Selecting the Right Subsea Pump for Your Application
Subsea gas compression and pumping technologies have been identified as a solution for accessing gas reservoirs that may be otherwise inaccessible or economically unfeasible to drill. Subsea stations offer a fast-track development solution with flexible, multiphase deployment and other inherent advantages. Pumping stations require a significant amount of process equipment improvements and integration solutions; however, the complete paper focuses on the rotating machinery, process pumps specifically.
Subsea development is a relatively recent concept associated with comparatively underresearched and unqualified technologies. The technological improvements necessary are characterized by requirements for severe service, multiphase handling, excellent reliability, and minimal, low-maintenance solutions.
Operating Conditions for Subsea Pumps
Depending on the application for which the subsea pump is being used, fluid can be either a produced fluid, produced water, or raw seawater. Losses in a subsea pipeline are mainly caused by friction and gravity. While estimating the losses, one should first establish the flow type and flow regime (i.e., whether the flow is single-phase or multiphase). Once the flow type is established, the losses or pressure drop in the pipeline can be easily calculated.
Flow rate. Because the flow rate from a depleting wellhead will inherently fluctuate, the pump requires a capacity-control system. For subsea applications, a variable-speed drive (VSD) is most commonly applied. VSDs require some additional capital expenditure but can lead to savings in the long term. Rather than using a mechanical method of control, they electrically control the speed of the pump converting the fixed based frequency/voltage input to a variable frequency/voltage output so that it is operating at its most efficient, and they tend to keep system pressure constant.
Operating temperature. The operating temperature will depend on the reservoir properties as well as the placement of pump in a subsea processing system. While raw seawater injection pumps are expected to operate at low temperatures, the produced water injection pump will see low-to-moderate operating temperatures. On the other hand, pumps handling produced fluids will see very high temperatures that can exceed 120°C.
Water/oil ratio (WOR). WOR is a reservoir property that dictates the density of produced fluid. Accurate estimation of expected WOR will enable the pump manufacturer to select and size the driver. If enhanced oil recovery by water injection is envisioned, then this estimate will also take into consideration the effect of waterflooding on the WOR or produced-fluid density.
Reliability. Reliability calculations should play an integral part of the product life cycle. It is necessary to consider reliability from the design phase, facilitating overall machine availability, maintainability, and safety of the system. While these are independent factors to consider in their own right, each has an effect on the others. Modularization of the design is important because not all failures can be foreseen and not all repairs can be carried out remotely. Modules that cannot be repaired in situ should be designed for ease of retrieval.
Safety. Safety analysis is a continuation of reliability analysis. While the prime objective of reliability analysis is to determine, and prepare for, the various ways that a system can fail, safety analysis provides an idea about what effects such a failure could have. An additional goal of safety analysis is to establish the ways in which the identified failures can be mitigated or avoided, thereby forming a vital component of risk-avoidance methodology.
Material Selection for Subsea Pumps
Subsea environments are severe service environments with high temperature ranges and an array of potential methods of corrosive attack. Inclusion of solid particulates can quickly wear down impellers and casing material of even high-hardness material. The process fluid will contain wet hydrogen sulfide. In addition, carbon dixodie (CO2) will be present either from the well or from high-pressure CO2-injection techniques, also dissolving in water to form carbonic acid.
Seawater itself will attack exposed material through pitting and corrosion. It will be necessary for insulation and high-specification paint to be applied to the casing if the pump will be deployed for long periods of time without maintenance. Materials used in maritime environments are largely limited to aluminium bronzes and nickel/copper alloys, nickel-based superalloys, and stainless steels.
Aluminium bronzes are a viable candidate; however, they can be somewhat costly and are subject to some material-specific difficulties such as dezincification and the need to avoid galvanic corrosion. Additionally, most grades give hardness measurements of just over half of stainless steel, increasing the chances of erosion problems.
Nickel-based superalloys are sometimes applied in extremely severe service conditions but, owing in part to their high cost, are more commonly used for smaller components or fasteners, not large housings.
Stainless steels are in all likelihood the prime candidate material for this service, with strong corrosion resistance, good mechanical toughness, a history of successful marine environment performance, and attractive cost and availability.
