Subsea gas-liquid separation coupled with liquid boosting can be an effective means of oil reservoir exploitation.
Despite advances, multiphase pumping technology remains limited in its capabilities. Dynamic (centrifugal and helico-axial) pumps function with reasonable efficiency for single-phase, low-viscosity liquids. However, they become very inefficient when a high-viscosity liquid is combined with high percentages of free gas.
While use of multiphase pumps is in many instances an effective solution, special consideration must be taken when challenging conditions exist such as are found in deeper water or with long tieback distances, or when heavy-oil production is involved.
More effective oil reservoir exploitation can be achieved using subsea separation coupled with liquid boosting. This enables production at very low flowing tubing head pressure, around 500 psi, even when water depth approaches 10,000 ft (3,000 m) and distance from the host exceeds 30 miles (48 km). This method also works well where heavy oil or low-reservoir pressure exists. When combined with gas-lift of the production wells, this method is very efficient.
Shell´s Parque das Conchas (BC-10) project is a good example, demonstrating that gas-liquid separation prior to liquid boosting improves recovery considerably more than boosting alone, while adding only limited incremental technical costs. Single-phase pumping combined with gas-liquid separation delivers the performance needed to exploit a reservoir’s full potential, while providing enhanced flow-assurance capabilities.
The Shell BC-10 block is located approximately 120 km (75 miles) southeast of the coastal city of Vitoria, in the state of Espirito Santo in water depths ranging from 1,500 to 2,000 meters (4,920 - 6,562 ft). This development project is the first full field development based on subsea oil and gas separation and subsea pumping in Brazil.
In this project, the hydrate management philosophy consists of venting of pressure at both ends of the pipeline enabling the pressure to be safely reduced to outside the hydrate envelope.
Oil that has been flashed at 500 psia in a subsea separator will have a new bubble point. This low bubble point means there is very little free gas, even under venting, thereby minimizing the possibility of hydrate formation.
This fact, when added to the ability to vent from both ends of the pipeline, could give enough confidence regarding hydrate formation and remediation to make other hydrate management technologies unnecessary. Other flow assurance concerns such as liquid slugging are also minimized and where wax may be an issue, round-trip pigging through the gas line and back through the liquid line is still possible.
The BC-10 and also Shell´s Perdido project in the GOM, use separators that are identical and based on a caisson separator design. In these projects, multiphase fluids are conditioned in the inlet piping and enter the inlet block at a downward angle and at a tangent.
This results in the liquids disengaging from the gas and swirling down the inside diameter of the caisson. The tangential velocity keeps the liquid from re-entraining in the gas traveling upward. There is approximately 100 ft (30 m) between the inlet nozzle and the normal liquid level. This provides upwards of 100 bbl (16 cu m) of liquid slug capacity. Just above the inlet is a gas polishing section with 32-in. inside diameter.
Subsea separation is one of the most innovative technologies being applied in the oil and gas industry today. The need exists to maximize recovery, increase pressure and hydrocarbon output at fields with low reservoir pressures, address and minimize hydrate formation risks and also to reduce constraints on topside facilities.
Treating production right at the seabed level equates to more efficient exploitation of an oil reservoir.
Probably the most important factor is that subsea gas-liquid separation coupled with liquid boosting, maximizes the potencial for higher recoveries from subsea reservoirs.
Photo courtesy of FMC Technology