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 the near future. 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 recently delivered the system for Gullfaks South.
With the subsea processing technology moving forward, the number of platforms may be reduced in the future. 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 6,562 ft (2,000 m), 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 8,202 ft (2,500 m), and the qualification of equipment for deeper waters is likely to continue. Into the 2020s we might see water depths at around 9,843 ft (3,000 m), 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 9,843 ft (3,000 m).
What does the future hold for subsea processing? Statoil is working on completing the subsea factory by 2020. Several of the building blocks needed are in place, however, this vision needs to be fine tuned 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 toward the full-fledged subsea factory.
Some of the obstacles needed to overcome are:
Power distribution. Large subsea fields with high power inputs, many components and long step-out distances means that subsea variable speed drives will be needed to convert, distribute and control the electricity. The subsea components run on high voltage alternated current, which has limits on transmission distance relative to power, meaning that high voltage direct current 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 functionality and regularity.
Oil storage. Not seen as a major technological challenge by the operators, but a component that needs to be tested and qualified. Kongsberg Oil & Gas has 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 multi-phase sensors will be key.
Subsea well intervention. 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 topsides, brings additional requirements to the system uptime, maintenance on demand and a general optimization of the intervention frequencies. To handle the up to 400-ton modules at Aasgard, in waves of 15 ft (4.5 m), Technip is supplying Statoil with a new handling system 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 with standardization being a key topic. In addition, equipment needs to be more robust, have a proven high-reliability and a decrease in cost.
Considering the number of subsea fields (~1,500) compared to the number of subsea processing projects (boosting ~30; separation ~15; compression ~three), 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 by the current cost-sensitive environment where low-risk solutions seem to be preferred. This downturn in the market might be a bump in the road in terms of realizing the subsea factory. However, looking toward 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 in deeper depths, the need for these technologies will increase.