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Subsea Systems

Despite uncertainties related to oil and gas industry dynamics and new requirements to reduce CO2 emissions, ­energy demand is expected to continue to grow. It is also expected that the mix of energy shares will change significantly in the next 10–20 years. Natural gas and renewables (wind and solar) gradually will represent a larger part of the energy mix, balanced by a drop in reliance upon fossil fuels such as oil and coal.

Some of the largest reserves of natural gas are located under deep waters, far from shore or any other existing infrastructure. Examples of areas where such field development is under way include western Australia, the North Sea, the Mediterranean, and southeast Africa. Among the many challenges often experienced in such fields is the requirement to transport gas in ultralong pipelines back to shore; in some instances, tiebacks are 100- to 250-km long and water depths can reach more than 2000 m.

Subsea gas-compression technologies have been developed, tested, and successfully deployed in recent years, and operators now are using these technologies to make remote subsea gas fields profitable.

Systems for subsea gas compression have reached Technical Readiness Level 7. After being in operation at the Gullfaks field and at the Åsgard field in the North Sea for several years, these technologies are now being considered for future field developments, not only in the North Sea but also in other parts of the world.

In the Åsgard subsea-compression system, the gas condensate is separated subsea so that the gas can be compressed by a centrifugal compressor and the liquids can be pumped. Gas and liquid then are commingled downstream of the compressor station, and the mix travels in a pipeline to a processing facility 40 km away.

The Gullfaks compression system uses a multiphase compressor technology that has been developed to handle mixtures of gas and liquid; hence, no separation or liquid pumps are required subsea. The result is that the weight and volume per unit of compression power are greatly reduced and the system becomes ­relatively small and less complex.

Both operational experience and studies of future offshore gas-field developments are showing that subsea gas-compression systems not only reduce investment costs but also increase ­recovery significantly.

New solutions, supported through relevant field studies, will be analyzed in the studies presented in this section.

This Month's Technical Papers

Developing Technologies Can Lower Subsea Tieback Cost

Subsea Multiphase Gas Compression System Offers Competitive Advantage

Flow-Assurance Strategy Manages Subsea Asset Without Continuous MEG Injection

Birger Velle Hanssen, SPE, is the global sales manager for subsea multiphase flowmeters at OneSubsea, a Schlumberger company, a position he assumed in 2018. Previously, he was product manager for subsea boosting and compression. Hanssen has more than 30 years of experience in subsea technology, covering a wide range of competencies, including mechanical design, product development, sales, and management. He has presented papers at various SPE conferences on subsea processing technologies. Hanssen holds a master’s degree in mechanical engineering from the Norwegian University of Science and Technology and is an active member of SPE. He is a member of the JPT Editorial Committee and can be reached at bhanssen@slb.com.

Subsea Systems

Birger Velle Hanssen, SPE, Global Sales Manager, OneSubsea, a Schlumberger Company

01 August 2020

Volume: 72 | Issue: 8

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