Subsea processing is making its way up the technology curve, but still several challenges ahead

May 6, 2015

Author: Jon Fredrik Müller, Senior Project Manager, Rystad Energy

Publication: The article has been exclusively published by Offshore Magazine

Offshore developments are continuously moving into deeper waters and the nature of the game is that the biggest potential targets get drilled first and the most commercial fields developed first. As the offshore fields mature, pressure differentials narrows and step outs from existing infrastructure increase, new technology has been developed to tackle the challenges. The different technologies have been implemented gradually both in greenfield developments and modifications of existing fields, but for many of the technologies the adaptation is still low. The following article will outline some of the main subsea technology developments, the current status and future barriers to widespread use.

Subsea processing is the concept of gradually moving the entire topside processing facilities to the seabed. Many subsea fields would create better financial returns for their owners if subsea processing were installed due to increased recovery. In some cases, subsea processing is a prerequisite for making developments economically viable at all. By moving the processing of the well flow from the topside to the seabed, projects previously deemed non-commercial may become economically viable, and one may also increase the recovery rates on existing fields. Currently, Petrobras, Statoil and the Majors are driving the developments behind subsea processing, together with the equipment manufacturers. These operators have the biggest potential and may sustain a market before smaller operators catch on. Subsea processing encompasses a large array of technologies and systems, but there are mainly four technologies that have been implemented by the industry so far; boosting, separation, water injection and compression.

Subsea boosting is the application of subsea pumps to “boost” the pressure in the well stream. The main advantages of subsea boosting is accelerated production, increased production & recovery, development of low energy reservoirs, heavy oil fields, long tiebacks and other fields where pressure differentials might be an issue.

The first subsea booster pump was a twin-screw multiphase pump developed by GE Oil & Gas, which was installed on Eni’s Prezioso field in Italy in 1994. Since this first installation in water depths of 50 meters, the technology has continuously been taken deeper. The Cascade oil field in the Gulf of Mexico is currently the deepest subsea boosting system installed, at a water depth close to 2,500 meters, and Shell is currently contemplating booster pumps at its Stones development in 2,900 meters. Although GE was first, it is OneSubsea (through Framo Engineering) that has become the market leader, capturing most of the market with their helico-axial pumps. Today, the booster technology is by far the most mature of the subsea processing technologies.

 

Booster pumps are mainly used on oil fields with low gas to oil ratios, both for heavier and lighter crudes. The key regions have been, and will continue to be, Brazil, the US Gulf of Mexico, the North Sea and West Africa due to the water depths, reservoir characteristics and tie back distances.

Subsea separation is the concept of separating gas/liquids or oil/water at the seabed. Such systems bring solutions to flow assurance challenges such as hydrates and slugging, enables viability of challenging reservoirs, prolongs economic lifetime of fields, debottlenecks flowlines, risers and topsides and handles water and sand at the seabed, thereby reducing the potential costs associated with a topside facility. Many of the installations have been in conjunction with booster pumps, and subsea separation is today a proven technology. Whilst OneSubsea has taken the lion’s share of the booster market, it is FMC Technologies that has become the market leader in the separation segment, being system provider on the majority of projects completed.

While there has been some experimentation on subsea separation systems prior to the 2000s (Zakum 1965, Highlander 1985 and Argyll 1986), most people regard the Statoil Troll C pilot on water separation and injection in 2001 as the first modern subsea separation unit. The Troll system was installed in 340 meters of water depth, 3.5 kilometer from the platform. Today, it is Shell’s Perdido field which is the deepest application of subsea separation at approximately 2,500 meters. Subsea separation systems have now been installed at 11 fields operated by Petrobras, Statoil, Shell and Total. All the fields lay in Brazil, Norway, US GoM or Angola, and going forward these areas, including the rest of the North Sea and West Africa, are seen as the primary markets for such systems.

 

Subsea water injection is used to increase recovery, and is thus important for value creation. Injection normally requires water treatment, which means larger platforms and higher development costs. In conventional injection systems the water treatment is performed topside and high pressure water pipelines to the wells are installed. With subsea water injection the whole system is placed on the sea floor, only requiring power from shore/host.

The main potential advantages of subsea water injection includes the ability to avoid expensive high pressure flowlines, potentially expensive topside modifications and enabling more flexible development solutions in terms of injection well placement and timing. The first system was installed at Columbia E in the UK part of the North Sea in 2007. Since then, similar systems have been installed at the Tyrihans field in Norway (2011) and at Albacora L’Este in Brazil (2013). However, the costs are still high and will need to come down in order to see more widespread use of these systems.

Subsea compression increases the pressure difference driving the gas through the flowline, and it effectively lowers the wellhead pressure, thus speeding up production and increasing recoverable reserves. The compressor can be placed close to the well, which increases and accelerates the production. Until recently the solution has been to install gas compressors on an existing platform, or to build a new staffed compression platform. By taking the compression subsea one can reduce the need for additional platforms. However, subsea compression systems are complex and require large gas resources to justify the investments.

