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The discovery of the Magnus oil field in 1974 catalyzed a major leap for subsea controls systems. At the time, producing from satellite wells just a mere 5 km away was the limit of what could be practically achieved with direct hydraulic controls. Extending beyond 5 km with existing technology raised significant concerns related to making wells safe in an emergency, while the manufacture and installation of large lengths of bundled umbilicals was also technically challenging. At the same time, the water depth and hostile environment of the Magnus Field made two-platform field development prohibitively expensive. The operator needed an alternative approach. 

Developing electrohydraulic multiplexed control systems 

Around the same time, GEC Marconi Avionics was looking to diversify away from military electronics into the commercial world, eventually leading to discussions with the operator about the development of an electrohydraulic multiplexed control system. To ensure the project was financially viable, GEC joined with NL Shaffer, an American company with a track record of providing direct hydraulic controls for satellite wells. The eventual solution achieved many industry firsts by bringing: 

  • Electrical connections to subsea controls overcoming several technical challenges related to power delivery and transfer, protection from corrosion and the weight and size of magnetics in the process;
  • A directional control valve that had dual capability of electrical and sequence hydraulic control to provide a fail-safe that could de-latch and vent pressure at the tree valve actuators; and
  • A communications solution that could transmit signals over distances greater than 2 km without using repeaters. 

As development of the solution progressed so too did the operator’s business case, which came to rely on the use of the multiplexed electrohydraulic control system. The operator was able to pursue the use of seven satellite wells, allowing drilling to commence much earlier, which significantly improved cashflow and brought forward the project’s return on investment. First oil was achieved in August 1983 to much fanfare; a televised event saw prime minister Margaret Thatcher press the “go to production” button in front of the nation. 

Bkaer Hughes subsea controls
(Source: Baker Hughes)

Pushing the boundaries of today’s subsea control systems 

Magnus remains a key North Sea asset to this day, and the original development of the multiplexed electrohydraulic control system has developed into a multimillion subsea control industry. Today’s systems use much smarter instrumentation albeit much of the fundamentals remain the same, relying on a 50-year heritage of bringing reliable communications to increasingly hostile and technically challenging environments.

As an example, Snøhvit, in the southern Barents Sea is the first offshore development of its kind that has no surface installations. The production facilities stand on the seabed and the controls run 143 km back to land. As the field is developed, it has potential to be offset up to 220 km. 

More recently, the Zohr gas field in the Mediterranean was developed in record time with 17 months between signing of the engineering, procurement and construction (EPC) contract and first production. At approximately 190 km north of the city of Port Said in Egypt, it is one of the longest offset projects ever developed and a ground-breaker in many respects. 

The broad success of subsea controls is allowing operators to continue to push boundaries with the most ambitious now considering the feasibility of projects up to 300 km offshore. 

To greater lengths

Understandably, greater offsets, greater depths and enhanced recovery techniques present new technical challenges for subsea controls manufacturers to solve. Monitoring flow, real-time erosion, temperature and seismic data, enhanced equipment performance diagnostics, for example, require greater communications capabilities.

Greater depths into the 4,000-m to 5,000-m range will likely drive a requirement for all electric controls while greater distances will require either higher voltages or an increase in the cross-sectional area of conductors in the umbilical, leading to further development in the area of cables and fiber optics.

Here, at least learnings can be taken from the laying of Transatlantic fiber with products being developed that have standardized cross sections and jointing technology so existing cables can be lifted to the surface for repairs or extensions.

While subsea controls were not at the top of the digitalization list, the industry’s insatiable thirst for information means that where there is mineable data, there is the potential for improved production outcomes. 

All electric, all AI?

The development of all-electric subsea controls has the potential to eradicate the need for costly umbilicals altogether when coupled with local power generation and energy storage. Floating wind turbine technologies already exist, while solar and wave are also being investigated. For projects farther offshore, removing the need for an umbilical could shave off $100 million in capex, which would make many more projects economically viable. Of course, local power generation comes with all the same challenges as a fixed platform—maintenance, piracy, hazard to ships—which makes experiments into tidal turbines situated on the seabed even more interesting. 

Eradicating the umbilical would also require a step change in communications protocol, with fiber being replaced by satellite and the potential for more decisions to be made locally using artificial intelligence (AI).

In reality, once the valves are open, there are very few instances where it needs to be closed again, and the role for subsea controls becomes more about ensuring that should a problem arise, the facility will be put into a safe state. Closed-loop algorithms based on distributed flow metering could be used to modulate the chemical injections and automate the positioning of the subsea choke, which is the primary flow control device on a subsea tree. 

Reliability required

In the same vein, increased use of remote, unmanned production facilities requires a greater focus on reliability to avoid costly downtime and intervention. The growing use of continuous condition monitoring allows incipient subsea equipment issues to be more readily identified and resolved before they become critical. 

That said, recent data collated by the Subsea Equipment Australia Reliability joint industry project suggests a significant portion of subsea equipment failures are seen within the first four years of deployment. This has driven the industry mean time to failure (MTTF) average down to 13.5 years. Whereas the Baker Hughes MTTF is reported to be 24.5 years. Similarly, the data indicated that Baker Hughes controls incurred a failure rate of 12%, against an industry average of 35%.

This insight into the performance of subsea controls is invaluable for preparing the industry for this step change in the way it produces oil and gas. Original equipment manufacturers (OEMs) are working collaboratively to address the root cause of subsea equipment failures and to help clients make the most of the data available from these types of subsea infrastructure assets more broadly.

Baker Hughes recognizes how important it will be for operators to seamlessly manage an ever-shifting portfolio as the energy transition progresses. The company's designs build in backward compatibility and obsolescence management while ensuring longevity and reliability that will continue to meet the needs of the industry as it decarbonizes. 

Fifty years ago, the persistence of a pioneering team on just one high-profile project changed the face of E&P forever. With all that digitalization and local power generation stands to unlock, the industry’s engineers stand on a similar precipice today. But who will be the first to take the proverbial leap? As it stands, many high-potential locations remain locked off due to the technical complexity of their production. However, with fresh advances in technology, many OEMs and EPCs alike are eyeing this next step to ensure they can stick the landing.

About the author:

Dean Arnison is responsible for the product leadership of Baker Hughes Subsea Controls, Processing, All Electric offerings and also has responsibility for energy transition product strategy. He is a subsea industry expert and has been in the business for more than 30 years. He has held numerous senior executive positions in operational, commercial and technical leadership roles. Arnison is an apprentice trained and degree qualified engineer and is passionate about developing and implementing technology that drives improved outcomes for the customer and helps lower our industries CO2 foot print. He can be contacted via email at


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