Subsea boosting is coming under the spotlight, despite and also because of the current low oil price environment. Elaine Maslin reports from Subsea Expo and Subsea Valley.
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Omnirise ECM Subsea Boosting Pump System. Image from Fuglesangs. |
Multiphase subsea boosting technology has been around for some 20+ years and has proven itself on a number of projects, including in deepwater.
It offers the capability to help increase production, reduce topsides facilities and enable late-life production and low pressure or deepwater field production. Where low pressure fields are developed close to high pressure fields it can help increase the low pressure production to the level of the high pressure production and could also help produce the fields with increasing levels of water cut, points out FMC Technologies’ Håkon Bruun, during a presentation at the recent Subsea Valley conference.
Yet, despite the perceived benefits, subsea boosting – multiphase or otherwise, has not been as widely adopted as many thought it would be. There are some 5000+ active subsea wells on 1500 fields out there, yet only about 30 of these have subsea boosting technology on them, Subsea Valley, was told early April.
The low take-out is not stopping an increasing number of firms entering the space and ongoing development in new technologies by the established players, however. In today’s low oil price market, they think there’s an even greater opportunity to be had, as operators look to sweat more out of existing assets.
Some of the latest developments were outlined at Subsea Expo, Aberdeen, and Subsea Valley, held in Oslo, earlier this year.
Aker Solutions
Marco Gabelloni, Aker Solution’s regional concept line manager, presented the firm’s latest subsea multiphase pump technology at Subsea Expo, including the latest MultiBooster, which is planned will be qualified this year.
The new MultiBooster is a multiphase, high-range gas volume fraction (GVF), high delta p system. The design trickery on the Multibooster has been to design a mixed-flow shroud impellor that allows for a high delta P, while minimizing phase separation. It has a 6MW, 6000rpm motor, which means it can provide high delta P at high GVF, Gabelloni says.
It also has an advanced condition monitoring system, with two sets of proximity probes in four locations, so you can accurately measure the rotor displacement.
A first prototype has been tested with joint industry project partners ConocoPhillips, ExxonMobil, and Total. The motor has been running successfully, and production models validated, with 8700 Nm of torque, he says. The system has been put through load and heat runs and more tests due, including locked rotor tests and new load tests. A range of tests for a whole range of gas volume fraction, using water and air as well as model oil and nitrogen will also be run and are due to be finalized by then end of the year.
As part of the project, Aker built a new multiphase test loop at its facility in Tranby, Norway. The MultiBooster will join Aker Solutions other subsea pumps, including a single-phase pump, Liquidbooster, and a Hybrid pump for mid-range GVF, the HybridBooster, developed which was qualified in 2012.
Fuglesangs
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Omnirise ECM Subsea Boosting Pump System. Image from Fuglesangs. |
Oslo-based Fuglesangs Subsea (FSubsea) is developing pumps, single-phase and multiphase, that could eliminate topside support and are seal-less, making it a potentially very easily deployable system on a whole range subsea infrastructures.
“The goal is to make subsea pumps as autonomous as possible,” says founder and CEO Alexander Fuglesangs. Seals and the need for additional topside equipment, such as variable speed drives, “are the main hurdles to subsea boosting today,” he says. The firm’s technology, Omnirise, developed in partnership with National Oilwell Varco (NOV) and help from Innovation Norway, looks to do away with these and make subsea boosting a more attractive option for subsea tiebacks.
The firm, set up in 2013, is a subsidiary of Norwegian firm Fuglesangs, which has been developing subsea pumps and seals for use subsea, as well as in drilling, mining, trenching and naval submarine, for at least three decades.
Omnirise ECM (electric centrifugal multistage) use electric driven centrifugal multistage technology for single-phase and multiphase pumping.
Key to the Omnirise design is making it seal-less and reducing the need for topsides support infrastructure and complex umbilicals, termination end units, subsea pressure casings, topside VSD and HPU., etc., by using a new “Hydromag” technology and a permanent magnetic coupling system to drive the pump and integrating VSDs, created from German firm Voith Turbo’s Voith torque converters, described as being like a car clutch system, into the subsea unit.
The Hydromag system has been developed by Fuglesangs in a project involving NOV and Voirth Turbo. It has a fixed low-speed (3600 rpm) pressure compensated electric subsea motor, magnetically connected, using synchronous magnets, to a variable (0-7200 rpm) high-speed pump, which are hermetically separated thanks to the magnetic coupling system and enables low pressure connectors.
By combining Hydromag and Voith’s torque converter, the booster only needs a power cable from a host facility or shore, as it no longer needs hydraulic lines, or a barrier fluid system due to the motor cooling fluid and the process pump being by the magnetic coupling system. Fuglesangs says to lubricate seals and provide barrier fluid costs US$1.5-2 million per kilometer of umbilical, in umbilical purchase costs.
Furthermore, the firms say the pumps come in cartridges, which can be switched out, to make the system modular. For gas compression, the firm would instead use a gas compressor cartridge.