Subsea pump selection. Broadly speaking, there are two categories of subsea pump: rotodynamic pumps and positive-displacement pumps. The rotodynamic class consists mainly of two types, electrical or hydraulic-submersible pumps (ESPs/HSPs) and helicoaxial pumps (HAPs). Positive-displacement pumps are twin-screw pumps (TSPs).
ESPs/HSPs. An ESP is a centrifugal pump driven by an electric motor. Apart from the motor and a multistage centrifugal pump, the system consists of a seal section, a gas separator, a power cable, a surface-control mechanism, and a transformer. ESPs are suitable for flow rates ranging from 1,000 to 20,000 B/D. However, ESPs are not suitable for a low gas/volume fraction (GVF) of less than 10. The ESP system is very versatile and can be installed vertically or horizontally.
HAPs. HAPs are a combination of a centrifugal pump and an axial compressor (Fig. 1). They include an in-line multistage barrel pump in which each stage consists of a helicoaxial impeller mounted on a rotating shaft followed by a diffuser.
The pump is capable of handling a GVF ranging from 0 (100% liquid) to 100 (100% gas). The pump is hydraulically very flexible, which makes it suitable for a wide range of duties, including subsea applications, where changing reservoir characteristics demand high hydraulic flexibility. The pump design is robust enough to handle sand content. HAPs are suitable for a flow range of 0,000 to 450,000 B/D and differential pressure up to 200 bar.
TSPs. The TSP is a rotary-type positive-displacement pump that displaces the fluid from suction to discharge (Fig. 2, at the top of the article). The pump is capable of handling a range of viscosity. With careful selection of material of construction for wetted parts, the pump can also be used in an environment with a significant amount of sand and other solid content. TSPs can handle flow rates of 10,000 to 440,000 B/D and a range of GVF from 0 to 100.
Flow Capacity. ESPs/HSPs. The minimum capacity for a centrifugal pump is restricted by increase in vibrations [minimum continuous stable flow (MCSF)] and temperature as the flow is reduced. The pump design should be equipped with suitable measures such as automatic recirculation line against excursions below MCSF.
HAPs. Because these are a combination of centrifugal pump and compressor, their minimum capacity is also limited, in addition to MCSF, by a phenomenon known as surging. Therefore, the pump should be furnished with measures to protect against both.
TSPs. The minimum capacity for TSP pumps is not limited by any of the previously mentioned parameters.
Each design has limitations when it comes to the maximum flow the pump can deliver. While ESPs/HSPs are suitable for low-flow applications, TSPs are better suited for moderate flows, and HAPs are suitable for high-flow applications.
Differential Pressure. Centrifugal pumps are the first choice for high-differential-pressure applications, while TSPs and HAPs are suitable for low to moderate ranges of differential pressure.
GVF. ESPs/HSPs are only suitable for flow having a low GVF of less than 10%, while TSPs and HAPs are capable of handling a high range of GVFs from 0 to 100, which makes them suitable for subsea pump applications in which multiphase flows of varying GVFs are expected.
Sand content. ESPs are not suitable for applications in which sand content is expected, but HAPs and TSPs with hardened screws are suitable choices for such applications.
Viscosity. Only TSPs are capable of handling high-viscosity fluids.
Reliability. While TSPs and ESPs/HSPs are mature designs, HAPs are still in nascent stages of development when compared to other designs. Therefore, from a reliability perspective, more data are available for ESPs/HSPs as compared with HAPs.
Operating expenditure is high for all types of pumps. Captal expenditure is higher for TSPs and HAPs, while it is considerably lower for ESPs because these can be installed onshore in a jumper and then lowered to the seabed.
Equinor Installs Templates for Troll, Other North Sea Fields
After seeing a significant increase in the price level for subsea equipment, Equinor says it is realizing the ways in which standardized subsea templates help build financial competitiveness. The new standard allowed for the installation of 14 templates in one month.
Subsea Pipelines, Umbilicals Installed for Nova Field
The completion of the subsea installation marks another major step for one of several projects scheduled to tie back to the Gjøa platform in the Norwegian North Sea. Production for the Wintershall Dea-operated project is expected to start up in 2021.
Subsea Markets Face High Stakes if Oil Prices Slide
In a $60 to $70 oil environment, the subsea market is poised to grow around 7% annually up to 2025. But a significant portion of this activity is at risk if the price of Brent crude falls to $50 per barrel.
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09 September 2019
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09 September 2019
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