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Subsea processing benefits

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As oil and gas production moves into deeper water, the cost of surface production platforms becomes prohibitively high. The industry has found that surface facilities must be kept to a minimum and shared by satellite fields to be commercial. Subsea processing is a key toward a cost-effective, “hub-and-spoke” development (Fig. 1), allowing the industry to operate successfully in deeper water.

Advantages of subsea processing

Subsea processing refers to the separation of produced fluids into gas and liquid—or gas, oil, and water—for individual phase transport and disposal (in the case of water). The liquid stream can be pumped to a central facility for final processing. The gas stream can be transported under natural pressure or pressure boosted (compressed) to the host facility.

The current practice is to flow produced fluids from subsea wells directly back to a central surface processing facility in multiphase (gas, oil, and water) pipelines, known as a “subsea tieback” field development. Because reservoir pressure is the only source of energy to overcome all the impediments to flow [e.g., pressure drop through the formation, wellbore, tubing (friction and static head), tree, flowline, and so on] well productivity for normally pressured reservoirs tends to be low, and the “tieback” distance is typically limited to less than 25 miles. In addition, multiphase pipelines potentially have many flow-assurance problems, like:

  • fluid slugging
  • hydrate formation
  • wax deposition
  • solids dropout

Subsea processing offers a technical solution to many of these problems. It can accomplish the following:

  • Improve well productivity with greater pressure drawdown.
  • Increase ultimate recovery by extending economic life.
  • Eliminate fluid surges by use of single-phase pipelines.
  • Avoid gas hydrates with no inhibition or with reduced inhibitor dosage.
  • Prevent solids dropout by allowing higher liquid-flow velocities.
  • Allow online pigging to control wax deposition in oil pipelines.
  • Reduce capital and operating costs by reducing surface processing needs.

Improved reservoir productivity

A key benefit of subsea processing (separation and liquid pumping) is greater pressure drawdown, which results in higher production rates and greater oil and gas recovery. Separating the produced fluids on the seabed allows the liquid to be pressure-boosted with an efficient conventional mechanical pump. Single-phase pumping overcomes the static backpressure of the fluid column from the seafloor to the surface, and it avoids the excessive pressure drop and surges of multiphase flow.

As illustrated in Figs. 2 (left) and 2 (right), for a typical deepwater development in 6,000 ft of water, flowing tubing pressure at the seabed may be 1,800 psi, even with a separator inlet pressure of only 200 psi on the platform. Much of the 1,600-psi pressure drop takes place because of hydrostatic head of the fluid (gas and liquid) column. If the separator can be located at the seabed, a significant portion of the 1,600 psi can be used as additional reservoir pressure drawdown. Assuming a modest productivity index (PI) of 5 bbl/psi, a production increase of 8,000 B/D per well may be realized. As reservoir pressure declines, reduced backpressure may extend the productive life of the field and increase ultimate hydrocarbon recovery. Because productivity and reserves recovered per well are key to field economics, use of subsea processing can greatly enhance the value of some deepwater developments.

Deepwater and long-distance tiebacks

Subsea processing moves the productivity limiting influences to the seabed and decouples the reservoir development from water depth. The source of flowing tubing pressure drop is only between the wellbore and seabed, rather than all the way up to the platform elevation. This has greater impact as production advances into deeper water, especially for shallow, low-pressure reservoirs in deep water. Similarly, the pressure-boosting benefits of subsea processing will enable longer distances from the subsea tieback to a host platform. Most direct subsea tiebacks are limited to approximately 25 miles because of available flow energy from the reservoir.

With subsea separation and liquid pumping, most of the energy required to transport the produced fluid is supplied by mechanical means rather than totally by reservoir pressure. Subsea liquid pumps are currently available for most applications. Separator gas can flow long distances under natural pressure. As advances are made into large-capacity subsea power supply and compressor systems, subsea gas compression will become another viable option, enabling smaller pipeline size and even longer transport distances.

Flow assurance

Flow-assurance problems such as multiphase flow, hydrate formation, and wax deposition are detrimental to deepwater and long-distance subsea tieback projects. In a direct tieback, major operational difficulties can be caused by:

  • fluid slugging
  • excessive pipeline pressure drop
  • startup dynamics

Such issues can require large investments in topside facilities. Gas hydrate formation is difficult to avoid in the high-pressure, cold deepwater environment. Using insulated and heated bundles and large quantities of chemical inhibitors are costly and not effective under all circumstances. With waxy crude production, pipeline plugs are a constant challenge. Because there is no universal inhibitor for wax, finding an effective chemical for a particular crude is always uncertain and sometimes not possible. Regular round-trip pigging (in a dual pipeline system, sending a pig from the host platform to the subsea well manifold and returning it by a crossover into the other pipeline) is the only reliable solution. But this method of pigging requires production shutdown that can be lengthy because of difficulties in restarting the wells and re-establishing flow.

Subsea processing can be a cost-effective solution to flow-assurance problems. In a subsea system depicted in Fig. 3, wellstreams are separated and transported in separate pipelines, which eliminates multiphase flow and associated problems. Separator gas entering the pipeline is saturated with water; therefore, hydrate formation is still a concern. However, the amount of water that must be inhibited to prevent hydrates is relatively small and very predictable. This eliminates the need for overinjection of inhibitor to combat water slugs and allows the use of the more environmentally friendly inhibitor, glycol, which can be easily recovered and regenerated at the host platform. Unlike methanol, glycol has a very low vapor pressure and is less prone to vaporization losses.

With waxy crude pipelines, regular and frequent pigging is the only sure way to guard against wax plugs. An automatic subsea pig launcher, working in conjunction with a subsea separation and pumping system, may solve the problem. Because the system downstream of the separator is decoupled from the flowing wells and the reservoir, it is possible to pig online without production interruption. Any additional frictional pressure drop because of pigging can be overcome by the pump. Similarly, flow velocity in the pipeline can be kept high (at the expense of horsepower) to avoid produced-solids dropout, if that is a problem. With a replaceable multipig cartridge, pigs can be launched on a regular basis at a time frequency matched to the estimated rate of wax or solids deposition.

Topside facilities limitations

With subsea processing, produced fluids arrive at the host platform already separated into their respective phases, so the need for large slug catchers and separators is reduced or eliminated. Degassed oil and water may be further separated at the seabed, and the produced water reinjected back into subsea wells. Seabed separation and water reinjection increase oil pipeline capacity, reduce pipeline internal corrosion and water treatment on the surface, and reduce overall power demand. This is the natural progression from two-phase (gas-liquid) separation as the field matures and water production increases.

Unmanned and minimum facilities developments

One way to reduce field development costs and improve project economics is to increase well productivity and reduce facility costs. As discussed earlier, subsea processing can improve well productivity and increase ultimate recovery. It can also enable unmanned minimum production facilities developments that do not need costly pipelines. An illustration of such an infrastructure independent system is shown in Fig. 4.

An infrastructure independent development for a remote deepwater field is built around subsea processing. Fluids produced by subsea wells are separated in a subsea separation system. The gas is routed to the surface for conversion to liquefied natural gas (LNG) or compressed natural gas (CNG) and tanker transport. Separated oil is routed to a seabed-grounded tank, where it is stored until sufficient volume has accumulated for tanker offtake. A local unmanned buoy can provide power and control functions. Most of these technologies either are being, or have been, deployed in some form. Subsea wells are well accepted and commonly used. Subsea processing technologies are beginning to be employed with the advent of deepwater developments.

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See also

Subsea processing overview

Subsea processing design

Subsea process configurations

Subsea processing technology

Downhole processing overview

PEH:Subsea and Downhole Processing