Subsea processing involves combinations of fluid conditioning and pressure boosting of well stream fluids and water at the seabed. It can include water removal from hydrocarbons, separation of liquids from gas, separation of sand and other solids from fluids, fluid cooling or heating, and chemical injection.
“The four main types of subsea processing applications include single and multiphase hydrocarbon boosting, subsea gas compression, separation systems, and raw seawater injection,” said Simon Davies, technology projects manager for Statoil.
“These cannot be implemented, however, without long-distance high-voltage power supply and distribution, advanced process monitoring and control systems, and cost-effective installation, maintenance and retrieval systems,” Mr Davies emphasized.
Benefits of subsea processing include increased hydrocarbon recovery and accelerated production. Lower field development costs, both capital and operating costs, and increased development flexibility through reduced needs for offshore topsides facilities and modifications also are benefits. Safety risks are minimized due to reduced fire and explosion hazards. Chemical consumption is reduced, fewer crew members are required aboard a platform, and there is increased energy efficiency.
The benefits aid operators in accessing additional resources in existing fields and near-field locations. They also help operators in new areas, including ultra-deepwater, remote locations and harsh environments, including Arctic and sub-ice locations.
“These and other benefits increase as the step out and water depth increase,” Mr Davies said.
Statoil experience
Statoil was a pioneer and early adopter in subsea processing and is currently operating, installing or developing all of the previously mentioned types of subsea processing. It installed hydrocarbon boosting on the Lufeng and Tordis fields, separation systems on the Troll and Tordis fields, and raw seawater injection on the Tyrihans field. Gas compression is being considered for the Asgaard and Gullfaks fields. Statoil is also responsible for the pilot test unit for the Ormen Lange field operated by Shell.
The company’s vision is to develop and deploy all of the necessary technology elements for a “subsea factory,” the equivalent of a topside processing facility to be operated on the seabed and enabling remote subsea-to-beach hydrocarbon transportation solutions in any offshore location.
Future opportunities
Statoil will continue to introduce value-creating technology, and it’s important to note that, once a technology has been deployed, it is replicated in new locations in order to generate additional value, including re-use of knowledge and an introduction of a standardization mindset in subsea processing.
The company recently completed an internal strategy process that identified a significant number of new subsea processing opportunities during the next dozen or so years. A stepwise development “ladder” was produced illustrating opportunities within boosting, separation systems, compression and raw seawater injection. The company intends to pursue a structured focus on the early development of a business case for each concept.
Subsea boosting
For example, a subsea boosting opportunity has been identified in the Norne field, with boosting of fluids as the water cut increases toward the end of field life to aid in maintaining production. “Three pump stations with a total power requirement of 4 MW are being assessed,” Mr Davies said.
An advantage of this application is that the pump specification will not require additional technology qualification since the operating envelope already is qualified for the Tordis field. However, Mr Davies explained, there are some technology challenges to overcome related to finding space on the FPSO for the topsides power system to optimize utilization of the high-voltage power swivel and umbilical and power distribution for the system.
Subsea boosting, possibly combined with downhole electrical submersible pumps (ESP), is likely to be an enabling technology for developing deepwater Gulf of Mexico fields, Mr Davies said. Many of the Gulf blocks where Statoil is operator have reserves located at more than 30,000 ft deep, which is why a combination of subsea pumps and ESPs may be required.
Subsea separation
Subsea separation is being considered for the Astero field development located approximately 35 km north of the Troll field. One development option is a subsea tieback to existing infrastructure. Using subsea separation and multiphase boosting would make it possible to route the gas to the Gjoa field processing facilities and the liquids to the Troll C floating production facility. A 1.5 MW multiphase booster will likely be employed upstream of the separator. Several options are being evaluated for the separator concept, including a conventional vertical separator that can be fitted into an available well slot on one of the Astero templates.
One of the challenges is a requirement for effective gas/liquids separation since the gas is planned to be routed to Gjoa without use of hydrate inhibitors.
Compression
Statoil identified several opportunities for deployment of subsea compression technology. For example, subsea compression has been conceptually evaluated for the Snohvit field. In addition to utilizing subsea compression for boosting of gas to a host facility offshore or onshore, opportunities for subsea gas recompression and injection are being considered. Subsea compression technology already has been qualified for part of the Gullfaks, Asgaard and Ormen Lange technology developments.
Raw seawater injection
Subsea raw seawater injection on the Tyrihans development will provide valuable operating experience for further deployment of the technology, coupled with improvements in particle filtration and water disinfection technology. Raw seawater injection and the other processing technologies noted above are all under evaluation as part of Statoil’s Norwegian Continental Shelf redevelopment study under way.
New applications and technologies
Mr Davies noted several new technology and application developments in applying subsea processing. The vision of the “subsea factory” may drive the application of more sophisticated gas processing on the seabed, for example. Additionally, reinjection of produced water for pressure support rather than disposing them will bring more stringent requirements for produced water quality, requiring effective subsea produced water treatment and monitoring.
Also, Mr Davies noted, pumping and compression technology will continue to evolve, with more robust and simplified systems capable of greater pressure boost while handling liquids without the need for upstream scrubbing. Separation systems will incorporate compact separation technologies.
“Close cooperation with suppliers and other partners will continue to be essential to realizing these new business opportunities,” Mr Davies concluded.
