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Subsea processing design
Designing a subsea processing facility is dependent on factors such as:
- Reservoir characteristics
- Expected production volumes
- Water depth
- Distance from surface facilities
- Capacity of surface facilities.
How these and related factors affect subsea processing design are discussed below.
The value of subsea processing is determined primarily by reservoir characteristics and water depth. Well productivity index (barrel per psi drawdown or PI), which is a function of reservoir permeability, is one of the keys. A high PI will leverage the reduced backpressure provided by subsea processing to higher production rates. This can have enormous economic implications for low-pressure reservoirs in deep water. With depletion-drive type reservoirs, the benefit will increase with time as reservoir pressure declines. Increasing water production will make the pressure-boosting effects of subsea processing more dramatic. For reservoirs without competent source rocks, good completion design is imperative to take advantage of the greater pressure-drawdown opportunity. If the well is choked back to avoid excessive sand production or formation damage, the full potential of subsea processing will not be realized. Because subsea processing can only impact the fluid column from the seabed to the surface, shallow reservoirs in deep water play to its strength. This is illustrated by Fig. 1 for a typical depletion reservoir.
As depicted in Fig. 1, the incremental recovery factor for subsea separation decreases with reservoir depth. Pressure boosting is most efficient when applied at the source. As reservoir depth increases and/or water depth decreases, downhole processing is more beneficial.
Water depth and tieback distance
The benefits of subsea processing increase with water depth and tieback distance. However, they also present greater technological challenges. Water depth has the greatest impact on liquid pumping. Because the separated oil must be pumped to the surface, the subsea pump must be able to generate high enough pressures to overcome the hydrostatic head of the liquid column and the flow-induced friction in the pipeline. In most applications, this would require multistaged centrifugal pumps operating at the low end of their flow range. The high-head, low-flow requirements narrow the operating range of the available subsea pumps, making pump selection difficult. Although for most fluids the liquid-pumping energy requirement is much less than that of gas compression, it is still a challenge to supply subsea, given the state of the technology. Electric motors or hydraulic turbines may be used to drive the pump. However, both types of systems have limitations.
Until the challenges associated with subsea gas compression can be solved, gas must be piped to the host platform under natural pressure. Given the low specific gravity of gas, water depth, which impacts pressure drop because of fluid head, should not be an issue. However, long-distance tieback can be a challenge. Subsea processing provides greatest benefit at low seabed separator pressure, so the gas pipeline must be sized for minimum pressure drop. That usually means larger diameter, and thus higher cost. Gas leaving the separator on its way to the pipeline is at its hydrocarbon and water dewpoints. It is important for pipeline hydraulic performance that heat exchange with the seawater environment and gas phase equilibrium be carefully balanced to avoid excessive liquid condensation in the pipeline.
Subsea processing can range from simple two-phase separation to a complex gas/oil/water separation for individual phase transport and/or disposal. The choice depends on what one is trying to achieve with the system, how difficult the fluids are to separate, expected value to be gained by the project, and risk tolerance. Separation philosophy will drive the system design and ultimately the success of the project. The state-of-the-art should be carefully considered at the time of decision. Subsea technologies are advancing rapidly. What was once deemed high-risk (i.e., subsea well systems) is common practice today. All forms of subsea separation may well be at that mature state by the time they are needed.
Capacity of topside facilities
A driving force for subsea processing is the lack of topside capacity at existing host platforms and high cost for facility expansions. Because of fluid slugging potentials, direct tieback using multiphase flow pipelines may require unacceptably large slug catchers. Space may not be available for the additional phase-separation and water-treating facilities. With partial or full processing on the seabed, the need for topside facilities may be significantly reduced. Availability and cost of topside capacity may influence the degree of preprocessing that makes sense on the seabed. As with most engineering decisions, life-cycle economics (capital and operating costs) will dictate the most cost-effective design.
Operating range and turndown requirement
Production rates will vary over the life of the field, as gas/oil ratio and water cut increase and reservoir pressure declines. All production systems must function over the expected operating range. In fact, some systems are asked to operate out of their design range because it is nearly impossible to predict with accuracy field performance before first production. It is not unusual for topside facilities to be modified to accommodate out-of-the-range operations, sometimes only shortly after startup. The consequence of missing the mark with subsea processing can be very costly. Whereas surface facilities are easily accessible, subsea system interventions may require special equipment that is not readily available, such as Remote Operating Vehicles (ROVs), heavy-lift vessels, dedicated tools, and instruments. Protracted loss of production and callout costs could doom the economics of a project. All these factors must be addressed in the subsea system design and the risk mitigated with robust and flexible engineering and equipment selection. It is imperative that a best effort be made to define the expected operating range and the equipment turndown capability required. It may not be possible for certain pieces of equipment to operate efficiently over the life of the project. In this case, a thorough contingency plan, perhaps with the system designed for scheduled equipment replacement, needs to be developed and taken into account in determining the project economics.
Instrumentation and monitoring
In many ways, operations of subsea facilities may be more stable because there is less opportunity for operator tinkering. By their remote nature, subsea systems are engineered with a high degree of automation. Nuisance trips because of human errors should be reduced. However, the consequences of instrumentation failure are much more serious. System reliability will depend on the robustness of the instrumentation and quality assurance/quality control (QA/QC) of the installation. When these systems fail, as they inevitably will, a well-designed monitoring system will speed problem identification. The importance of proper control system design, instrument selection, and installation cannot be overemphasized.
How and what well-test data are to be acquired (for reservoir management and well-system diagnostics) are always contentious with subsea well and processing systems. To reduce equipment count and cost, some have proposed a system of well test by difference, that is, to shut in a well, and the loss of production is attributed to that well. The drawback is that production is lost during the test period, and bringing back the well may be problematic.
Others have proposed using a dedicated well-test system, such as a separate test separator and manifold, similar to those facilities on the surface. The components for subsea well-test separation system are available and essentially the same as for the main separation system, but add tremendous complexity, size, cost, and potential risk of failure to the overall system.
A more cost-effective option may be the use of subsea multiphase meters. A meter installed on each wellstream can provide individual real-time production data. These nonintrusive devices are submarine versions of their well-proven surface counterpart. Although they are not yet commonplace items (only a few dozen in service as of 2002), they are gaining acceptance in the subsea community. Meter performance, quality, and reliability have improved, while the cost has dropped with successive generations.
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