Subsea compression is a technology under development and remains to be proven, although Statoil has qualified two different systems, Aasgard and Gullfaks Compression, which will be installed in 2014/2015. In addition, the technology has been tested in an onshore pool on the Ormen Lange Pilot project, where Shell is the operator. However, in April 2014 Shell put the concept selection for Ormen Lange on hold citing too high costs and an option value in compression not being time critical. While the Ormen Lange and Aasgard fields will require separation of liquid from the well stream before compression, Gullfaks South will involve compression of wet gas without pre-separation. Aker Solutions is working on the Aasgard project, and they also had the Ormen Lange pilot, while OneSubsea is to deliver the system for Gullfaks South.

With the subsea processing technology continuing to move ahead, the number of platforms may be further reduced in the future, but we are not quite there yet.  Even with a full-fledged subsea factory, the distance to shore might be such that offshore export solutions are preferred and risers will still be needed.

Water pressure and the structural integrity of the risers have been an issue that flex pipe manufacturers have been working on for many years. By the end of the 2000s flexible production risers were approved down to around 2,000 meters, however, there were rigid and hybrid solutions (riser towers/submerged bouys) capable of handling deeper waters. Currently, there are flexible production risers capable of withstanding 2,500 meters, and the qualification of equipment for deeper waters is likely to continue. Into the 2020s we might see water depths at around 3,000 meters, for example with the giant Libra development moving forward in Brazil. These depths are at the limits of what is possible today, but the hope is that emerging composite flexibles (more strength and less weight) will be qualified to handle water depths beyond 3,000 meters.

So what does the future hold for subsea processing? One of the pioneering operators, Statoil, has been speaking about a complete subsea factory by 2020. Although several of the building blocks needed are in place, there is still some way to go in order to reach such an aggressive target. With the current downturn in the market, the mid to late 2020s is probably a more realistic target before such a complete subsea facility is tested and in place. There are several challenges towards the full-fledged subsea factory. Some of the obstacles needed to be overcome are:

  • Power distribution: Large subsea fields with high power inputs, many components and long step-out distances means that subsea variable speed drives (VSD’s) will be needed to convert, distribute and control the electricity. The subsea components run on High Voltage Alternated Current (HVAC), which has limits on transmission distance relative to power, meaning that High Voltage Direct Current (HVDC) may be needed. Major electro and automation companies like ABB and Siemens are working on these aspects.
  • Control systems: Putting all the equipment subsea also increases the requirements for the control systems. There will be a need for increased bandwidth, real-time information on system performance, in addition to increased demands on safety functions and regularity.
  • Oil storage: Not seen as a major technological challenge by the operators, but a system still needs to be tested and qualified. Kongsberg Oil & Gas have an ongoing development project for Statoil.
  • Monitoring: Knowing the state of the well stream will be crucial in terms of production monitoring and flow assurance. Improved reliability for subsea and multiphase sensors will be key.
  • Subsea well intervention and maintenance: Subsea processing fields bring challenges related to year-round well intervention and maintenance operations from ships in high waves, particularly the handling of large and heavy processing modules. The reduced accessibility of a subsea installation compared to a topside brings additional requirements to the system up time, maintenance on demand and a general optimization of the intervention frequencies. To handle the up to 400-ton modules at Aasgard, in waves of 4.5 meters, Technip is supplying Statoil with a new handling systems to lower and raise modules over the side of the vessel.
  • Integration, reliability and cost: Enabling and qualifying the integration, i.e. cooperation between all of the components is a key challenge. Standardization has long been a key topic, but it has a tendency to be a `yes we want standardization, as long as it is according to our specifications.’ In addition, the equipment needs to be more robust, have a proven high reliability and come down on price.

Considering the number of subsea fields (~1,500) compared to the number of subsea processing projects (boosting ~30, separation ~ 15, compression ~3), the current technology adoption is low. The main reasons for this are related to costs, uncertainty regarding reliability (proven on boosting and separation by now), and a general conservatism in the industry. These factors are likely to be spurred on by the current cost sensitive environment where low risk solutions seem to be preferred and the current downturn in the market might be a bump in the road in terms of realizing the subsea factory.  However, looking towards the end of this decade and into the 2020s, offshore field developments are forecasted to be one of the most important sources for new liquids production. With shelf production maturing and the most prospective areas becoming deeper and deeper, the need for these technologies will only continue to increase.

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Contacts

Contact: Jon Fredrik Müller, Senior Project Manager
Phone: +47 24 00 42 00
Jon.Fredrik.Muller@rystadenergy.com

Contact: Julia Weiss, VP Marketing
Phone: +47 24 00 42 90
Mobile: +47 48 29 87 61
julia.weiss@rystadenergy.com


About Rystad Energy

Rystad Energy is an independent oil and gas consulting services and business intelligence data firm offering global databases, strategy consulting and research products.

Rystad Energy’s headquarters are located in Oslo, Norway, with additional research teams in India. Further presence has been established in the UK (London), USA (New York & Houston), Russia (Moscow), Norway (Stavanger), Africa as well as South East Asia.