A 45 KW, single-phase prototype has been developed and is at TRL5, having had 6000 hours running time, without the VSD element.
“You have had 20 years of big companies doing big things, some right, some wrong. We have taken a systematic look at what has gone right and wrong. Seals are 75-80% of the failures, either as a symptom of the failure or the root cause.”
FMC Technologies
Permanent magnet motor technology has also been used by FMC Technologies. The firm worked with Sulzer Pumps for more than eight years and qualified a hybrid, 3.2MW, 5000 psi high boost multiphase pump system (OE: October 2012).
Late last year, a version of this pump was ordered for Shell’s BC10 Parque das Conchas fields offshore Brazil in up to 2000m water depth.
Håkon Bruun, FMC Technologies, said the company’s work in this area involved buying LA-based DDS, Direct Drive Systems, a firm that makes permanent magnet motors and high speed machines to avoid gears, in 2009.
Typically, he says, there are three different types of pump: helicoaxial for multiphase boosting, single-phase pumps using conventional centrifugal pumps for liquids with limited gas, and a hybrid type with one or several helicoaxial impellors in several stages to get the gas volume down so you can then use a centrifugal pump to create high differential pressure.
FMC’s high boost is a hybrid type multiphase booster, combining Sulzer’s pump hydraulics, FMC’s high-speed permanent magnet motor technology and subsea system design into a unit with helicon-axial multiphase pumps, and single-phase centrifugal pumps, which in combination can handle high gas volume fraction and differential pressure.
It’s the permanent magnet motor that is the enabler for this technology, allowing for a wider liquid gap between the pump’s rotor and stationary elements, reducing drag losses and meaning the pump can operate faster than an induction machine, using less energy. The firm was also developing a 6MW, 15,000 psi version.“At FMC, we see subsea boosting has growth potential despite the challenging times in this industry,” he says. “We see several new developments being pushed out with increased focus on existing fields and IOR on existing fields. Subsea boosting could be applied. We also see several new developments.”
GE Oil & Gas
GE Oil & Gas is running a joint industry project (JIP) to develop a new, simplified subsea boosting system, which could reduce lifecycle costs and improve flexibility. The initial phase of the JIP on the so-called modular contra-rotating pump (MCP) includes Statoil, Total and two other operators.
GE Oil & Gas says the design draws on technology from its aviation business, where it was used as an auxiliary system on aircraft engines, and eliminates equipment, such as the barrier fluid system needed in conventional subsea boosting systems. GE Oil & Gas’ system, involves stacking a series of integrated new motor impellors to deliver high delta p and high flow rates, the firm says.
The firm is also aiming to make the MCP system simple, reliable, standardized and scalable so that if one stage fails, the system can be adjusted so the others compensate.
The firm has also been working on optimizing control systems using simulation. In a presentation at Subsea Valley, Dejan Doder outlined a concept for process control and operation of a subsea multiphase boosting station.
The boosting station, in his example, would include separation and a recirculation loop, which twinned with a simulation model and automated control, can be used to ensure safe and optimal operating limits, particularly during start-up. This means using the recirculation loop to help make sure the production stream is stable, and does not have a high gas volume fraction as it goes through the boosting station, but also adjusting the speed of the pumps, based on the pressure at the inlet or outlet, so that the load on both pumps, in a two pumps in parallel configuration, is equal.
Aker Solutions-Baker Hughes
Jonah Margulis, of Aker Solutions, updated Subsea Valley on a joint project that was created under an alliance formed with Baker Hughes to offer seafloor boosting solutions.
These are not the large, 6MW+ booster stations positioned downstream of manifolds offered by others, but a solution, called PowerJump (OE: NCE Subsea supplement 2015), based on a high-end Baker Hughes’ electrical submersible pump (ESP), which can be retrofitted in a horizontal configuration into the subsea flowline infrastructure on otherwise marginal brown and green fields. The ESP has been developed to handle up to 60% gas, on subsea wells producing less than 30,000 b/d, drawing on 2MW power, with an integrated control system. By being able to slot it into the subsea infrastructure, it means fast installation and minimal downtime, Margulis says.
The first use case, as it were, is aimed at installation on an M type high profile production jumper as a solution for fields in the Gulf of Mexico or offshore West Africa. A low profile version would be more suitable to the North Sea. The unit would be installed within a truss, to ensure the ESP remains straight and rigid, with vertical connectors for easy installation, using a light well intervention vessel, and an upstream gas dampener to protect the ESP. Downstream would be a mini liquid collection unit. There would also be a recirculation line to ensure consistent liquid in the system.
Because the ESP isn’t being used downhole, and is no-longer constrained by well size, its length can be shortened and hydrodynamics improved, Margulis says. Use of simple pipeline end terminations also makes it easy to tie-in the system anywhere, he says. To increase the pressure boost, pumps could be added in series. “We have done several studies and we haven’t found a field we haven’t been able to tie this in to from a field architecture point of view,” he says.
The alliance hopes have the system qualified by September and to deliver an entire system in 12-14 months. Rather than selling units, they will be operated on a pay for performance basis, he says.
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