulics and remove a lot of high-grade stainless steel that is used in 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.
The volume of piping shrinks, which means that there is less need to distribute it and manage it through the manifold. There is also less demand for auxiliary equipment such as hydraulic stab plates. Operators can reach deeper and longer distances with less expense than traditional hydraulic controls.
Interest increases. 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 gaining interest and engagement after a slow but steady decline in acceptance. This is due in part to:
- Compression stations that were not equipped with hydraulics can now be used as electric actuators
- Chemical injection metering vales, using electric motors with a strong track record.
- Retrofitting electric actuators to operate ROV-operated valves on manifolds. Fig. 1.
These incremental steps, taken together, have decreased the risk of subsea electricity being used by the industry. TotalEnergies and Equinor have made similar promises that all new systems will be electrified by 2023.
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 begun to issue all-electric regulations and requirements, documents, and industry standards to be adopted. 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 and carbon cost. This technology is now ready to be mainstream. The business case for subsea electrification is not always clear to all operators. It must be stated clearly. No new technology can ever be introduced without the right evidence, safety and reliability.
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 didn’t choose a site that was already considered to be the best location for electric systems. Instead, we worked with partners and selected a site that would be comparable to a typical subsea facility. 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 covered a single production loop in Bonga Main field. It includes two production loops, as well as associated wells and control system wells. The hypothetical project was evaluated as it would be for a subsea electrified new system. The results were conclusive.
CAPEX savings. An extensive analysis revealed a 9% savings in subsea hardware cost at system level. These savings can be attributed to several sources. Umbilical costs were 30% less with electric systems and control systems were 24% less, as well testing. The subsea tree system cost increased by less than 1%, but was offset by savings in wellhead systems and structures, distribution, intervention, tooling, and distribution systems. Subsea hydraulics is far more efficient in terms CAPEX than traditional hydraulics.
It is difficult to calculate operating costs because of all the variables involved. However, the study shows the main benefit of the electric approach to tree starting is the significantly shorter time. Operators can open multiple trees simultaneously using local energy storage modules (ESMs), which allows them to restart systems in a much shorter time than the traditional 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. First, system availability will improve as less repair work is required. Hydraulic systems are a major cause of subsea system downtime. This could lead to significant improvements in production availability. Operators can also reduce leakage pathways, marine operations, and the risk of faulty or incorrect installation. All of these factors result in lower OPEX, and more production.
Operators can also expect to see a decrease in inspection, maintenance, and access requirements. This will reduce the need for staffing interventions, especially in dangerous 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. These actionable insights, which digital infrastructure provides, would also be available for subsea-electrified systems. 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, a skills shortage, and unprecedented political scrutiny. There is very little room for experimentation. There is no future for business as usual. Operators and their providers must think differently to avoid being caught between these competing pressures. They need evidence to support this. Subsea electrification is now under scrutiny. It is irresistible: Subsea electrification will be the future.
All-electric is the key to transitioning to energy frontiers. Baker Hughes views all-electric technology expansion in the context of real cost and blue-economy consciousness and trust and interdependency with system intelligences. 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 or umbilical-free system that uses at-source renewables.
We have tried to go beyond the electrified core to offer a true, full electric system offering. This includes removing all chemical injection topsides and utilizing electric surface-controlled, subsurface safety valves. The role of traditional umbilical systems and topside platforms is more prominent in an operational world without hydraulics and a greater dependence on electrical power. This is especially true for deepwater and long-offset 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 enablement is what prompted us to begin to plan the reconfiguration of common system elements in order to serve the energy frontiers just beyond the hydrocarbons 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. He has previously worked in aerospace for 11 years. He has served in various manufacturing and customer facing roles at Rolls-Royce aero engines, GE Aviation, as well as as being a consultant in strategic management and business change. Mr. Lamb holds charterships in both leadership and engineering disciplines and a first-class honors engineering degree.